Fracking : Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing [2 ed.] 9781119363422

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Fracking

Scrivener Publishing 100 Cummings Center, Suite 541J Beverly, MA 01915-6106

Publishers at Scrivener Martin Scrivener ([email protected]) Phillip Carmical ([email protected])

Fracking Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing 2nd Edition

Michael D. Holloway

This edition first published 2018 by John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, USA and Scrivener Publishing LLC, 100 Cummings Center, Suite 541J, Beverly, MA 01915, USA © 2018 Scrivener Publishing LLC For more information about Scrivener publications please visit www.scrivenerpublishing.com. 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. Wiley Global Headquarters 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. Limit of Liability/Disclaimer of Warranty 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. 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. 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. Library of Congress Cataloging-in-Publication Data ISBN 978-1-119-36342-2 Cover image: Bounder32h | Dreamstime.com Cover design by Kris Hackerott Set in size of 11pt and Minion Pro by Exeter Premedia Services Private Ltd., Chennai, India Printed in the USA 10 9 8 7 6 5 4 3 2 1

Dedicated to the memory of my father Leon Holloway: a printer, a math whiz, a decorated soldier, a consummate salesman, a philosopher, and a true father. Your spoken words will be missed but not forgotten.

Contents Preface

xv

List of Contributors

xvii

An Introduction to Hydraulic Fracturing

xix

1 Environmental Impact – Reality and Myth and Nero Did Not Fiddle While Rome Burned 1.1 The Tower of Babel and How it Could be the Cause of Much of the Fracking Debate 2 Production Development

1 2 5

3 Fractures: Their Orientation and Length 3.1 Fracture Orientation 3.2 Fracture Length/ Height

11 11 13

4 Casing and Cementing 4.1 Blowouts 4.2 Surface Blowouts 4.3 Subsurface Blowouts 4.4 Horizontal Drilling 4.5 Fracturing and the Groundwater Debate

15 16 17 17 18 18

5 Pre-Drill Assessments 5.1 Basis of Design

19 21

6 Well Construction 6.1 Drilling 6.2 Completion

23 23 26

7

29 30 30

Well Operations 7.1 Well Plug and Abandonment “P&A” 7.2 Considerations

vii

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8 Failure and Contamination Reduction 8.1 Conduct Environmental Sampling Before and During Operations 8.2 Disclose the Chemicals Being Used in Fracking Operations 8.3 Ensure that Wellbore Casings are Properly Designed and Constructed 8.4 Eliminate Venting and Work Toward Green Completions 8.5 Prevent Flowback Spillage/Leaks 8.6 Dispose/Recycle Flowback Properly 8.7 Minimize Noise and Dust 8.8 Protect Workers and Drivers 8.9 Communicate and Engage 8.10 Record and Document

43

9 Frack Fluids and Composition 9.1 Uses and Needs for Frack Fluids 9.2 Common Fracturing Additives 9.3 Typical Percentages of Commonly Used Additives 9.4 Proppants 9.5 Silica Sand 9.6 Resin Coated Proppant 9.7 Manufactured Ceramics Proppants 9.8 Additional Types 9.9 Slickwater

49 50 50

10 So Where Do the Frack Fluids Go?

61

11 Common Objections to Drilling Operations 11.1 Noise 11.2 Changes in Landscape and Beauty of Surroundings 11.3 Increased Traffic 11.4 Subsurface Contamination of Ground Water 11.5 Impacts on Water Wells 11.6 Water Analysis 11.7 Types of Methane and What They Show Us 11.8 Biogenic 11.9 Thermogenic 11.10 Possible Causes of Methane in Water Wells 11.11 Surface Water and Soil Impacts 11.12 Spill Preparation and Documentation 11.13 Other Surface Impacts

63 64 65 66 67 67 67 70 71 71 71 72 72 73

43 44 44 44 45 45 45 46 46 47

53 53 55 57 58 58 59

Contents ix 11.14 11.15 11.16 11.17 11.18 11.19 11.20 11.21 11.22 11.23 11.24 11.25 11.26 11.27 11.28 11.29 11.30

Land Use Permitting Water Usage and Management Flowback Water Produced Water Flowback and Produced Water Management Geological Shifts Induced Seismic Event Wastewater Disposal Wells Site Remediation Regulatory Oversight Federal Level Oversight State Level Oversight Municipal Level Oversight Examples of Legislation and Regulations Frack Fluid Makeup Reporting FracFocus Atmospheric Emissions

12 Air Emissions Controls 12.1 Common Sources of Air Emissions 12.2 Fugitive Air Emissions 12.3 Silica Dust Exposure 12.4 Stationary Sources 12.5 The Clean Air Act 12.6 Regulated Pollutants 12.7 NAAQS Criteria Pollutants 12.8 Attainment Versus Non-attainment 12.9 Types of Federal Regulations 12.10 MACT/NESHAP HAPs 12.11 NSPS Regulations: 40 CFR Part 60 12.12 NSPS Subpart OOOO 12.13 Facilities/Activities Affected by NSPS OOOO 12.14 Other Types of Federal NSPS and NESHAP/MACT Regulations 12.15 NSPS Subpart IIII 12.16 NSPS Subpart JJJJ 12.17 NSPS Subpart KKK 12.18 MACT Subpart HH and Subpart HHH 12.19 MACT Subpart ZZZZ 12.20 Construction and Operating New Source Review Permits 12.21 Title V Permits

73 74 74 75 76 76 77 78 78 78 79 79 80 80 81 82 83 85 87 88 89 89 90 90 91 91 92 92 92 93 93 95 95 95 95 95 96 96 96

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13 Chemicals and Products on Locations 13.1 Material Safety Data Sheets (MSDS) 13.2 Contents of an MSDS 13.3 Product Identification 13.4 Hazardous Ingredients of Mixtures 13.5 Physical Data 13.6 Fire and Explosion Hazard Data 13.7 Health Hazard Data 13.8 Emergency and First Aid Procedures 13.9 Reactivity Data 13.10 Spill, Leak, and Disposal Procedures 13.11 Personal Protection Information 13.12 HCS 2012 Safety Data Sheets (SDS)

99 102 103 104 104 105 106 106 107 107 107 108 117

14 Public Perception, the Media, and the Facts 14.1 Regulation or Policy Topics: Media Coverage and Public Perception

123

15 Notes from the Field 15.1 Going Forward

137 150

16 Migration of Hydrocarbon Gases 16.1 Introduction 16.2 Geochemical Exploration for Petroleum 16.3 Primary and Secondary Migration of Hydrocarbons 16.3.1 Primary Gas Migration 16.3.2 Secondary Gas Migration 16.3.3 Gas Entrapment 16.4 Origin of Migrating Hydrocarbon Gases 16.4.1 Biogenic vs. Thermogenic Gas 16.4.1.1 Sources of Migrating Gases 16.4.1.2 Biogenic Methane 16.4.1.3 Thermogenic Methane Gas 16.4.2 Isotopic Values of Gases 16.4.3 Nonhydrocarbon Gases 16.4.4 Mixing of Gases 16.4.5 Surface Gas Sampling 16.4.6 Summary 16.5 Driving Force of Gas Movement 16.5.1 Density of a Hydrocarbon Gas under Pressure 16.5.2 Sample Problem (Courtesy of Gulf Publishing Company)

153 153 154 157 157 159 159 161 161 161 162 165 167 168 170 172 172 174 174

128

176

Contents xi 16.5.3

16.6

16.7

16.8

16.9

16.10 16.11

Other Methods of Computing Natural Gas Compressibility 16.5.4 Density of Water 16.5.5 Petrophysical Parameters Affecting Gas Migration 16.5.6 Porosity, Void Ratio, and Density 16.5.7 Permeability 16.5.8 Free and Dissolved Gas in Fluid 16.5.9 Quantity of Dissolved Gas in Water Types of Gas Migration 16.6.1 Molecular Diffusion Mechanism 16.6.2 Discontinuous-Phase Migration of Gas 16.6.3 Minimum Height of Gas Column Necessary to Initiate Upward Gas Movement 16.6.4 Buoyant Flow 16.6.5 Sample Problem (Courtesy of Gulf Publishing Company) 16.6.6 Gas Columns 16.6.7 Sample Problem 2.2 (Courtesy of Gulf Publishing Company) 16.6.8 Continuous-Phase Gas Migration Paths of Gas Migration Associated with Oilwells 16.7.1 Natural Paths of Gas Migration 16.7.2 Man-Made Paths of Gas Migration (boreholes) 16.7.2.1 Producing Wells 16.7.2.2 Abandoned Wells 16.7.2.3 Repressured Wells 16.7.3 Creation of Induced Fractures during Drilling Wells Leaking Due to Cementing Failure 16.8.1 Breakdown of Cement 16.8.2 Cement Isolation Breakdown (Shrinkage—Circumferential Fractures) 16.8.3 Improper Placement of Cement Environmental Hazards of Gas Migration 16.9.1 Explosive Nature of Gas 16.9.2 Toxicity of Hydrocarbon Gas Migration of Gas from Petroleum Wellbores 16.10.1 Effect of Seismic Activity Case Histories of Gas Migration Problems 16.11.1 Inglewood Oilfield, CA 16.11.2 Los Angeles City Oilfield, CA

177 181 183 184 188 189 191 192 193 195 198 199 200 201 203 204 207 209 211 211 212 213 213 217 217 217 220 222 222 224 227 228 228 230 231

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Contents 16.11.2.1 Belmont High School Construction 16.11.3 Montebello Oilfield, CA 16.11.3.1 Montebello Underground Gas Storage 16.11.4 Playa Del Rey Oilfield, CA 16.11.4.1 Playa Del Rey underground Gas Storage 16.11.5 Salt Lake Oilfield, CA 16.11.5.1 Ross Dress for Less Department Store Explosion/Fire, Los Angeles, CA 16.11.5.2 Gilmore Bank 16.11.5.3 South Salt Lake Oilfield Gas Seeps from Gas Injection Project 16.11.5.4 Wilshire and Curson Gas Seep, Los Angeles, CA, 1999 16.11.6 Santa Fe Springs Oilfield, CA 16.11.7 El Segundo Oilfield, CA 16.11.8 Honor Rancho and Tapia Oilfields, CA 16.11.9 Sylmar, CA — Tunnel Explosion 16.11.10 Hutchinson, KS — Explosion and Fires 16.11.11 Huntsman Gas Storage, NE 16.11.12 Mont Belvieu Gas Storage Field, TX 16.11.13 Leroy Gas Storage Facility, WY 16.12 Conclusions References and Bibliography

17 Subsidence as a Result of Gas/Oil/Water Production 17.1 Introduction 17.2 Theoretical Compaction Models 17.3 Theoretical Modeling of Compaction 17.3.1 Terzaghi’s Compaction Model 17.3.2 Athy’s Compaction Model 17.3.3 Hedberg’s Compaction Model 17.3.4 Weller’s Compaction Model 17.3.5 Teodorovich and Chernov’s Compaction Model 17.3.6 Beall’s Compaction Model 17.3.7 Katz and Ibrahim Compaction Model 17.4 Subsidence Over Oilfields 17.4.1 Rate of Subsidence 17.4.2 Effect of Earthquakes on Subsidence

233 234 234 235 235 238

238 240 241 241 241 244 244 244 247 247 248 248 249 252 261 261 264 270 272 274 275 275 276 277 277 279 281 282

Contents xiii 17.4.3 Stress and Strain Distribution in Subsiding Areas 17.4.4 Calculation of Subsidence in Oilfields 17.4.5 Permeability Seals for Confined Aquifers 17.4.6 Fissures Caused by Subsidence 17.5 Case Studies of Subsidence over Hydrocarbon Reservoirs 17.5.1 Los Angeles Basin, CA, Oilfields, Inglewood Oilfield, CA 17.5.1.1 Baldwin Hills Dam Failure 17.5.1.2 Proposed Housing Development 17.5.2 Los Angeles City Oilfield, CA 17.5.2.1 Belmont High School Construction 17.5.3 Playa Del Rey Oilfield, CA 17.5.3.1 Playa Del Rey Marina Subsidence 17.5.4 Torrance Oilfield, CA 17.5.5 Redondo Beach Marina Area, CA 17.5.6 Salt Lake Oilfield, CA 17.5.7 Santa Fe Springs Oilfield, CA 17.5.8 Wilmington Oilfield, Long Beach, CA 17.5.9 North Stavropol Oilfield, Russia 17.5.10 Subsidence over Venezuelan Oilfields 17.5.10.1 Subsidence in the Bolivar Coastal Oilfields of Venezuela 17.5.10.2 Subsidence of Facilities 17.5.11 Po-Veneto Plain, Italy 17.5.11.1 Po Delta 17.5.12 Subsidence Over the North Sea Ekofisk Oilfield 17.5.12.1 Production 17.5.12.2 Ekofisk Field Description 17.5.12.3 Enhanced Oil Recovery Projects 17.5.13 Platform Sinking 17.6 Concluding Remarks References and Bibliography 18 Effect of Emission of CO2 and CH4 into the Atmosphere 18.1 Introduction 18.2 Historic Geologic Evidence 18.2.1 Historic Record of Earth’s Global Temperature 18.2.2 Effect of Atmospheric Carbon Content on Global Temperature

283 286 289 290 292 292 294 297 297 297 299 299 301 302 303 305 306 318 324 325 328 335 336 343 345 346 348 348 350 351 361 361 363 363 366

xiv

Contents 18.2.3 Sources of CO2 18.3 Adiabatic Theory 18.3.1 Modeling the Planet Earth 18.3.2 Modeling the Planet Venus 18.3.3 Anthropogenic Carbon Effect on the Earth’s Global Temperature 18.3.4 Methane Gas Emissions 18.3.5 Monitoring of Methane Gas Emissions References

370 373 373 375 380 383 385 385

19 Fracking in the USA

389

Appendix A: Chemicals Used in Fracking

729

Appendix B: State Agency Web Addresses

907

Bibliography:

911

Index

913

Preface For eons, human beings have had to endure many natural calamities that are out of their control. Events such as landslides, avalanches, drought, lightning strikes, wildfires, earthquakes, floods, tsunamis, volcanic eruptions, tornados, and hurricanes are all cataclysmic events that occur without the help of people creating them…until recently. It has been argued (and in some cases proven) that humans have adversely affected their environment and helped to create many of the above mentioned events. Improper land development has led to landslides, wildfires, and flooding. The dust bowl a century ago was the result of aggressive farming practices which many believe contributed to the devastating drought. Some even argue that such practices today lead to increased tornadic activity. It wasn’t until recently that in certain regions, seismic activity was due to frac fluid being pumped back into the well for disposal purposes. In 2016, the EPA released a report indicating that such practice does in fact lead to a relief of pressure leading to a reduction in formation friction thus contributing to seismic adjustment. While these earthquakes are relatively small on the Richter scale, nonetheless there is seismic activity attributed to the overall practice of hydraulic fracturing. The industry will strongly defend the fact stating that “Fracing doesn’t cause earth quakes, what you do with the frac fluid does…” and while semantically that is true, the process of hydraulic fracturing (fracing) should be considered to be the overall process from site exploration to well completion and all tasks in between as it relates to the process of fracing. Pumping fluid mixed with a little sand into the ground to break rock formations and increase natural gas and crude oil permeability is essentially fracking, it can’t be ignored that there are other parts of the process that make up this thing we know as fracing. Without fracing, you wouldn’t need to dispose of the frac fluid. As soon as we get past the argument of semantics we can address the larger issue which are the dangers of fracing. Yes, fracing causes environmental situations that produce an opportunity for water contamination, air contamination, as well as seismic activity. Those who say it doesn’t, are part of the industry and will defend their livelihood or they are unaware of the facts. But just as fracing can contribute xv

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to environmental situations, so do slaughter houses, mines, steel mills, textile mills, and even golf courses. Countless examples consume far greater amounts of water and produce far more environmental dangers then fracing. There is a price to pay for food, materials, and for energy. Textile mills, steel mills, mining facilities, slaughter houses use more water per hour then frac sites use during a year. There is more atmospheric damage done by dairy cows in a day then frac facilities create in a lifetime. There is a price to pay for everything. Consider the end product and when put in environmental comparison, fracing is not as bad is you would be lead to believe. Those who oppose fracing would not like life without it. The cost of energy, transportation, and goods would all be much more expensive. George Bernard Shaw was at a party once and he told a woman that people would do anything for money, if the price was right. `Surely not’, she said.’ `Oh yes,’ he said. `Well, I wouldn’t,’ she said smiling. `Oh yes you would,’ he said. He lowered his voice, met her eyes with hers and said with a boyish grin `For instance, would you spend a romantic, and erotic night with me for... for a million pounds?’ `Well’ she said blushing, ‘you are very charming and maybe for a million I would, yes.’ She said with wide eyes and hopeful gaze .Shaw stepped back, paused and said `Would you do it for say … ten shillings?’ asked Shaw ending in a higher pitch. `Certainly not!’ said the woman in horror and indignation `What do you take me for?’ she huffed. `We’ve established that already,’ he said coyly, `we are just trying to settle on your price now.’ It is unknown if Shaw went home alone that night or not. George Bernard Shaw identified a very common thread; for the right price anything is possible but when confronted with a lower then an acceptable offer, people develop a sense of personal morality, and social ethics. Money provides control, comfort and convenience – all tenants of a wonderful life. Money also buys energy. The need for energy is all consuming. When we lose power to our homes, life becomes unbearable. We lose the ability to use our appliances, various forms of entertainment, and all forms of communication if the battery runs out. We will burn coal, fuel oil, even wood to stay warm. We would harness the power of a nuclear bomb to have electricity, and we would barter with rouge nations who commit social atrocities just of a tenth of a cent reduction on a barrel of crude oil – all for control, comfort and convenience. It isn’t until we are confronted with the reality of the ramifications of our needs do we assume a social responsibility but only if it doesn’t interfere with our control, comfort and convenience…too much. Integrity is very easy with warm feet and a full belly. “Those who cannot change their minds cannot change anything.” — George Bernard Shaw “You talk like a man with a paper head.” – Leon D. Holloway

List of Contributors Oliver Rudd John O. Robertson George V. Chilingar

xvii

An Introduction to Hydraulic Fracturing On March 24, 1989, the Exxon Valdez ran into a reef and spilled over 30,000,000 gallons of crude oil into Prince William Sound, Alaska. The spill is considered to be one of the most devastating environmental disasters. The reason for the spill was due to crew deployment mistakes and failed collision avoidance systems. On April 20, 2010, the Deepwater Horizon experienced a wellhead blowout resulting in an oil spill in the Gulf of Mexico considered to be the largest accidental marine oil spill in the history of the petroleum industry. The accident claimed 11 souls and countless marine animals and wasted an estimated 1,960,000,000 gallons of crude oil. According to a federal commission, the reason for the failure was attributed to defective cement curing of the well. These incidents have been burned into our collective memories and will be forever used as examples of just how important safety and environmental aspects are in the petroleum industry. Surprisingly, these disasters are not the most devastating environmental incidents that have occurred in the past 100 years. In fact, they don’t even rank in the top ten. Consider the Baia Mare Cyanide spill which occurred in Romania on January 30, 2000, which killed over 100 people and contaminated millions of gallons of water. Consider the methyl isocyanate chemical leak in Bhopal, Madhya Pradesh, India on the night of December 2-3, 1984. The accident claimed 2,259 casualties, and crippled the Union Carbide Corporation. We all remember Love Canal, Three Mile Island, Chernobyl, and Fukushima. All were considerable disasters as well, yet if you combine all these tragedies, they still do not equal the environmental and human toll of the Great Smog of 1952. How many of us have heard of the Great Smog of ‘52? On December 5, 1952, in London, England, a combination of cold temperatures, lack of wind and increased particulate pollution due to increased coal burning produced a heavy blanket of smog pollution that covered London for four days. It was determined that 12,000 people had died prematurely and 200,000 more were made ill because of the smog’s effects. In 1956, the Clean Air Act was put into effect due to the Great Smog of ‘52. It was only after this catastrophe that action was taken. What if we xix

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were to put safeguards in place prior to an incident? That is exactly what the petroleum industry has done with the practice of hydraulic fracturing or fracking. In today’s society, it is easy for organizations – be it the general media, political groups, local organizations, unions, or religious associations – to spread their beliefs to the public and push whatever agenda or ideals they may have. These beliefs could be successfully put forward with good intentions, successfully put forth with bad intentions, or, in many cases, put forward with good intentions, but have a negative result. Sadly, it seems human nature dictates that the first opinion heard or the opinion heard the loudest and with the most hyperbole will be what the public comes to believe. In time, once something is believed by enough people and stated as “fact” long enough, the general public will no longer even bother looking into facts, and it will become part of the fabric of beliefs in our society – for instance, a few examples of this phenomenon are: 1) one, in fact, cannot see the Great Wall of China from the moon (not even close); 2) the Sherlock Holmes character never once said “Elementary, my dear Watson”; and 3) Nero didn’t play the violin while his city burned; the violin wasn’t invented yet. Now, upon reading this, the hope is that many will stop reading (but, of course, come back) to fact-check that what is written here is true. That is the purpose of this text – not to give opinions or try to sway beliefs, but to merely give facts and provide ample background knowledge to initiate further study. Following this and further study, one can make up his or her own educated opinion on fracking. As far as hydraulic fracturing is concerned, the aspect given the most attention by press and most concerned organizations is its environmental impact. The question of environmental impact through fracking is, to say the least, a very emotional topic and by far the most polarizing issue; however, a great deal of analysis indicates that the most significant environmental risks attributed to fracking are similar to risks long associated with all drilling operations, including groundwater contamination due to inadequate cementing and/or well construction, risks associated with trucking, leaks from tanks and piping, and spills from waste handling. This all-encompassing blame has given industry all of the ammunition needed to claim that effects attributed to hydraulic fracturing are overstated, not based on good science, or related to processes other than hydraulic fracturing. Due to the great ongoing controversy over alleged impacts from fracking, many public groups have become deeply suspicious of the trustworthiness and overall motives of the oil and gas industry. These suspicions are continuously intensified by two things:

An Introduction to Hydraulic Fracturing xxi 1. ongoing mistrust of data and findings due, in great part, to semantics; and 2. by the industry initially refusing to disclose the chemical makeup of fracking fluids and the additives used to enhance hydraulic fracturing. On December 3, 1952, the folks of London, England were kept warm due to the coal they burned on a windless, abnormally cold day. Their quest for comfort, control, and convenience led to disease and death but only because there was no consideration for the environment. The operation of fracking is one of the most regulated and controlled processes with regard to the environment. In the pages that follow, an examination of the operations and the environmental concerns of fracking shall be explored. It’s important to consider, however, that due to hydraulic fracturing, the production of natural gas and even crude oil has been increased to the point that the United States is now in the position where it has higher productivity in manufacturing than China due to our reduced cost of energy. With Congressional approval, the United States is able to export crude oil and natural gas. Economically, the United States is poised to gain the position of energy and production independence. This would not have happened without fracking. Now, consider the last concept. Burning natural gas in order to produce energy – for electricity or transportation – produces poison. Plain and simple. Yet without burning this hydrocarbon, life becomes very uncomfortable, and we give up control and convenience. Comfort, control, convenience are the cornerstones of human development and survival. We are not willing to give these up, and so we will suffer the consequences and are destined to eventually perish. Hydraulic fracturing has made it much easier to reach finality. So, if we are to do this, let us do it with the greatest opportunity of productivity with the minimal cost to the world. Fracking fits that bill. Before the process and impact of hydraulic fracturing is explored, a few questions should be addressed. First, is fracking legal? The answer depends largely on location. For example, France has effectively banned the practice, both legislatively and judicially. Meanwhile, the UK is in the nascent stages of shale exploration and preliminary discussions regarding the regulations have begun. Many countries with shale gas prospects have yet to build out E&P infrastructure, and the questions of regulation and law have yet to be addressed. In the US, federal law regulates fracking when it comes to protecting clean air and water, and preventing the release of toxic substances and chemicals into the environment, but fracking is generally permitted by the federal government. That said, some US states have legislatively imposed moratoria (e.g. fracking is “illegal” in New York).

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Second, is fracking safe? There is much to be said about the safety of the practice of hydraulic fracturing. This question is akin to asking, “Is driving a car safe?” Provided a person follows the rules of the road, has a valid driver’s license, and is an experienced driver, then yes, driving a car can be considered safe. Unfortunately, there are companies and individuals who do not follow the proper protocols due to ignorance or malice (much the same as drivers) and this results in serious problems. In subsequent chapters, the topic of safety (both personal as well as environmental) will be deeply explored.

An Introduction to Hydraulic Fracturing xxiii Among all industrial processes, fracking is the most hotly debated environmental and political issue. Advocates insist it is a safe and economical source of clean energy; critics, however, claim fracking can destroy drinking water supplies, pollute the air, and contribute to the greenhouse gases that cause global warming. Numerous studies have been conducted as to whether fracking is a safe process. Most of these studies have centered upon whether the practice yields water contamination. Additionally, one of the most oft-cited environmental concerns is methane emissions. One of the chief benefits of natural gas engines is its reduction in greenhouse gas emissions as compared to gasoline or diesel fuels. If methane leaks out of wells that are being fracked, one of the principal benefits of fracking is reduced or even eliminated, thereby decreasing the value of the technology to society. Many fracking opponents have concerns regarding fresh water supply and drinking water contamination. Three EPA studies and a US Department of Energy study has proven that these claims are largely false and the operation of hydraulic fracturing has no effect on drinking water. It is a different story when one considers the aftermath of the fracking fluid disposal. However, groundwater contamination from injected fracking fluids is nearly impossible as a fracture created by the drilling process would have to extend through thousands of feet of rock that separate shale deposits from freshwater. Fracking proponents point out that fracking is an effective drilling method that reduces the surface footprint of the drilling operation. The Energy Information Administration estimates that the US has 2,552 TCF of natural gas resources, and shale gas will account for nearly half of the natural gas produced in the US by 2035. If we wish to continue to have a particular style of life, natural gas seems to be our best option. While the US shale revolution has only taken off over roughly the past decade, the fracking technology that is accelerating the boom has been around for a while. Experiments conducted during the 1930s paved the way for the first industrial-scale commercial uses of the modern patented “Hyrafac” process in 1949. Halliburton held an exclusive license for the process in the early years. In a 2010 study, the Society of Petroleum Engineers said that 332 wells were fracked in 1949 alone, with up to 75% production increases recorded. By the mid-1950s, fracking was happening at a pace of roughly 3,000 wells a month. The first hydraulic fracturing experiment was conducted in 1947 at the Hugoton gas field in southwestern Kansas by Stanolind O&G Corp. In 1949, a patent on this process was issued and an exclusive license was granted to what was then called the Halliburton Oil Well Cementing Company. In March 1949, Halliburton performed the first two commercial fracking treatments in Oklahoma and Texas. Since then,

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An Introduction to Hydraulic Fracturing

fracking has been employed to stimulate numerous oil and gas wells. It is fair to say that Halliburton held the first patent on fracking, but the process has changed considerably since then. Fracturing can be categorized into four major methods (groups): 1)  Hydraulic Fracturing, 2) Pneumatic Fracturing, 3) Fracturing with Dynamic Loading, and 4) Other Methods. Hydraulic Fracturing is the technique that makes use of a liquid fluid to fracture the reservoir rocks. The following techniques are identified: a) Water-based fluids (slickwater, gel, and hybrid), b) Foam-based fluids, c) Oil-based fluids, d) Acid-based fluids, e) Alcohol-based fluids, f) Emulsion-based fluids, g) Cryogenic fluids (CO2, N2, He, etc.). Pneumatic Fracturing is the technique that makes use of a gas (typically air or nitrogen) to fracture the reservoir rock. It is a technique normally used in shallow formations. In Fracturing with Dynamic Loading, fluids are not used. The following techniques are identified: a) Explosive fracturing, b) Electric fracturing. Other Methods  do not readily fall in one of the previous categories. The following techniques are identified: a) Thermal (cryogenic) fracturing, b) Mechanical cutting of the shale formation, c) Enhanced bacterial methanogenesis. One aspect that differentiates most fracturing methods is the technique used to divert fluids from one stage to the other. On most shale formations, the frack fluid or slickwater is used, preferably injected at high rate, (70–120 bpm) or a combination of slickwater and gel (hybrid). The high rate is intended to fracture the shale formation into many pieces and create a fracture network. On conventional (sandstone) formations gel and proppant are used at low rates (usually 10 – 50 bpm). Some of these methods are experimental or their application has been very limited due to lack of equipment and trained personnel so they are not commercially available. There is much effort to find methods that are not objectionable to people, specifically in regards to water source contamination, seismicity, truck traffic, large location footprint, etc. Another type of hydraulic fracturing uses acid. It is used in carbonate rocks where acid acts as the proppant. The acid provides conductivity and develops wormholes in the rock. When pressure is released and fracture closes, channels are created by the acid. Acid is gelled or chemically retarded to act slowly to prevent developing large vids instead of making wormholes. An acid package would typically contain a corrosion inhibitor, non-emulsifier, anti-sludge, and iron control. The acid is either HCl, HCl/ HF mix, or an organic acid like acetic acid. A similar method is called pad acid fracking. A “pad” of water is pumped ahead of a large volume of acid

An Introduction to Hydraulic Fracturing xxv to initiate a fracture which the acid then enlarges and expands. The water and acid are usually pumped in cycles of increasing volumes to expand the volume of the acidized rock. Occasionally, proppant is added but mainly to wear away the rock once the acid has softened it, not to prop open the fracture once the pumping is stopped. This type of method is used mostly in carbonate reservoirs (limestone, dolomites, etc.) that are acid soluble. Acid fracturing is used in producing wells to remove damage caused by deposition of carbonates or scale. Wellbore cleanout of scale and other deposits (soluble in acid) are carried out at low injection rate (1-2 bpm range), which is specifically intended to avoid fracturing. This is called injection in matrix mode. Matrix mode signifies fluid flow in the porous space of the formation in a radial fashion. The fluid doesn’t go very far in the formation, as it takes extremely large fluid volumes to treat far into the formation. Another type of application utilizes a gelling agent, usually guar gum, to impart viscosity to the transport fluid. The gel can be either a linear gel or a cross-linked gel depending on the viscosity required for the particular job, the cross-linked version having the greatest viscosity. A gelling agent allows loading the fluid with higher concentrations of proppant and also using proppant of larger sizes. The added viscosity prevents the proppant from settling out near the wellbore and screening off the fracture prematurely. Also, the more viscous the fluid, the wider but smaller, the stimulated fracture being created. The gelling agent application creates a fracture that extends into the formation away from the wellbore in a direction perpendicular to the direction of least stress on the rock formation. This type of fracture is used primarily on sandstones. Frac wells can also be pumped with a gas or a foam as the carrying fluid. These are used in low pressure or pressure depleted reservoirs to introduce energy in the form of gas expansion. This aids in the recovery of the frac fluids pumped into the rock. It is also used in water sensitive formations where the introduction of water to the rock matrix has a detrimental effect on the permeability of the rock. Permeability is a measure of the ability of fluids to flow through the rock itself. The gas is added into the pump stream along with the primary fluid (water with or without gel, acid, or proppants as the case may be) being used for the job. Nitrogen, carbon dioxide, or a mix of both are the primary gases used for these types of wells. The gas, commonly nitrogen, can be pumped without fluid in what is called a gas frac (or pneumatic as cited previously). Gas fracs have mainly been used in coalbed methane wells. Fracking companies have been required to increase disclosure of what their fracking fluids are comprised of in recent years. Fracking fluid is

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An Introduction to Hydraulic Fracturing

over 99% water and sand. The remaining 1% (or less) is made up of a mix of chemicals and additives used to clean the wellbore, prevent scale, and prevent bacterial growth. The most common of the additives includes diluted acid, which dissolves cement and minerals and initiates fractures. The hydrochloric acid is diluted to 0.03%, which is roughly the amount added to swimming pools. Friction reducer polyacrylamide is also added, which reduces friction between fluid and pipe. Another common additive is an antimicrobial agent like glutaraldehyde, ethanol, or methanol, which removes bacteria in the water that produces corrosive byproducts. It is also used to sterilize medical and dental equipment and surfaces. Scale inhibitor, ethylene glycol, alcohol, and sodium hydroxide is also added to prevent scale deposit in the pipe. Some operators will also add salt to reduce the swelling of clay when exposed to water. In the pages that follow, the operations and environmental considerations of hydraulic fracturing will be explored and explained. Many states in the US have become economically strong due to fracing while other states have banned it. There are sound arguments made on both sides. The latest EPA report indicates that the practice can contribute to contamination as well as seismic activity. One must weigh the consequences. Energy requires an environmental sacrifice. It is not an easy topic to discuss but it is realistic. For as long as electricity has been made publically available, coal was burned to generate electricity. Hydroelectric power is available but it doesn’t provide the volume of energy required for the country. While coal may have been plentiful, it still had to be mined and transported which was costly. There was a less expensive energy source – nuclear. In the 1970s, there was a major push to utilize nuclear energy which accounted for the majority of the energy produced but safety and nuclear waste concerns lost favor for other energy sources such as diesel and natural gas. Natural gas has always been a source of energy but it wasn’t until the mid-1990s that natural gas became the predominate source for energy fuel due to the advancement of hydraulic fracturing. In the beginning of 2000, natural gas became the major source of fuel to power turbines. With the EPA standards for clean air and emissions reductions, natural gas saw an uptick in interest for power vehicles and trains but sadly it was short lived with the situation that Volkswagen got themselves into. As many know, Volkswagen committed fraud of the emissions of their passenger cars in order to achieve the emissions standards. The future standards are basically unachievable and unrealistic and engine manufacturers realize this. The only discourse is to develop electric vehicles; passenger, commercial, and even heavy industrial and agriculture. The combustion engine that runs on gasoline or diesel fuel will be extinct. Relics will remain and they will be near and dear to

An Introduction to Hydraulic Fracturing xxvii our hearts but the future of transportation will be electric. Power will still need to be generated. Until nuclear is made safer for public acceptance, and wind and solar are able to provide an economic way to produce energy without government assistance, natural gas will be the source of the energy. The most effective way to mine natural gas is through hydraulic fracturing.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

1 Environmental Impact – Reality and Myth and Nero Did Not Fiddle While Rome Burned

In today’s society, it is really easy for organizations – be it the general media, political groups, local organizations, unions, or religious associations – to spread their beliefs to the public and push whatever agenda or ideals they may have. These beliefs could be successfully put forward with good intentions, successfully put forth with bad intentions, or, in many cases, put forward with good intentions, but have a negative result. Sadly, it seems human nature dictates that the first opinion heard or the opinion heard the loudest and with the most hyperbole will be what the public comes to believe. In time, once something is believed by enough people and stated as “fact” long enough, the general public will no longer even bother looking into facts, and it will become part of the fabric of beliefs in our society – for instance, a few examples of this phenomenon are: 1) one, in fact, cannot see the Great Wall of China from the moon (not even close); 2) the Sherlock Holmes character never once said “Elementary, my 1

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dear Watson”; and 3) Nero didn’t play the violin while his city burned. The violin wasn’t invented yet. Now, upon reading this, the hope is that many will stop reading (but of course come back) to fact-check that what is written here is true. That is exactly the point to push: as previously stated many times, the point is not to give opinions or try to sway beliefs, the point is to merely give facts described in the most straightforward and clear way possible and hopefully give enough background knowledge to initiate further study. Following this and further study, hopefully one can make up his or her own educated opinion on fracking…and that Nero actually funded relief money from his own savings to help his subjects. As far as hydraulic fracturing is concerned, the aspect given the most attention by press and most concerned organizations is the impact it may have on the environment. The question of environmental impact through fracking is, to say the least, a very emotional topic and by far the most polarizing issue; however, a great deal of analysis indicates that the most significant environmental risks attributed to fracking are similar to risks long associated with all drilling operations, including groundwater contamination due to inadequate cementing and/or well construction, risks associated with trucking, leaks from tanks and piping, and spills from waste handling. This all-encompassing blame has given industry all of the ammunition needed to claim that effects attributed to hydraulic fracturing are overstated, not based on good science, or related to processes other than hydraulic fracturing. Due to the great ongoing controversy over alleged impacts from fracking, many public groups have become deeply suspicious of the trustworthiness and overall motives of the oil and gas industry. These suspicions are continuously intensified by two things: 1. ongoing mistrust of data and findings due, in great part, to semantics, and 2. by the industry initially refusing to disclose the chemical makeup of fracking fluids and the additives used to enhance hydraulic fracturing.

1.1 The Tower of Babel and How it Could be the Cause of Much of the Fracking Debate Almost everyone has heard the story, or has a general understanding, of the Tower of Babel from the Old Testament. In the Biblical account of this

Environmental Impact – Reality

3

story, humanity was attempting, as a unified group, to build a tower in Mesopotamia to reach the heavens, only to have their efforts brought to a halt by one of the most effective means imaginable. The efforts of this united group of people were not thwarted by military force, or by weather, or even by sickness and injury; their efforts in this undertaking were thwarted by speech. The simple fact of this story is that building of the tower came to a halt once the unified people were confounded by speech and no longer able to communicate to work together. Now far be it for this work to compare modern day hydraulic fracturing with the construction, and subsequent stop in construction, of the Tower of Babel, but much of the confusion, name-calling, and general mistrust between groups on this subject can be attributed to a difference in communication. Maybe once this communication gap is bridged, more effective talks can be established between industry and the concerned public in place of wasting time on mistrust and name-calling. Hopefully, this work can help to bridge that gap. It can be easily considered that a very large portion of negativity toward hydraulic fracturing is actually attributable to processes other than hydraulic fracturing. In the discussions between industry and the public, a great deal of this problem can boil down to an issue of semantics: the oil and gas industry has a narrow view of what fracking entails (including just those processes related to the actual process of fracking while on location conducting the fracking operation), while the general public is more inclined to include many more activities commonly related to fracking (water and sand trucking, product and equipment transport and storage, water disposal) under the heading of “fracking.” This can cause misunderstandings and skewed data, in that many of the processes included by the general public are utilized in many, if not all, drilling practices, and are hard to put solely under the heading of “fracking,” when in actuality they could just as easily be under the heading “completions” or “production.” This topic has been discussed many times in the media, in town hall meetings, as well as on various concerned citizens’ blogs to the point of exhaustion. There are many proven environmental impacts caused by drilling operations and processes related to drilling. There are also many concerns raised about any industrial effort. Any time that man and machine are working, there are countless opportunities for an environmental issue to emerge. It is the nature of the beast. It has been suggested by many that the advent of industry in England as well as the northeast of the United States changed the seasons, the combination of drought and unmanaged farming led to the Midwestern Dust Bowl of last century, and the increase in exhaust emissions from automobile exhaust has led to unsafe levels of

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pollutants in all cities. These are facts. Facts can almost assuredly not be disproven by industry, and can be a concern by the public in their feelings on gas well completion and production activities. However, by the same token, there have been over a million wells that have gone through the process of hydraulic fracturing. With such a great opportunity for environmental impact, one would think that the process would surely have poisoned the water. With the current issue of semantics, public concerns can include many drilling processes, while industry can fall back on the fact that the industry definition of fracking has never impacted fresh water in the ways commonly claimed by the media for public consumption. The debate can rage on, with both sides being right and both sides being wrong, while never taking steps to come together on a common goal. The goal of this work is not to shine light on the mistakes of the drilling industry or show how citizens can make false claims; the goal is to educate and share insight. If the one message that can be taken away from this work is how to drive this technology safely, then the goal shall be reached.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

2 Production Development

Before an investigation is begun into the production of a well site, it is important to understand what the product is. There are several types of ‘product’ that are obtained at the well site. Gas reservoirs are classified as conventional or unconventional for the following reasons: Conventional reservoirs: Wells in conventional gas reservoirs produce from sand carbonates (lime stones and dolomites) that contain the gas in interconnected pore spaces that allow flow to the wellbore. Gas in the pore scan will move from one pore to another through smaller pore-throats that create permeable flow through the reservoir. In conventional natural gas reservoirs, the gas is often sourced from organic-rich shale proximal to the more porous and permeable sandstone or carbonate. Unconventional reservoirs: Wells in unconventional reservoirs produce from low permeability (tight) formations such as tight sands and carbonates, coal, and shale. In unconventional gas reservoirs, the gas is often sourced from the reservoir rock itself (tight gas sandstone and carbonates are an exception). Because of the low permeability of these formations, it is typically necessary to stimulate the reservoir to create additional permeability. Hydraulic fracturing of a reservoir is the preferred stimulation

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method for gas shale. Differences between the three basic types of unconventional reservoirs include: Tight Gas: Wells produce from regional low-porosity sandstones and carbonate reservoirs. The natural gas is sourced (formed) outside the reservoir and migrates into the reservoir over time (millions of years). Many of these wells are drilled horizontally, and most are hydraulically fractured to enhance production. Coal Bed Natural Gas (CBNG): Wells produce from the coal seams, which act as source and reservoir of the natural gas. Wells frequently produce water as well as natural gas. Natural gas can be sourced by thermogenic alterations of coal or by biogenic action of indigenous microbes on the coal. There are some horizontally drilled CBNG wells, and some that receive hydraulic fracturing treatments. However, some CBNG reservoirs are also underground sources of drinking water, and as such, there are restrictions on hydraulic fracturing. CBNG wells are mostly shallow, as the coal matrix does not have the strength to maintain porosity under the pressure of significant overburden thickness. Shale Gas: Wells produce from low permeability shale formations that are also the source for the natural gas. The natural gas volumes can be stored in a local macro-porosity system (fracture porosity) within the shale, or within the micro-pores of the shale or it can be adsorbed onto minerals or organic matter within the shale. Wells may be drilled either vertically or horizontally, and most are hydraulically fractured to stimulate production. Shale gas wells can be similar to other conventional and unconventional wells in terms of depth, production rate, and drilling. The following is a comparison of conventional well structure and hydraulic fracturing. Drilling conventional wells and those to be used in hydraulic fracturing begin in much the same ways. The basic well construction steps are: An initial length of steel pipe, called conductor casing, is inserted into a vertical wellbore soon after drilling begins. This is done to stabilize the well as it passes through the shallow sediments and soils near the surface.

Production Development Hydraulic fracturing

Conventional wells

Fresh water table Salt water table

7000 + Feet Gas zone

Figure 2.1 Comparison of Well Sites.

Once conductor casing is set, operators continue drilling and insert a second casing, called surface casing, from the ground surface and extending past the depth of all drinking water aquifers. After allowing the cement behind the casings to set (cementing is described in detail in the following section), operators continue drilling for approximately 10 to 50 feet before stopping to test the integrity of the cement process by pressurizing the well. In horizontal wells, after drilling the horizontal section of the well, operators run a string of production casing into the well and cement it in place. Operators then perforate the production casing using small explosive charges at intervals along the horizontal wellbore where they intend to hydraulically fracture the shale. Acid stage; consisting of several thousand gallons of water mixed with a dilute acid such as hydrochloric or muriatic acid: This serves to clear cement debris in the wellbore and provide an open conduit for other frack fluids by dissolving carbonate minerals and opening fractures near the wellbore. Pad stage; consisting of approximately 100,000 gallons of slickwater without proppant material: The slickwater pad stage fills the wellbore with the slickwater solution (described below), opens the formation, and helps to facilitate the flow and placement of proppant material.

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Fracking 2nd Edition Prop sequence stage; which may consist of several sub-stages of water combined with proppant material (consisting of a fine mesh sand or ceramic material, intended to keep open, or “prop,” the fractures created and/or enhanced during the fracturing operation after the pressure is reduced): This stage may collectively use several hundred thousand gallons of water. Proppant material may vary from a finer particle size to a coarser particle size throughout this sequence. Flushing stage; consisting of a volume of fresh water sufficient to flush the excess proppant from the wellbore.

Other additives commonly used in the fracturing solution employed include: A dilute acid solution, as described in the first stage, used during the initial fracturing sequence. This cleans out cement and debris around the perforations to facilitate the subsequent slickwater solutions employed in fracturing the formation. A biocide or disinfectant, used to prevent the growth of bacteria in the well that may interfere with the fracturing operation: Biocides typically consist of bromine-based solutions or glutaraldehyde. A scale inhibitor, such as ethylene glycol, is used to control the precipitation of certain carbonate and sulfate minerals. Iron control/stabilizing agents such as citric acid or hydrochloric acid, are used to inhibit precipitation of iron compounds by keeping them in a soluble form. Friction reducing agents, also described above, such as potassium chloride or polyacrylamide-based compounds, used to reduce tubular friction and subsequently reduce the pressure needed to pump fluid into the wellbore: The additives may reduce tubular friction by 50 to 60%. These friction-reducing compounds represent the “slickwater” component of the fracking solution. Corrosion inhibitors, such as N,n-dimethyl formamide, and oxygen scavengers, such as ammonium bisulfite, are used to prevent degradation of the steel well casing. Gelling agents, such as guar gum, may be used in small amounts to thicken the water-based solution to help transport the proppant material.

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Occasionally, a cross-linking agent will be used to enhance the characteristics and ability of the gelling agent to transport the proppant material. These compounds may contain boric acid or ethylene glycol. When crosslinking additives are added, a breaker solution is commonly added later in the frack stage to cause the enhanced gelling agent to break down into a simpler fluid so it can be readily removed from the wellbore without carrying back the sand/proppant material.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

3 Fractures: Their Orientation and Length

Certain predictable characteristics or physical properties regarding the path of least resistance have been recognized since hydraulic fracturing was first conducted in the oilfield in 1947. The following table lists various sites also known as Plays throughout North America.

3.1 Fracture Orientation Hydraulic fractures are formed in the direction perpendicular to the least stress. Based on experience, horizontal fractures will occur at depths less than approximately 2000 ft because the earth’s overburden at these depths provides the least principal stress. If pressure is applied to the center of a formation under these relatively shallow conditions, the fracture is most likely to occur in the horizontal plane, because it will be easier to part the rock in this direction than in any other. In general, therefore, these fractures are parallel to the bedding plane of the formation. As depth increases beyond approximately 2000 ft, overburden stress increases by approximately 1 psi/ft, making the overburden stress the 11

327

44

Original Gas-In- Place, TCF

Technically Recoverable Resources

60 to 160

N/A

Water Production, Barrels water/day

Well spacing, acres

To 350

4–

Total Porosity, %

Gas Content, SCF/Ton

4.5

~1200

Depth to Base of Treatable Water#, ft

Total Organic Carbon, %

To 600

Thickness, ft

7,300

8,500

Depth, ft

Rock Column Thickness between Top of Play and Bottom of Treatable Water, ft

5,000

Estimated Basin Area, square miles

41.6

52

80 to 160

N/A

To 220

8

9.8

6,500

~500

To 200

7,000

9,000

251

717

40 to 560

N/A

To 330

9

4.0

13,100

~400

To 300

13,500

9,000

262

1,500

40 to 160

N/A

To 100

10

12

7650

~850

To 200

8,500

95,000

Marcellus

11.4

23

640

N/A

To 300

9

14

10,600

~400

To 220

11,000

11,000

Woodford

20

76

40 to 160

5 – 500

To 100

9

20

1,900

~300

To 120

2,200

12,000

Antrim

19.2

160

80

5 – 500

To 80

14

25

1,600

~400

To 100

2,000

43,500

New Albany

Gas Shale Basin

Haynesville

Table 3.1 Well Comparisons. Fayetteville

Fracking 2nd Edition

Barnett

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dominant stress. This means the horizontal confining stress is now the least principal stress. Since hydraulically induced fractures are formed in the direction perpendicular to the least stress, the resulting fracture at depths greater than approximately 2000 ft will be oriented in the vertical direction. In the case where a fracture might cross over a boundary where the principal stress direction changes, the fracture would attempt to reorient itself perpendicular to the direction of least stress. Therefore, if a fracture propagated from deeper to shallower formations, it would reorient itself from a vertical to a horizontal pathway and spread sideways along the bedding planes of the rock strata.

3.2

Fracture Length/ Height

The extent that a created fracture will propagate is controlled by the upper confining zone or formation, and the volume, rate, and pressure of the fluid that is pumped. The confining zone will limit the vertical growth of a fracture because it either possesses sufficient strength or elasticity to contain the pressure of the injected fluids, or an insufficient volume of fluid has been pumped. This is important because the greater the distance between the fractured formation and the USDW, the more likely it will be that multiple formations possessing the qualities necessary to impede the fracture will occur. However, while it should be noted that the length of a fracture can also be influenced by natural fractures or faults, as shown in a study that included micro-seismic analysis of fracture jobs, natural attenuation of the fracture will occur over relatively short distances due to the limited volume of fluid being pumped and dispersion of the pumping pressure, regardless of intersecting migratory pathways.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

4 Casing and Cementing

Typically, the casing and cementing of wells is accomplished in multiple phases, working inward from the from the largest diameter casing to the smallest: picture a pirate’s spyglass opened up and buried with the eyepiece at the deepest point underground. First, as described above, the surface casing is inserted. Cement is then pumped down the inside of the casing, forcing it up from the bottom of the surface casing into the annular space between the outside of the surface casing and the drilled wellbore. Once a sufficient volume of cement to fill the annulus is pumped into the casing, it is usually followed by pumping water into the casing until the cement begins to return to the surface in the annular space. This process of cementing is called “circulation” and ensures that the entire annular space fills with cement from below the deepest ground water zone to the surface, which, when done properly, protects the aquifer. After the surface casing is completed and set, the well is drilled to the pay zone. Upon reaching the pay zone, 15

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Fracking 2nd Edition production casing is set at either the top extent of, or into, the producing formation. This zone is then cemented by the same process as before.

As can be expected when working in underground formations, sometimes a well will be extended into a formation that is difficult to cement because of high formation porosity or high water flow. This condition can be detected by personnel during drilling operations or by observing that more cement is being pumped downhole than the calculated area of the annulus. When this happens, additives (such as cellophane flake and calcium chloride) can sometimes be added to the cement to seal off such zones, quicken the cement hardening process, and prevent downhole loss of the cement into formation. When completed properly, sealing of annular spaces with cement creates a hydraulic barrier to both vertical and horizontal fluid migration, essentially eliminating subsurface releases and blowouts. Consequently, the quality of the initial cement job is one of the most critical factors in the prevention of fluid movement into groundwater resources. If well cementing and casing is improperly or poorly done, leakage into an aquifer of fluids that flow upward in the annulus between the casing and the borehole can occur: this is the greatest potential pollution risk. Well integrity issues resulting in leakage can be divided into two categories: Annular flow: fluids move up the wellbore by traveling up the space between the borehole formation and cement or between the cement and the casing Leak flow: fluids move in a radial direction out of the well and into the adjacent formation.

4.1 Blowouts The simple definition of a blowout is an uncontrolled fluid release occurring during the drilling, completion, or production of oil and gas wells. They rarely occur, however: when blowouts occur, it is typically when unexpectedly high pressures are encountered in the subsurface or due to valve or some other type of mechanical failure. What is normally brought to mind when one hears the term “blowout” is the highly graphic explosion that goes with a catastrophic well blowout; however, as used here, this term also includes the smaller above and below ground blowouts.

Casing and Cementing 17 Blowouts may take place at the surface (wellhead or elsewhere) or subsurface (naturally high pressure, or may be artificially induced in the well bore during hydraulic fracturing during completion operations, but not during pumping). A high percentage of blowouts occur due to casing or cement failure, allowing high-pressure fluids to escape up the well bore and flow into subsurface formations. Blowouts have shown to be the most common of all well control problems, and they also appear to be underreported. The potential environmental consequences of a blowout depend mostly on: The timing of the blowout relative to well activities, which determines the nature of the released fluid such as natural gas or pressurized fracturing fluid; Occurrence of the escape of containments through the surface casing or deep in a well; and The risk receptors, such as freshwater aquifers or water wells that are impacted.

4.2 Surface Blowouts Surface blowouts at the wellhead are serious matters that can result in a major safety hazard to workers and may also result in surface spills. Surface blowouts are primarily prevented through proper well construction, maintenance, and ensuring well integrity.

4.3 Subsurface Blowouts Subsurface blowouts, due to high gas pressure or mechanical failures, happen in both regular and hydraulically fractured wellbores. However, fractured wells have the incremental risk of potential failures caused by the high pressures of fracturing fluid during the process. In the event of a blowout in the subsurface, a major problem due to the limited ability to discern what is happening in the subsurface, blowout preventers are used to automatically shut down fluid flow in the well bores. Subsurface blowouts may pose both safety hazards and environmental risks. For example, when a blowout preventer engages to prevent flow from reaching the surface, the fluid may be forced through weaknesses in the casing and cement below the blowout preventer into the surrounding formations and aquifers. Blowout preventers are important safety devices;

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however, like all mechanical devices, they have been known to fail, sometimes with highly visible and catastrophic results.

4.4

Horizontal Drilling

When drilling a horizontal well, operators begin turning the drill bit when they near the production zone so the wellbore runs through the formation horizontally: then it can extend up to 10,000 feet, which vastly increases contact with the production zone relative to vertical drilling.

4.5 Fracturing and the Groundwater Debate While hydraulic fracturing in particular has been the primary focus of controversy and numerous demonstrations, studies indicate that environmental risks associated with hydraulically fractured wells are similar to those associated with all production wells, including surface and subsurface spills and releases, gas migration and groundwater contamination due to faulty well construction, blowouts, and leaks and spills of waste water and chemicals stored on pad sites. Of all the issues related to hydraulic fracturing, the possible effects on groundwater are without a doubt the most contentious. Numerous allegations have been made related to hydraulic fracturing, with particular emphasis on impacts to water wells. More of this serious issue will be covered in detail.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

5 Pre-Drill Assessments

If fresh water aquifer contamination is a concern, many concerned parties – both in industry and in the environmental sector – believe shallow water monitoring wells should be drilled at the perimeters of the pads, with samples taken as needed. Collecting samples from these water wells before drilling would then be done to establish a base line set of analytical data to show water conditions prior to drilling operations. In fact, some states have enacted regulations to establish pre-drilling groundwater quality through a baseline monitoring program. The baseline sampling would then be followed by regular monitoring during all phases operations, including hydraulic fracturing. This process could serve two purposes: Provide very early warning in case of a well construction leak; and Eliminate the operation as a potential source of pollution in some areas of concern, as when it is shown that constituents were present in water wells before shale gas development began. High-quality analytical data before, during, and after production processes have been increasingly collected to document baseline and 19

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post-drilling groundwater quality through wells installed at the well pad. However, one obvious shortcoming of this protocol is that, as stated previously in this book, typical horizontal lengths may range from 2,000 feet to 6,000 feet, with extremes of 12,000 feet or more. Therefore, if water monitoring wells are located at the well pad, they could be anywhere from 2,000 to 12,000 feet from the location of the actual fracturing process. The following is an excellent paper written by Lloyd Hetrick from an EPA workshop and reprinted with permission. It describes the essentials of well design. While normally the authors would have read the work, paraphrased important parts, and quoted where necessary, after reading this work, it became clear that every aspect was important to share. The work defines well integrity by one simple outcome: the prevention of vertical migration of fluids in order to protect drinking water resources. A generic shale development well is presented, beginning with its basis of design, then construction, an operational phase, and ultimately its plug and abandonment. This chronology is illustrated by a series of well schematics, which are provided in the images mentioned later as pictogram slides. Regulations, industry standards, and best practices will be addressed, as will failure categories and relative failure rates at each phase of the well’s life cycle. This case study will also raise relevant issues that may not have been fully discussed during this workshop, such as the difference between exploration and development phases, development well economics, the potential for well integrity impacts from adjacent well activities, and a time line perspective. A brief process description for oil and gas projects might be helpful. Years before a well is drilled, significant geological and geophysical “G&G” work is performed to identify prospective areas. During this time, offset wells are studied to identify subsurface hazards that may be present in order to avoid or mitigate them. Once a prospect is defined, mineral leases are acquired, additional G&G and reservoir analysis performed, and well design determined for specific drilling locations. The first group of wells drilled are called “exploratory” and intended to define the commercial value of the prospect. Exploratory wells require extra time to gather data on the quality of the reservoir and are also used to identify well construction efficiencies for the development phase. Once the project transitions from exploration to development, each well has to pass an economic hurdle to be drilled. Regardless of being exploratory or development, responsible oil and gas companies have a strong business incentive to protect the environment, mineral reserves, and the well itself (1). It is almost always more difficult

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and costly to re-enter and repair a well than addressing design deficiencies up front during construction. This case study, although generic, is not unlike the Marcellus, Eagle Ford, and other unconventional plays with multiple hydrocarbon zones. Even though only one reservoir is the current development objective, additional reservoirs are candidates for future development. Accordingly, only the most relevant technical items such as failure modes will be included and even then, will be greatly abbreviated. For example, if corrosion is considered to be the primary failure category, the technical discussion will end there with no deeper look into the true root cause failure mode such as galvanic corrosion, sulfide stress cracking, etc. Federal and state environmental laws protect underground sources of drinking water or “USDWs.” The term USDW is used synonymously with the term “protected water” and refers to an aquifer with less than 10,000 mg/l total dissolved solids or “TDS” (2). State mineral law regulates the extraction and conservation of minerals unless on federal BLM or BIA land, where federal mineral laws apply. In either case, the regulatory agency that oversees mineral extraction is also the primary regulator for protecting USDWs during oil and gas exploration and production activities (3) (4). Protected water and hydrocarbons have natural separation (5) in most situations. There are however, areas of the country where methane is routinely found to exist naturally in USDWs (6) (7) and has been associated with bubbles in rivers as early as the mid-1800s (8). There are also locations where methane vents to the surface via natural pathways having nothing to do with oil and gas extraction activities (9) (10). It has been estimated from a review of Pennsylvania regulatory records that over 95% of the complaints that oil and gas activities had contaminated private water wells were actually due to preexisting or other land use activities (11). These naturally occurring migrations are not limited to methane, as towns named Oil Springs, KY (12), Oil Springs, Ontario (13), and historical sites such as Seneca Oil Spring, NY (14) and Brine Springs, TX (15) all attest that oil and brine have been observed migrating to the surface dating back to the 1600s.

5.1 Basis of Design A development well is drilled only if there is confidence that the estimated recoverable hydrocarbon reserves will provide an acceptable economic rate of return, given the cost to construct and operate the well. For an unconventional gas play, development wells tend to have generational designs where a group of wells will have a similar drilling, casing, cementing, perforating,

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and hydraulic fracturing design. Over time as more wells are drilled, experience provides opportunities to correct any design deficiencies, improve drilling efficiencies, and well performance, and therefore subsequent generations of wells are seldom designed exactly the same. Individual wells, regardless of their generational status, receive detailed engineering analysis and planning that is communicated to the well site supervisor in the form of a written drilling and completion procedure. These well-specific procedures are a planned sequence of activities that also incorporate regulatory compliance and industry best practices.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

6 Well Construction

6.1

Drilling

A typical onshore well is a conductor pipe that is driven, drilled, or augered into the ground by a construction crew or “spud rig” prior to the drilling rig’s arrival. This conductor pipe is a structural component that sometimes is not needed at all. Conductor pipe most often does not reach the top and does not penetrate the base of protected water; therefore, it is not involved in protecting USDWs from vertical migration of fluids. Accordingly, failure categories for the conductor pipe will not be discussed. The surface hole is drilled to a prescribed depth below the base of protected water. This depth is most often provided by the State Oil and Gas Regulator, as in Oklahoma (16), or the State Environmental Protection Regulator, as in Texas (17), or not specifically provided other than to protect all USDWs encountered, as in Pennsylvania (18). In this latter situation, oil and gas operators typically research a Pennsylvania Groundwater Information System “PaGWIS” database and local water well driller’s records to generate a hydro-geological map in order to determine depths of water that need to be protected. The surface hole is not left open for more than a few hours while being drilled, cased, and then cemented back to surface. Those zones left open 23

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during this brief period are all USDWs, so vertical migration of fluids does not present a significant threat during surface hole drilling. The surface hole on our case study well is drilled in a few hours on day #1of the drilling operation. The surface casing string is the primary barrier to prevent fluids from the wellbore from entering protected water as the well is being drilled to the next casing setting depth. Unlike the conductor pipe, surface casing is always required, and is typically specified by regulation to be of “suitable and sufficient” quality (19) or “suitable for all drilling and operating conditions such as tension, burst, collapse” (20). For all casing strings, industry best practices provide extensive guidance on the selection of proper casing size, grade, weight, and connections, plus procedures for field handling, inspection, and testing (21) (22) (23) (24) (25) (26) (27). For our case study well, the surface casing is “run” or installed in a few hours during day #1 of the drilling operation. Failure categories for the surface casing and all other casing strings can be divided into the following five categories (28). It should be noted that two of these categories, mechanical and corrosion, may be secondary to cement failures where a failed cement sheath can lead to buckling or external corrosion that would not have otherwise occurred. Failure categories, their respective failure modes, relative failure rates, and remedial options will be discussed briefly: Materials: defects, tolerance busts, not getting the quality of pipe specified Connections: wrong connection selected for the service, improper makeup Wear and Handling: internal wear from drilling, external damage from handling Mechanical: tensile, burst, collapse, buckling, cyclic loading Corrosion: internal vs external; galvanic, CO2, sulfide stress, hydrogen induced cracking Materials defects are supplier dependent, and can be managed by inspections and other supply chain quality control efforts. Connection problems are most often related to improper makeup and can be minimized by onsite supervision. Wear for the surface casing string is seldom a concern and occurs as a result of other problems encountered while drilling the well. Mechanical problems with the surface casing are very few when compared to deeper casing strings that are exposed to higher pressures and

Well Construction 25 temperatures. External corrosion presents the highest failure category for surface casing. Remedies may include external coatings, cement squeezes, and cathodic protection systems. The surface casing string’s cement job provides the primary barrier against vertical migration of fluids into protected water for the entire life of the well. In the context of USDW protection, the importance of getting a good primary cement job on the surface casing string cannot be overstated. Remedial cementing options do not provide high success rates for zonal isolation and should be considered only for contingency purposes. Of all regulations for onshore wells, the rules for surface casing cementing contain the most stringent requirements for hole size versus casing size, centralization, cement quality, cement quantity, cement placement techniques, and quality assurance than for any other casing string (29). Failure to properly cement the surface casing string triggers both agency notification and corrective actions (30). The surface casing on our case study well is cemented on day #2 of the drilling operation. There is a significant body of information published on cement selection and cementing best practices (31) (32) (33) (34). There is also a significant body of information available on cementing failure rates (35) (36). This Well Integrity Case Study will focus on those conditions that directly relate to zonal isolation for the protection of USDWs, briefly discussing three failure categories, with their respective modes and relative failure rates, and remedial options: Insufficient cement volume: underestimated annular volume, lost circulation Low bond strength: poor slurry design, poor management of hydrostatic head pressure Micro annulus, cracking, plastic deformation: thermal and pressure effects, cyclic loads Cement failure rates are directly proportional to the ability to evaluate the top of and quality of the cement sheath. Cement tops can be identified by a temperature log, relative cement bond quality can be identified by a Cement Bond Log or CBL, while absolute cement bond quality requires a combination of logging, testing, and engineering analysis (37). For all three cement failure categories, remedial options are not optimum, and include pumping in from the top, spotting from the top via a small work string, or by perforating and squeezing. It should be noted that two of these three remedies, pumping in from the top and perforating and squeezing, might add new problems for zonal isolation if not properly executed.

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There is a strong correlation between gas migration and un-cemented or poorly cemented casing strings. There is also a strong correlation between external casing corrosion and the absence of a good cement sheath (35) (36). After the surface casing has been successfully tested, the float collar, float shoe, and approximately 10 feet of new formation are drilled. Another integrity test is then performed, a Formation Integrity Test or “FIT,” which tests both the casing shoe and new formation together. This is not a leakoff test and does not test the limits of the shoe and formation; rather, the FIT provides an assessment of the wellbore’s ability to withstand additional pressure in case of an influx of fluids and allows for safer drilling to the next casing point (38). The next sections of well, which for this case study includes an intermediate and production casing section, are essentially a repeat of the surface casing section described above, except that: The design depth for intermediate and production casing strings are not as comprehensively regulated (as for the surface casing depth) other than to provide safe drilling operations and to prevent the waste of minerals. The regulations concerning hole size versus casing size, centralization, cement quality, cement quantity, cement placement techniques, and quality assurance for intermediate and production casing strings are not as specific (as for the surface casing) other than to provide safe drilling operations and prevent the waste of minerals. Although this case study well has been drilled, cased, and cemented over a 30 day period, the first two days are the most critical for zonal isolation of USDWs where the foundation for well integrity is determined.

6.2 Completion Well completion is the where the production casing is perforated, the formation is hydraulically fractured, frack fluids are unloaded from the formation, and production operations commence. This is basically the well’s configuration for the rest of its life as it relates to protecting USDWs. Prior to performing the hydraulic frack, the production casing is tested to anticipated frack pressure plus a safety factor, as is the frack tree and all of the surface pumping equipment and lines. During the frack, all casing annuli are monitored, as are the injection rate, injection pressure, and

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Cemented to surface Conductor casing Cemented to surface Surface casing Drilling mud Cement Intermediate casing Drilling mud Cement

Production casing

Figure 6.1 Well Casing.

slurry properties. If during the frack job, significant pressure is found on the intermediate casing annulus, or there is any indication of communication with the surface casing annulus, the frack job is shut down and not resumed until corrective actions are made that only the intended zone is subject to frack pressures. Refracks are similar to original fracks as discussed above, with the exception that a frack string or wellhead saver might be used to protect older production casing strings and wellheads from frack pressures. This is a case-by-case situation that requires additional testing and engineering analysis in order to protect both the well and USDWs during refrack operations. As the well is produced, reservoir pressures tend to drop and liquid rates tend to rise; therefore, devices for lifting liquids, such as a tubing string with pumping or gas lift equipment, become necessary. This internal configuration can have an impact on USDW protection and is addressed during the operations phase. Below is a schematic of the various layers in a typical site casing.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

7 Well Operations

Prudent operators monitor all casing annuli on a regular basis to be able to detect sustained casing pressure or SCP. This condition could be caused by thermal expansion of annular fluids, packer or liner leaks, leaks into the annulus from inner tubing or casing strings, or from annular migration due to poor zonal isolation. All states have rules for reporting and responding to the loss of well integrity, which includes releases, non-thermal SCP, and other abnormal situations (39), as does the BLM (40), as do best industry practices (41). The Commonwealth of Pennsylvania has new rules that require quarterly mechanical integrity testing and annual reporting for all operating wells (42). Adjacent well operations may have an impact on mechanical integrity as our case study well contemplates. Hydraulic fracturing of a well near our case study well into a zone that is not protected, or not adequately protected for the conditions imposed, can lead to unwanted well to well communication. This is currently a void where regulations and industry practices have not fully recognized that well integrity can become a neighborhood issue.

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7.1 Well Plug and Abandonment “P&A” Similar to well construction regulations and industry practices, well P&A also has comprehensive guidance to prevent vertical migration of fluids into USDWs. There is clear guidance for plug location, cement quantity, quality, placement techniques, testing, and reporting (43) (44) (45). Regulations may also specify that only approved cementing contractors perform plugging, require independent onsite supervision, and require post cement job certifications by both the operator and the cementing company. There are also significant industry studies and best practices for well P&A (46) (47). Failure studies have found that vertical migration issues in P&A wells are directly related to the original primary cement job during well construction. Those wells with gas migration to the surface prior to well P&A were likely to continue to have gas migration to the surface after P&A. Additionally, those wells plugged with bridge plugs and dump bailed cement on top were found to be more prone to leakage than wells plugged with cement that was circulated or squeezed in place (35) (36).

7.2 Considerations Well integrity and well construction are inextricably linked, regardless of the completion technique selected. Primary cementing is the critical step for preventing vertical migration of fluids during the well’s productive life, and afterwards. State and federal regulations address casing and cementing with prescriptive rules and reporting requirements, while industry employs a large body of technical studies and best practices. There are five identified casing failure categories: materials, connections, wear/handling, mechanical, and corrosion. These are not as problematic for zonal isolation as three identified cementing failure categories: insufficient cement volume, low bond strength, and cement sheath damage. For hydraulically fractured completions, significant bodies of industry technical information and best practices have been published. State and federal regulations address hydraulic fracturing with rules and reporting requirements that are continuously adapting to keep pace with technology advancements (48). Adjacent wells and the potential for unwanted communication during hydraulic fracturing is a concern. State and federal regulations are largely silent on this issue, as are industry studies and best practices.

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Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

8 Failure and Contamination Reduction

The following are several key areas to be addressed in order to develop a pad site that is both safe for the environment as well as being productive.

8.1 Conduct Environmental Sampling Before and During Operations Many of the contaminants that have been attributed to fracking, such as methane gas, occur naturally in groundwater and soil. If post-fracking contamination of soil or water is found, and there is no pre-fracking baseline against which the contamination can be compared, it could be difficult for the well operator to demonstrate that such contamination was preexisting. This type of uncertainty increases the risk of regulatory scrutiny and litigation. Some states, like Wyoming, already require pre-drilling disclosures. Consider engaging a qualified environmental consultant to test water and soil before fracking begins. Air modeling or monitoring should also be performed during operations to help demonstrate that emissions are under control. 43

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Disclose the Chemicals Being Used in Fracking Operations

This may be the issue that generates the most attention from state legislators and environmentalists. All of the states that recently have enacted fracking related statutes (e.g., Texas, Colorado, Ohio, Pennsylvania) have included sections that not only address the disclosure of chemicals used, but also provide some level of protection for trade secrets. The energy industry as a whole has supported this approach and generally agrees that while the disclosure of the chemicals used is appropriate, companies should not be forced to publish their exact fracking fluid “recipes.” Companies have also come to recognize that there are benefits to using environmentally “friendly” chemicals as much as possible. For example, when the public is advised that the guar gum used to gel frack water is the same ingredient commonly found in ice cream and bakery products, this type of disclosure tends to negate the fear associated with the use of “unknown” chemicals.

8.3 Ensure that Wellbore Casings are Properly Designed and Constructed The U.S. Department of Energy demonstrated that the risks of a properly constructed well contaminating an aquifer as a result of racking are remote. The most significant risks come instead from poorly constructed casings that might leak into groundwater. Thus, many state legislatures have enacted strict regulations that govern the manner in which casings are to be constructed, tested and monitored. Once again, the industry as a whole has already embraced these efforts to ensure that wells are properly built and should continue to implement improved technologies as they become available.

8.4 Eliminate Venting and Work Toward Green Completions On April 17, 2012, the U.S. Environmental Protection Agency (EPA) issued the first federal air standards for natural gas wells that are hydraulically fractured. A key component of the final rules is the implementation of a process known as “green completion.” The process separates gas and liquid hydrocarbons from the flowback and is expected to yield a nearly

Failure and Contamination Reduction 45 95 percent reduction in greenhouse gases. Although green completions are not mandatory until January of 2015, companies are expected to use this time to acquire the necessary equipment. Until then, flaring is to be used to minimize the impact of these gases upon the environment.

8.5 Prevent Flowback Spillage/Leaks Millions of gallons of flowback can be generated by fracking just one well. The flowback will include sand, chemicals (i.e., biocides, surfactants, gelling agents), brine, and dissolved solids. If the flowback is not contained properly, it can leak into nearby surface water and soil, thereby harming the environment and increasing the risk for various types of litigation and regulatory action. One way to minimize such risks is to ensure that all flowback pits are properly lined. Another is to implement a “closed system” that eliminates the pit altogether and routes the flowback directly to storage tanks prior to offsite treatment and disposal.

8.6 Dispose/Recycle Flowback Properly The EPA and states share responsibility for implementing the Clean Water Act (CWA) programs. The effluent guidelines program prohibits the onsite direct discharge of flowback from fracking wells into waters of the U.S. While some flowback is transported to publicly owned treatment works (POTWs), and significant amounts are still injected into underground wells for disposal, there is an increasing trend to recycle the flowback, and for good reason. Recycling can significantly reduce the amount of water needed for fracking activities – an extremely important consideration in those portions of the country experiencing drought conditions. And if the recycling is done near the drilling pad, it can also curtail the truck traffic needed to deliver the water and remove the flowback, thereby lowering transportation and offsite disposal costs.

8.7 Minimize Noise and Dust Fracking activities at the drill pad can be loud. When they occur in urban areas or near residential communities, efforts are frequently undertaken to abate the noise by surrounding the drill pad with noise blankets, sound

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curtains, or wall barrier systems. Truck traffic also has the potential to generate significant levels of noise and dust. As indicated above, reducing the amount of traffic at the drill pad by recycling is one way to combat these potential problems. Other ways include the use of centralized pump stations and multi-well drilling techniques that reduce the number and size of pads needed for fracking. Spraying service roads with treated production water and brine is also permitted in some states to reduce dust, but care must be taken not to apply such liquids near vegetation, residences, or drainage ditches.

8.8 Protect Workers and Drivers The New York Times has reported that the most dangerous jobs associated with fracking are not at the drilling rig but on the road. Drivers working at oil and natural gas wells reportedly work longer hours than drivers in other industries, thereby subjecting them to fatigue and a greater risk of having an accident. That is not meant to minimize the risks faced by drilling crews who obviously could be exposed to a many potential jobsite hazards if proper safety precautions are not followed. While certain exemptions for oil and gas truckers were upheld by the Federal Motor Carrier Safety Administration, the exemptions have come under closer scrutiny in the last two years. The need for companies to enforce OSHA regulations and other safety rules implemented by the industry to protect its workers is of critical importance.

8.9

Communicate and Engage

Nearly every group that has generated a set of Best Management Practices has emphasized the importance of communicating with nearby residents, local governments, and other stakeholders. Misinformation can be quickly spread through the Internet. First impressions, although mistaken, can be difficult to reverse. The Investor Environmental Health Network (IEHN) recommends that the fracking industry identify communities potentially impacted, address their major concerns, and establish a mechanism for resolving conflicts. Companies should be prepared to direct persons with legitimate questions to websites that provide answers that are scientifically and factually accurate. Several such websites exist, such as http://www. energyindepth.org/. The need for patience must also be stressed, since many of the discussions that involve fracking are emotionally charged.

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8.10

Record and Document

This last recommendation comes from the authors who also happen to be litigators. Sloppy record keeping gives plaintiffs, regulators, and juries too much leeway to draw erroneous conclusions. If documentation should have been kept, but was not, there will almost always be an inference that the “lost” documents were adverse to the interests of the company. Sloppy record keeping reflects poorly on a company’s overall reputation even though the company may have an excellent history of actual environmental compliance and worker safety. It is also important to recognize that in this fast-paced age of instant communications with emails and text messages, virtually all of those communications can be converted to documents that must be produced if litigation occurs. Thus, to the extent possible, refrain from sending emails and text messages when frustrated or angry. Similarly, jokes and needless exaggeration usually do not translate well. Think about how that email might look if blown up on a screen in front of a jury. If that image causes discomfort, think twice before sending it.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

9 Frack Fluids and Composition

The use of hydraulic fracturing for oil and gas exploration in the U.S. has become highly controversial, with one of the greatest points of contention between the public and industry being the make-up of frack fluids and their possible impacts on public health and the environment. This has become such a hot topic with many segments of the public for two reasons: 1. if a concern exists about the pumping of fluids into any structure, then the most concern will naturally be centered on what is being pumped, and 2. a great deal of suspicion arose and was intensified when the oil and gas industry initially balked at the disclosing the chemical makeup of fluids used to enhance hydraulic fracturing. This has become a major argument point for the concerned public because, basically, “if there is nothing to hide, why not disclose it?” Take, for example, if a small child walks into a room with his hands behind his back and will not show what is there for several minutes…and then only

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does when forced. Well, even if it turns out he was holding something as harmless as a feather behind his back it will cause suspicion all the same, wondering “what was he doing with that feather!” To make this contentious subject a little clearer, this section will provide descriptions of why frack fluids are needed, what general chemicals are needed and used, relative amounts of chemicals in frack fluid composition, the different types and uses of proppants, a discussion on slickwater, and a discussion on present regulations and standards for industry disclosure of frack fluid compositions.

9.1 Uses and Needs for Frack Fluids There are a great deal of varied chemicals used every day in oil production wells during all phases of drilling, completions, and production. These chemicals can include cements used to seal the annulus to protect the pipe and surrounding formation from damage through wells exceeding the producing and stimulation requirements placed on the pipe, temperature, and even natural ground stresses. An example is corrosion inhibitors. These chemicals help pipe and connection seals remain within design specifications to prevent failures. Corrosion prevention and treating chemicals may also be necessary due to operational and field changes, even after well completion and during production. These chemicals can be used in much the same fashion as fracturing; however, chemicals in well operation are applied in smaller quantities, at lower pressure, and in a regular maintenance-driven schedule during a well’s life. Just like the maintenance-driven chemicals utilized during operations, chemicals serve numerous necessary functions to ensure successful, safe, and efficient hydraulic fracturing operations. The following provides a comprehensive look at common chemical additives utilized in the current fracturing industry.

9.2 Common Fracturing Additives There is no one formula for how much each of the following additives are used in a given fracturing fluid; however, the following section is intended to present a brief description of some of the most commonly used additives and a general percentage breakdown of each that has been widely reported. Each well differs in the number, type, and amount of additives used (please note: the term “additives” is used to include water, sand, and chemicals to

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allow for a discussion of each under one heading) in a successful fracture treatment; “typically,” between 3 and 12 additives are used, depending on the conditions of the specific well to be fractured and characteristics of the surrounding formations. Additives utilized in hydraulic fracturing operations are intended to serve specifically engineered uses, such as biocides to control microorganism/bacterial growth, corrosion inhibitor to prevent corrosion of pipe, viscosity agents to carry proppant, gelling agents to improve proppant placement, friction reduction to decrease pump friction and reduce treating pressure, oxygen scavengers to also aid in corrosion prevention in metal pipes, and acids to help remove drilling mud build up damage. Fluids (typically water): usually approximately 98%-99% of the total volume; used to create the fractures in the formation and to carry a propping agent (typically silica sand) that is deposited in the induced hydraulic fractures to keep them from closing up. Hydrochloric acid (HCl): from 5% to 25% in solution used to help dissolve minerals and help remove damage near the well bore by cleaning out cement around pipe perforations; also helps initiate fissures in the rock matrix. Corrosion inhibitor (typically ammonium bisulfate): usually approximately 0.2%-0.5% of acid total volume, resulting in approximately 5–10 gallons; used only in instances when acid is used to prevent pipe corrosion. Biocides (typically sodium hypochlorite or chlorine dioxide): usually approximately 0.005%-0.05% of the total volume; used to control bacterial growth in the water injected into the well and prevent pipe corrosion. Friction reducers (typically polyacrylamide based compounds): usually approximately 0.025% of total volume; used to reduce pipe friction and pressure in the piping required to pump fluids. Gelling agents (guar gum and cellulose): not often used; used to thicken water-based solutions and help in suspension and transport of proppants into formation. Crosslinking agent (boric acid, titanate and zirconium): used to enhance abilities of the gelling agent to even further aid in transport of proppant material.

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Breaker solution: when cross-linking additives are added, a breaker solution is commonly added in the frack stage to cause the enhanced gelling agent to break down into a simpler fluid so it can be readily removed from the wellbore without carrying back the sand/ proppant material. Oxygen scavenger (ammonium bisulfate): used to prevent corrosion of pipe by oxygen. Iron control and stabilizing agents (citric acid and acetic acid): used to keep iron compounds in soluble form to prevent precipitation. Surfactant: usually approximately 0.5 to 2 gallons per thousand gallons of frack fluid; used to promote flow of the fluids used in the fracturing process. Scale Inhibitor (ethylene glycol): seldom used; used to control the precipitation of specific carbonate and/or sulfate minerals. Proppants (sand, resin coated sand, or man-made ceramic particles): usually approximately 1%-1.9% of total volume; used to hold fissures open so gas and oil can be extracted. Now, many readers that have seen this type of information before are now expecting to see one of those “other uses” tables stating that fracking fluid must be safe due to the “ingredients” of fracking fluids having everyday uses, such as scale inhibitors having the same chemicals as windshield washer fluid, friction reducers having same chemicals as many makeup products, surfactants being basically the same as shampoo products, proppants being play sand, and hydrochloric acid also being swimming pool cleaner. These may be true in the strictest sense of the word, but this type of listing can also be very misleading and insincere, in that most all chemicals can be used for many different things, but are still not something with which one necessarily wants to come in contact. For example, ammonium nitrate is commonly used in agriculture as a high-nitrogen fertilizer, nitromethane is a commonly used industrial solvent, and Ryder trucks are commonly used to move families and their belongings to their dream homes; these are also three of the common “ingredients” used in the tragic April 1995 Oklahoma City bombing of the Alfred P. Murrah Federal building that killed 168 people. This is, of course, a comparison made for shock value, but it is meant as such to stick in your memory as how these sorts of comparisons can be manipulated and to drive home

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the fact that the best policy is to study upon facts when reading a comparison like this and make an informed decision for oneself.

9.3 Typical Percentages of Commonly Used Additives Fracturing fluids are varied to meet the specific needs of each location; however, evaluating the widely reported percentage volumes of the fracturing fluid components reveals the relatively small volume of different chemicals that are present. Overall, the concentration of various chemicals in most fracturing fluids is a relatively consistent 0.5% to 2%, with water and proppants making up the remaining 98% to 99.5%. Keep in mind, however, that a typical fracturing job uses upwards of five million gallons of fracturing fluid, so a small percentage amount may actually result in a great deal of chemical usage, no matter how diluted it may be. As one can imagine, the overall composition of fracturing fluids varies among companies and the drilling location. Fracturing fluids typically contain: Approximately 90% water Approximately 9.5% proppant materials Approximately 0.5% chemicals: this percentage varies, but is typically between 0.5–1.0% by weight of total fluid As described in previous sections, the chemical additives are included in fracking fluids to tailor the fluids to the requirements of the specific geological situation. The very popular chart below, taken from Modern Shale Gas Development in the United States, demonstrates typical volumetric percentages of additives that were used for a typical hydraulic fracturing treatment of a shale horizontal well.

9.4 Proppants Proppants are pretty hard to make into anything fun, exciting, or entertaining…as they are, for the most part, made up of sand or a manufactured facsimile of sand. Sure, if one wants to be poetic, one can refer to proppants as the only materials the operators want to remain downhole in the fractures. If one really wants to think poetically, feel free to consider a proppant’s life as one of making its way from origins mined within the earth, only to return to its final resting place deeper within the earth’s fractures.

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KCl 0.06%

Gelling agent 0.056% Scale inhibitor 0.043%

Ph adjusting agent 0.011%

Surfactant 0.085%

Water and sand 99.51%

Breaker 0.01% Crosslinker 0.007%

Other 0.49%

Iron control 0.004% Corrosion inhibitor 0.002% Friction reducer 0.088%

Acid 0.123%

Biocide 0.001%

Graph 9.1 Volumetric Percentages of Additives in Fracturing Fluids.

As discussed earlier, proppants are simply materials (typically silica sand, resin coated silica sand, or manufactured ceramics) used to prop open the open fractures to promote flow and eventual extraction of hydrocarbons. As simple as proppants may seem, the estimated amount of proppant used in industry has grown tenfold since 2000. In some regions, it is not uncommon to see upwards of four million pounds of proppant used per well, and for proppant to represent up to 5% of well costs. The growth in proppant usage is generally attributed to operators realizing better well completion techniques with more proppant per stage and better well pad techniques with more laterals and fracturing stages per pad. Even considering the accelerated growth in the last decade, the evolution of proppant usage has been slow to develop over the industry lifetime as a whole. Consider that the first frack job was conducted in 1947, utilizing a reported approximate 20,000 pounds of uncoated frack sand, and manufactured ceramic proppant was not first used until 1983, or 36 years later. Then, approximately one year later, resin coated proppant was first introduced. As with most all technologies, as new techniques continue to develop, proppants will surely evolve further to increase effectiveness and efficiency in hydraulic fracturing. No matter the type of proppant used, the most important characteristics for a proppant are particle size distribution, crush resistance, shape, and sphericity (or roundness). Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore. Grain size is critical because a proppant must reliably fall within certain size ranges to coordinate with downhole conditions and completion design.

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Proppant shape and hardness qualities are also very important to the efficiency and effectiveness of a fracturing operation. A coarser proppant allows for higher flow capacity due to the larger pore spaces between grains, but it may break down or crush more readily under high closure stress, and rounder, smoother proppant shapes allow for better permeability. Another important quality that must be taken into consideration is the proppant’s hardness with respect to the formation. If the proppant is unable to embed in the formation, something referred to as point load occurs, which leads to higher flow capacity, but the proppant will break more easily. However, if the proppant is able to embed in the formation, it is referred to as embedment, which results in the load pressure spreading out over the proppant area, increasing the breaking point, but also lowering flow capacity. Embedment is also a function of particle size. Even though almost all proppant materials are naturally occurring, including manufactured ceramic proppants, with relatively low amounts of additional engineering necessary, the logistics in procuring and transporting proppants can be daunting. Logistical considerations include coordination of manufacturing material resources, transportation costs, and possibly a substantial monetary investment, or in equipment necessary, for processing and material handling facilities.

9.5

Silica Sand

While the all-encompassing term for the material “sand” is generally used for nearly all forms of broken down granules of minerals or rocks, to be specific, sand falls between silt and gravel in the spectrum of sizes. There are, however, many varieties of sand in the world, each with their

Sufficiently placed & sized proppant –Effective return–

No proppant –No return–

Individual fracture Return flow Insufficiently placed & sized proppant –Ineffective return–

Figure 9.1 Proppant Size and Placement.

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Proppant irregularity = Less effective return and weakness

Figure 9.2 Proppant Shape.

Point load proppant

Higher flow capacity, increased proppant fragility

Embedded proppant

Lower flow capacity, increased proppant strength

Figure 9.3 Proppant Hardness.

own unique composition and qualities. Everyone likes to picture the white sandy beaches of vacation destinations, for example, which are made up primarily of limestone that has been broken down. Then there are also many black sands, either volcanic in origin or containing magnetite. Other sands have high levels of iron in them, and so are rich and yellow in color. The type of sand utilized for proppant materials is silica sand, which is, by far, also the most commonly used type of proppant. Silica sand, unlike many other “ingredients” of frack fluid, is more of a natural resource than an engineered product. Silica sand proppant is, in a simplistic description, made up of the most common mineral in the earth’s continental crust, quartz. Silica sand is simply quartz that over the years, through the work of time and several erosion forces, has been broken down into tiny granules. Even though silica sand is a relatively common material, silica sand used for proppant is a specifically selected and utilized product. Proppant quality silica sand is a direct function of both the original depositional environmental and some slight mechanical processing, if necessary. Silica sand used for proppant is chosen for its round spherical shape and commonly graded particle distribution…unlike the common sand one might find at the beach or on a playground, which often feels gritty when rubbed between the fingers. In addition to the oil and gas industry, there is some competition between other industries for the bulk of silica sand, as industrial-grade

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silica sand has a wide range of uses. This resource is also commonly used in the manufacture and preparations of various types of glass, in water filtration, sand blasting, as fill and as an ingredient in industrial concrete, in the metal casting industry to make cores and molds, and ironically, it is also used in the creation of highly flame-resistant industrial molds and construction materials for the kilns used in the manufacture of the sintered ceramic and bauxite proppants. Even considering all the helpful and positive uses for silica sand across several different industries, there are some possible hazards related to its use. Because of the fine grains involved in silica sand, it can present a health risk if not properly handled. Care must be taken to keep the silica sand out of the lungs during use, and all materials containing more than 0.1% of silica sand must be clearly labeled. Workplace health applications also need to be in place and enforced: failure to wear a proper respirator or mask can result in lung irritation, and prolonged exposure can cause a chronic condition known as silicosis. Silicosis is a form of lung disease resulting from occupational exposure to silica dust over a period of years, causing a slowly progressive fibrosis of the lungs, impairment of lung function, and even a heightened susceptibility to tuberculosis of the lungs. Silicosis can also progress and worsen even after someone is no longer exposed to the silica dust, causing long-term effects and shortness of breath years later. Also, in the year 2000, the World Health Organization determined that crystalline silica is “associated with silicosis, lung cancer, and pulmonary tuberculosis” in classifying it as a Group I carcinogen “based on sufficient evidence of carcinogenicity in humans and experimental animals.”

9.6 Resin Coated Proppant As the name suggests, and to describe in the most simplistic of terms, resin coated proppant is exactly that: silica sand coated with resin. Resin coating silica sand proppant is utilized for two main functions: 1. to spread the pressure load more uniformly to improve the crush resistance of the silica sand particles, and 2. to keep pieces together that were broken from high closure stress from down hole pressure and temperature: this not only prevents broken pieces from flowing into the borehole, but also prevents these same broken pieces from returning to the surface during flowback production operation.

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Currently, there are two types of resin coated proppants, Pre-cured and Curable. Pre-cured is the “original” technology, in which the resin coating on the silica sand grains is fully cured prior to injection into the fractures. The newer, curable technology has often been described as having a coating that is not completely “baked” or hardened. Curable resin coated proppants are used at a little more than half cure, so that when the proppant is pumped downhole it can finish curing in the fractures with down hole pressure and temperature. The advantage to curable proppant technology is that it allows the individual proppant grains to bond together in the fracture, resulting in the grains bonding together uniformly in strength when temperature and pressure reach appropriate levels.

9.7 Manufactured Ceramics Proppants A third commonly used type of proppant is the manufactured ceramic proppant. This is a proppant generally manufactured from a type of ceramic material, typically non-metallurgic bauxite or kaolin clay. Bauxite is an aluminum ore from which most aluminum is extracted, while kaolin is one of the most common minerals, occurring in abundance from chemical weathering of rocks in hot, moist climatic soils like tropical rainforest areas. Both bauxite and kaolin are utilized as proppants because of their superior strength characteristics, which are further enhanced through a process known as sintering. The sintering process is conducted in high-temperature kilns that are used to bake the bauxite or kaolin powder after it has been made into specifically sized particles. This process decreases the water content in the bauxite and kaolin to make them more uniformly shaped for size roundness and spherical shape. The desired results of this process are that the manufactured ceramic proppants can be engineered to withstand high levels of downhole pressure (closure stress).

9.8 Additional Types As more is learned through the ongoing processes and further advances are made in technology, additional types of proppants are sure to come up. One current trend is toward the usage of “waste” material, including glass, metallurgical slags, and even rock cuttings produced to the surface during oil and gas drilling. The reuse of rock cuttings from gas drilling operations

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is especially attractive, since not only does it reuse a common waste product in industry, but it is also utilizing sources indigenous to the locality, which will cut down wastes while also cutting down on transportation and overhead costs. However, the other possibilities are also quite attractive, in that agreements can be made with landfills, metallurgical operations, and glass companies to recycle and reuse their wastes in lieu of land filling.

9.9 Slickwater Slickwater is a more dilute, predominately water-based fracturing fluid that utilizes a limited amount of additive sand, friction reducers, and other chemicals. Slickwater is prepared this way in order to create a lower viscosity fracturing fluid to allow for an easier escape out of the created hydraulic fracture. Due to its low viscosity, slickwater can also be pumped down the wellbore at a higher rate.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

10 So Where Do the Frack Fluids Go?

As discussed many times in this book, hydraulic fracturing involves the use of pressure applied by a fluid to create a new fracture or enlarge natural fractures present in the rock. These fractures extend in a planar style in general directions perpendicular to the plane of the least principal stress in the rock, following what is called “fracture direction.” These hydraulic fractures are most commonly vertical (until contact is made with a rock of different structure, texture, or strength to stop the fracture height growth), and may extend laterally several hundred feet away from the well bore. These fracture barrier rocks, which stop the fracture upward or downward growth, are very common. Fracture height growth may extend up to a few hundred feet or more, but will likely be quickly limited by one of the dozens of rock barriers above the pay zone. Driving a fracture upwards through several thousand feet of rock is simply not possible, given the limits imposed by natural barriers and stresses of the formation and rocks above the pay zone. A good way to consider this is that if oil and gas are still in the reservoir millions of years after being created, then logic would

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dictate the reservoir barriers would also prevent the upward migration of fracturing fluids. Pumping of a single frack stage may be limited to anywhere from 20 minutes to four hours, depending on the design and intent of the frack. This period of high pressure operation is normally the only time most wells will experience pressure high enough to reverse fluid flow into the formation. However, the required travel time for fluid to flow from the shale to aquifer under those pressures would be years. Any flow of frack fluid toward an aquifer through open fractures would be reversed during flowback. As far as where the chemicals in frack fluids go, chemicals returning from a well after fracture are a fraction (usually between 20% or less for chemicals and about 40% for polymers) of what was pumped down the well. Most corrosion inhibitors, scale inhibitors, and surfactants adsorb onto minerals such as clays in the formation. Those that do not adsorb may bleed back very slowly, usually in a concentration of approximately 5-10 parts per million of water. The hydrochloric acid is typically used up within inches of the frack entry point and yields calcium chloride, water, and a small amount of CO2; therefore, no live acid is returned to the surface.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

11 Common Objections to Drilling Operations

The common objections to drilling operations is different than other objections for two reasons: There is no attempt to separate the operations related to fracking from all other drilling operations: this is simply because most nuisances related to one operation are the same for all (for instance, additional traffic is additional traffic, no matter the origination). The nuisances described in this section are not written of or discussed in a quantifiable way: in other words, this discussion is not centered on an amount, but the simple fact that it exists. A reason for this is because a lot of data is collected for the other aspects related to fracking operations to attempt to prove/disprove their existence, when the nuisances discussed in this section are easily seen as being in

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existence (just spend a few minutes along any road used for drilling operations, and this will become abundantly clear). Please keep in mind that there are many additional nuisances absorbed by those living near drilling locations or related roadways, so this listing is far from comprehensive. The following are merely what most see as the most common, and are not presented in any order of magnitude. That decision has to be made by each individual: one person may be more affected by noise, while another is much more concerned with dust.

11.1

Noise

Noise conditions are usually one of the first things to change and be noticed by local landowners. An increase in noise is also one of the most continuous nuisances related to operations. Drilling and completing a well, from the pad construction to the final completion of the well, takes several weeks and utilizes many different types of equipment. This additional equipment can include additional trucking, construction, and drilling equipment. The noise concerns usually begin with the additional traffic brought to an area during pad construction, then continue with the noises associated with equipment and trucking required to construct a pad, only to be followed by the large amount of noise related to rig construction and operation throughout the well drilling process. Then, once the well site is completed, there may come the additional sounds of compressors used during ongoing production activities. When one thinks of noise concerns related to the oil and gas industry, the first thing that commonly comes to mind is the big noisy rig, or maybe the noisy traffic coming back and forth. These are, of course, very real and valid concerns; however, the thing that is quite possibly the most notable noise nuisance related to the oil and gas industry, due to length of time, is the compressor. For the most part, the heavy rig work and heavy truck traffic lasts approximately one to two months, while the compressor, while not as loud, can continue for a much longer amount of time (months to even years). Gas compressors are normally the largest equipment remaining after the well development process is complete and are utilized for something called gas lift. Gas lift is used in wells that have insufficient reservoir pressure to produce efficiently on their own. The gas lift process involves injecting gas through the tubing-casing annulus to aerate the fluid to reduce its density. Following aeration of the fluid, the formation pressure is then able to better lift the oil column up the wellbore. For pad sites where long-term

Common Objections to Drilling Operations 65 compressor use is anticipated, especially in rural communities where serenity is the norm and even the slightest ongoing noise can be heard clearly for long distances, operators have addressed compressor noise concerns with remote siting (trying to locate the compressors on the part of the pad farthest from homes), noise tampering sound walls, and directing compressors with fans away from homes. However, even with the measures presently taken to mitigate ongoing sound issues, additional work must be done and technology developed to work toward a solution.

11.2 Changes in Landscape and Beauty of Surroundings Several different types of pollution are commonly mentioned in relation to the oil and gas industry, including water pollution, spoil pollution, air pollution, and, as presented in the previous section, noise pollution. However, one that may be overlooked to the majority of the public, but certainly not overlooked to those affected, is visual pollution. Visual pollution is an aesthetic issue, referring to the impacts of pollution that impair one’s ability to enjoy a vista or view. Now, with the possible exception of the immense number of billboards lining the nation’s highways, not many things meet the definition of visual pollution as much as a drill rig. Drill rigs utilized in most unconventional well drilling typically can range from approximately 50 feet to 100 feet in height. Couple the height of the drill rig with the ongoing movement and dust related to drilling, and it is easy to imagine how this would be bothersome to those adjacent to rig locations. One mitigation attempt for this problem would be the usage of lower height rigs. However, the undesirable trade-off for a lower height rig is the necessary extended time on location for smaller rigs. Ironically, horizontal drilling techniques commonly related to unconventional well drilling and hydraulic fracturing locations can actually be considered a “semi-solution” to this problem. Pads used for horizontal drilling commonly include multiple laterals on one location, in which the drilling of multiple wells literally means moving the rig over as little as twenty feet from the original location. This allows wells to be drilled from one location without the necessity of moving the rig and drilling in several locations, which would only disturb that many more possible visual pollution points. This also allows for accelerated drilling time due to lessened rig movement time, a reduction in the number of necessary lease roads and drill pad locations, fewer necessary pipelines, and fewer tank batteries.

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11.3 Increased Traffic Another nuisance commonly cited by those living in oil production areas is the drastic amount of added traffic it creates. This is not necessarily the type of traffic most think of when hearing the word. Traffic related to the oilfield includes all of the initial traffic to bring in heavy equipment for pad construction and eventually the rig itself, followed by traffic for well completion and fracking activities (to get a taste for what this is like, consider the amount of sand used in each frack job, then consider how many separate truckloads that would be), then the ongoing traffic related to hauling produced water and oil from the locations until some sort of pipeline infrastructure can be put in place. Also, keep in mind that many of the areas affected by oil and gas operations are rural and do not, quite simply put, have the proper roadways for the larger size or amount of traffic vehicles that come with industry operations. Not only does increased traffic add additional wear and tear to the local roadways, the narrower two-lane and sometimes even more narrow gravel roads cause very unsafe driving conditions for the industry and local resident vehicles alike. The answers to the traffic problems may seem obvious – do something to lessen the amount of traffic or do something to improve the roads – but finding ways to turn those answers into reality is something much more difficult than may first appear. The first possible answer, “do something to lessen the amount of traffic,” would include: 1. the need to either use fewer (but larger) transport vehicles, resulting in additional hazardous conditions with the larger vehicles on the narrow rural roads; or 2. the need to install a pipeline infrastructure to transport produced water and/or oil, which comes with the obvious concerns related to pipelines installation and location. The second possible answer, “do something to improve the roads,” would depend on the type of road to be improved. Improving and widening gravel-type lease and rural roads is a less daunting task than improving paved city/county roads due to ease of obtaining the proper materials and fewer restrictions put on maintenance. However, making improvement to city and county roads would include needing to clear a wider right-of-way all along the road to be widened, and the city/county would need to have the funds set aside for this task, which is a time consuming process.

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11.4 Subsurface Contamination of Ground Water An increasingly common concern expressed about hydraulic fracturing is that operations create fractures extending past the target formation to aquifers, allowing fracturing fluids to migrate into drinking water supplies. There are several factors that would prevent this from occurring: This would require hydro-fractures to extend several thousand feet beyond the upward boundary of the target formation through many layers of rock. Geologists estimate there is at least a half mile of rock between the natural gas deposits and the groundwater. Impermeable shale acts as a barrier to vertical propagation of both natural and artificial fractures. After hydraulic fracturing is completed, the fluid flow is toward – not away from – the well as gas enters the well bore during production. Despite what the protests may lead one to believe, as discussed before, studies have shown that failure of the cement or casing surrounding the wellbore poses a far greater risk to water supplies than hydraulic fracturing.

11.5

Impacts on Water Wells

Many allegations have been made by residents and documentaries of impacts on water wells that hydraulic fracturing activities are causing some of the most visible and contentious controversies. Most allegations of water well impacts involve methane, color changes, turbidity, and odor. Particularly in areas underlain by gas-producing shales, methane migrates out of the shales under natural conditions and moves upward through overlying formations, including aquifers. Such naturally-occurring methane in water wells has been recognized as a problem in shale gas areas for many years or decades before shale gas drilling began.

11.6 Water Analysis The quality of groundwater can affect not only health, but also society and the economy. Groundwater contamination can adversely affect property values, the image of a community, economic development, and the overall quality of

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life shared by all. Clean water at a reasonable cost is essential, and in many parts of the country, groundwater is the only economical water source available. Once groundwater has been contaminated, it is usually very difficult and costly to clean. Even small contamination sites often cost many thousands of dollars to clean up. The quality of water from private water supplies, such as those from wells at individual homes, is not regulated. It is the responsibility of the well owner to ensure a safe drinking water supply. Although there are a few requirements for water quality testing and monitoring of private wells (i.e., in some areas, testing is required at the time of property transfer), it is recommended that all well owners have their water tested periodically. While “complete” drinking water analyses can be expensive and are generally unnecessary for the private well owner, it is recommended that private water supplies be tested routinely for common contaminants including total coliform bacteria, nitrates, and lead. These contaminants can occur in well water due to agricultural activity, septic system use, household chemical use/ disposal, age of the plumbing, or industrial activity. The frequency of water testing and the contaminants to test for depend on factors such as the potential sources of pollution and the type of well. Another consideration is ensuring that the private well complies with proper well construction standards. A water’s taste, smell, or color is not necessarily an indicator of water quality. Many of the most hazardous contaminants are undetectable to the senses. The only way to detect most pollutants is by testing. Before hydraulic fracturing operations begin in a new area, American Petroleum Institute guidance (API - HF1) recommends that a baseline assessment program that includes the sampling of nearby water wells be conducted prior to hydraulic fracturing operations. Fresh water wells should also be sampled following hydraulic fracturing operations. At least one state (Colorado) requires the sampling of certain water wells in various areas of the state as part of their regulatory program. Another state (Pennsylvania) has regulations that presumptively place the burden of proof on any oil and gas company to demonstrate that they have not caused deterioration of the quality of groundwater used for drinking water purposes in the vicinity of oil and gas wells in the event of a contamination complaint.  In order to obtain valid results from sampling, it is important to follow proper sampling and analysis protocols. Contact a state or EPA-certified laboratory for sampling containers and instructions. Proper protocols may include: 1. using appropriate containers and seals; 2. purging of the well prior to sample capture;

Common Objections to Drilling Operations 69 3. 4. 5. 6. 7.

collection at points before water treatment equipment; following sample container filling procedures; following storage and holding time requirements; utilizing appropriate analysis methods; and following appropriate quality control/ quality assurance protocols.

Sampling should be conducted by someone familiar with sampling procedures. Analyses should be conducted by an accredited laboratory using appropriate analysis methods. One may be able to obtain a list of qualified laboratories by contacting a local health department, state water quality agency shown on the regulations by state page, or county extension agent. It is important for the landowner to have an oil and gas operational sampling and analysis of their groundwater conducted by a professional for constituents that may provide a reasonable baseline for post-fracturing analysis. The National Ground Water Association maintains a list of groundwater professionals that the reader can review to help find someone in the local area for assistance. The following is a good basic list of constituents that should be considered for analysis prior to oil and gas operations. Major cations and anions pH Specific Conductance Total Dissolved Solids Benzene, Toluene, Ethyl benzene, Xylene (BTEX)/ Diesel Range Organics (DRO)/ Gasoline Range Organics (GRO) Total Petroleum Hydrocarbons or Oil & Grease (HEM) Arsenic Barium Calcium Chromium Iron Magnesium Selenium Boron Sodium Chloride Potassium Bicarbonate Dissolved Methane

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Once hydraulic fracturing has taken place and a record of the actual chemicals used is available, it would be advisable to consider having a sampling and analysis conducted on the groundwater for the chemicals shown on the record that match those listed above or those that are by-products, reaction products, or daughter products of those listed above. This is important because many of the chemicals used in hydraulic fracturing will be degraded, oxidized, or otherwise modified during the fracturing process. Thus, simply looking for the chemicals on the list shown above may not yield enough information for a comparative analysis. However,  to minimize costs for the landowner, an alternative analysis should be conducted for at least Total Dissolved Solids (often abbreviated TDS) is a measure of the combined content of all inorganic and organic substances contained in liquid and dissolved methane. An increase in the concentration of either of these constituents could indicate that further, more complete sampling and analysis should be conducted. The reader can learn more about the toxicity characteristics of chemicals by searching for the chemical using the name or CAS number on the USEPA National Center for Computational Toxicology website. USEPA also maintains a Drinking Water Hotline that is available Monday-Friday from 8:30 AM-4:30 PM Eastern Time at 1-800-426-4791. Important: Only a trained professional such as a toxicologist or a physician can tell you if your water is safe to consume. The reader should not use the information obtained from the USEPA Toxicology website, or any other website to make decisions regarding the safety or drinkability of water.

11.7 Types of Methane and What They Show Us One of the most graphic and widely publicized issues related to hydraulic fracturing is the thought that it causes methane gas to emit from water wells, in some instances in ignitable concentrations. However, methane has always been a relatively common contaminant in water wells and can be the result of natural or man-made causes. Methane is a natural hydrocarbon gas that is flammable and explosive in certain concentrations and is produced either naturally by bacteria or by geologic processes involving heat and pressure. There are several possible causes for methane gas to be found in water wells unrelated to hydraulic fracturing operations. These include naturally forming biogenic methane caused by the decay of organic materials or natural seeps of thermogenic methane that have been coming to the surface for millions of years.

Common Objections to Drilling Operations 71 Biogenic and thermogenic methane are reasonable easy to differentiate through analyses, and through this “fingerprinting,” experts can determine if specific instances of methane in a well are related to biogenic or thermogenic processes. Biogenic and thermogenic methane differ in the carbon isotopes they contain, with biogenic methane containing more C12 carbon, while thermogenic methane contains more of the C13 carbon isotope. Biogenic methane is also nearly 100% methane, while thermogenic methane may also contain some propane and butane from thermal decomposition.

11.8 Biogenic Biogenic methane is a near-surface, naturally occurring microorganism type of methane that is continually produced as a by-product from decay of organic materials by reactions in wetlands, sewage, landfills, and even agriculture. Once formed, it will often remain in some shallow, water-bearing geologic formations, into which many domestic water wells are completed.

11.9 Thermogenic Unlike biogenic methane, thermogenic methane is formed deep within the earth from the thermal decomposition of buried organic materials deposited millions of years ago. It is found buried deeper within the earth, and thermogenic gas found near or at the surface is a strong indicator of natural seeps.

11.10 Possible Causes of Methane in Water Wells As mentioned earlier, many water wells are liable to produce some level of odorless methane through sources such as agriculture, livestock, wetlands, landfills, and other sources allowing biogenic gas to form through decaying or vegetation. In addition to these natural causes, it is also quite possible to have detectable methane content in a water well caused by a nearby improperly constructed gas or oil well. A third possible cause of methane in water wells is from the penetration of coal formations that are saturated with fresh water. Coals can have as much as 90% or higher organic content and gas that naturally adsorbed on the organic materials in the coal can desorb as water is pumped from the area, such as water well. Proof of naturally occurring methane near surface in concentrations high enough to allow ignitability can be seen in natural seeps. There are

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literally thousands of natural oil, gas, and salt water seeps that come to the surface. The earliest historical written record of natural oil and gas seeps in the Western Hemisphere was that of Sir Walter Raleigh’s account of Pitch Lake in Trinidad in 1595. Well-known current oil and gas seeps in the United States include the La Brea Tar Pits and McKittrick Tar Pits in California and the “Eternal Flame Falls” of the Shale Creek Preserve, a section of the Chestnut Ridge Park in New York.

11.11

Surface Water and Soil Impacts

Another major concern for hydraulic fracturing well production is the potential for spills or releases at the well pad site or during transportation. Potential sources of release are fuels and oils for the drilling rig and on-site equipment, possible overflow or leak of storage tanks and pits, releases or spills of drilling mud, and flowback, produced water, or hydraulic fracturing fluid released or spilled during storage. In contrast to the effects they may cause downhole, chemical additives pose quite a higher risk in their concentrated form while being transported or stored on site than when injected into the subsurface during hydraulic fracturing. Common sources of spills at the pad site include the drill rig itself from possible mechanical failure and other operating equipment, storage tanks, pits, and even leaks or blowouts at the wellhead. Leaks or spills may also occur during transportation (by truck or pipeline) of materials and wastes to and from the well pad. As in most all of these cases, surfaces water and groundwater are the primary risk receptors. Root causes of on-site and off-site releases can be accidents, inadequate facilities management or staff training, or even illicit/illegal dumping. In the event of spills, effective containment is a major factor in minimizing the impacts on human health and the environment when a spill occurs. Containments, including berms around tank batteries, double walls in tanks and vessels, and catch pans and basins for smaller storage containers, are the first line of defense against migration into exposure pathways that are linked through surface water or groundwater to humans, animals, or other receptors.

11.12 Spill Preparation and Documentation As will be discussed later in this section, the Clean Water Act addresses spills and other accidental releases. A main component of spill prevention is the Spill Prevention Control and Countermeasures (SPCC) plan prepared

Common Objections to Drilling Operations 73 to assure that adequate responses, materials, and personnel are available to respond to releases. Most states require an SPCC plan or equivalent for oil and gas operations as well as a statewide plan for response to spills and other releases. SPCC plans include prevention and control measures along with contact information, site-specific maps and details, reporting and cleanup requirements, and specifications for proper materials handling.

11.13

Other Surface Impacts

Drilling operations require significant above-ground development. In addition to possible spill scenarios related to the well pad itself, other possible surface impact scenarios are also quite common. Lease roads may need to be built and gathering infrastructure installed to bring the product from the wellhead to a delivery point or a pipeline. The pipeline itself, including installation and the remaining easement, may require the development of several acres of land. Total land use and resulting impacts to the environment can be reduced by drilling multiple wells from a single well pad, which ironically is a very common practice on horizontal hydraulic fracturing well pads. Nonetheless, with so many wells being drilled and the related infrastructure development, it is imperative that industry and regulatory bodies do as much as possible to minimize the overall impact on local communities, habitats, and road systems.

11.14 Land Use Permitting Land use decisions affect a wide range of stakeholders, including landowners, adjacent neighbors, surrounding communities, and community leaders. Permitting procedures will need to consider the needs of each of these stakeholders and include concise and enforceable preventative and remediation strategies to help provide minimal impact and maximum restoration of the land associated with well pads and production. Proper oversight also needs to be provided to help manage soil erosion and transport of sediment into streams and other water bodies, prevent damage to ecological habitats, and avoid fragmentation of habitats. During the construction phase for a well pad or infrastructures, the quality of surface water resources may be impacted by runoff, particularly during storm events. Shale gas development will also affect forests and ecological habitat on a large scale. Development studies indicate that many

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well pads are constructed in forest clearings, resulting in the clearing of thousands of acres of habitat from pads and associated road infrastructure.

11.15 Water Usage and Management Flowback water is the portion of injected fluid that returns to the wellbore after the downhole hydraulic fracturing process is completed, and the fluid pressure is relieved. Flowback water is then brought back to the surface for treatment, recycling, and/or disposal. The initial fluid withdrawn from the wellbore actually consists of a mixture of the flowback water and saline water from the formation wellbore, referred to as “produced” water. There is much concern over the use of water for fracking. Consider the following table: The source for the above table is the Chesapeake Energy 2009 presentation to the Ground Water Protection Council, citing Chesapeake well estimates for shale gas and a U.S. Department of Energy water use report: Chesapeake gave the authors its sources on these facts. Coal plant water consumption: “Energy Demands on Water Resources,” U.S. Department of Energy, December 2006, http://www.sandia.gov/energy-water/docs/121-RptToCongress-EWwEIAcomments-FINAL.pdf. NYC water consumption: New York City Department of Environmental Protection. Golf course consumption: Colorado State University Agricultural and Resource Policy Report, April 2004. Chesapeake says that the water it uses to frack an average shale well is the same amount consumed by a coal-fired power plant in 12 hours. It is what New York City consumes in seven minutes. Even recreation compares unfavorably: a golf course drinks the same amount in 25 days and then drinks that same amount every month, year after year.

11.16 Flowback Water Flowback water contains some or all of the following: sand and silt particles (from the shale or returned proppants), clay particles that remain in suspension, oil and grease from drilling operations, organic compounds from the hydraulic fracturing fluids and the producing shale, and total dissolved solids from the shale. The amount of injected fluid returned as flowback ranges widely – from 20% to 80% – due to factors that are not well understood. The flowback period can range anywhere from hours to weeks: as continued withdrawal proceeds, the flowback water becomes more saline as the relative amount of produced water increases.

Common Objections to Drilling Operations 75 Table 11.1 Water use comparison. Energy resource Shale Natural Gas

Range of gallons water used per MMBTU of energy produced 0.60 – 1.80

Natural Gas

1 to 3

Coal (no slurry transport)

2 to 8

Coal (with slurry transport)

13–32

Nuclear (processed uranium ready to use in plant)

8 to 14

Conventional Oil

8 to 20

Synfuel-Coal Gasification

11 to 26

Oil Shale Petroleum

22 to 56

Tar Sands Petroleum

27 to 68

Synfuel-Fischer Tropsch (Coal)

41 to 60

Enhanced Oil Recovery (EOR)

21 to 2,500

Fuel Ethanol (from irrigated corn)

2,510 to 29,100

Biodiesel (from irrigated soy)

14,000 to 75,000

Proper management of the flowback and produced water streams has been a major issue of the hydraulic fracturing controversy. Issues arise from the spills, both on location as well as during transport of these water sources to the proper disposal. Disposal of flowback water has historically been by permitted injection wells in some areas and by discharge to publicly-owned treatment works in others. However, discharge to publicly-owned treatment works, which is necessitated by less desirable subsurface conditions for underground injection wells in eastern states, has become controversial and has been prohibited by some states, while other states require pretreatment before discharge to a publicly-owned treatment works.

11.17

Produced Water

Produced water is generally a term used in the oil industry for water that is produced and returned to the surface along with the oil and gas. Produced

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water originates as a natural water layer that lies under the hydrocarbons in oil and gas reservoirs. Produced water is typically found in greater amounts in oil reserves than gas reserves.

11.18 Flowback and Produced Water Management One of the major problems concerned with handling flowback water and produced water is the relatively large amount temporary storage followed by transport of fluids prior to treatment or disposal. Flowback water and produced water is commonly stored on a temporary basis in on-site pits or tanks before transport removal by truck or pipeline for reuse, treatment, or disposal. These pits or tanks are another possible source of leaks or spills. Lining of pits, or lack thereof, for flowback water and produced water depends on company policies and regulatory requirements, which vary from state to state. Even in cases where liners are used, they may leak either from age and wear from use or even by improper installation and upkeep. These leaks result in releases to the subsurface, and have led many to question the use of pits in favor of closed-loop steel tanks and piping systems. Storing flowback water and produced water in enclosed steel tanks, a process many companies have already adopted, has led to a reduction in the risk of releases while improving water retention for subsequent reuse. The following chart is a breakdown of the various substances found in the produced water.

11.19

Geological Shifts

Contrary to popular belief, seismic events have been extremely common throughout our nation’s history, and with improving technology and detection methods, the United States Geological Survey has compiled data showing that the number of damaging earthquakes has remained constant. Also, their data indicate that there appears to be no direct connection between hydraulic fracturing and damaging earthquakes. However, fracturing into a moderate size fault may produce seismic energy sufficient to create measurable signals at instruments very close to the frack. Data has shown that the hydraulic fracturing process, while not necessarily creating damaging earthquakes, does create a large number of

Common Objections to Drilling Operations 77 micro-seismic events, or micro-earthquakes. The magnitudes of these micro-seismic events are generally too small to be detected at the surface. The biggest micro-earthquakes have a magnitude of about 1.6: an event of this size represents the slip of about the thickness of a human hair or about as much energy as is released by a gallon of milk dropped from chest height to the floor.

11.20 Induced Seismic Event Scientists have known for some time that pumping fluids in or out of the earth’s subsurface has the potential to cause seismic events. These seismic events, when attributable to human activities, are called “induced seismic events.” Data collected from research at several energy development sites has illustrated factors that induce seismicity, including: The presence, orientation, and physical properties of nearby faults The volumes, rates, pressures, and temperatures of fluids being injected or withdrawn The subsurface properties in the location

Produced water

Heavy metals

Salt content

Chemical additives

Radioactive materials

Total oil

Other compounds

Mostly sodium chloride

Dispersed

Dissolved

Aromatics

Acid

Phenols

BTEX

Fatty acids

PAHs

Naphthenic

Chart 11.1 Water and Contaminates.

Aromatics

Acid

Mainly PAHs

Aliphatics

Fatty acids

Naphthenic

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11.21 Wastewater Disposal Wells Tens of thousands of injection wells have been drilled and operate in production areas to dispose of the flowback water and produced water generated by oil and gas production operations. This flowback and produced water injection for disposal has also been suspected and, in some cases, determined a likely cause for induced seismicity in the past several decades. Unlike production wells, those used only for flowback and produced water disposal normally do not undergo detailed geologic review prior to construction.

11.22

Site Remediation

The requirements for the removal, known as plugging and abandoning, of production wells at the end of their life cycle is determined by state agencies. States also have oversight for specifying site restoration requirements. The common objective in site restoration for drill pads and other infrastructure requirements is to restore the site to its former conditions and use. Prior to release of the location for other uses, operators are required to test for contamination, clean up all apparatus and restore the location to prior drainage patterns, and reinvigorate the site within a reasonable time.

11.23

Regulatory Oversight

The different processes of shale gas development are regulated at almost all levels of government. However, the principal regulatory authority generally lies within each state. Not only is primary regulatory authority at the state level, many federal requirements have also been delegated to the state level. State agencies typically administer the federal environmental regulations and also are tasked with writing and enforcing their own regulations, governing nearly all phases of oil and gas operations. In addition to problems encountered through differing states managing production facilities by differing regulations, most oil and gas regulations were written before hydraulic fracturing became the industry that it is today; therefore, it is subject to oil and gas regulations enacted prior to its development and in many cases not adequately addressing fracturing processes. In general, too few regulations are currently directed specifically to hydraulic fracturing: many applied regulations are directed to broader environmental laws for air, water, waste, and land development. However,

Common Objections to Drilling Operations 79 state and federal regulations are currently being developed and and/or revised to focus on: Proper cementing and casing of wells Disclosure of hydraulic fracturing chemicals Proper management and disposal of flowback water and produced water In addition to having concise and relevant regulations, it is also very important to have adequate enforcement of regulations both by office and field staff conducting field inspections. This includes having an adequate number of staff assigned, conducting inspections, and ensuring violations are recorded. The type and severity of violations demonstrate the type of adverse effects being addressed by the regulatory programs. To be truly effective, regulations should focus on the most urgent issues, such as spill prevention, which may pose a greater risk of interacting with receptors than hydraulic fracturing itself. Most recorded violations are associated with overall gas drilling operations rather than being specific to hydraulic fracturing processes: surface spills, improper disposal of oil and gas wastes, problems with leaking pits or tanks, and administrative issues are typically the most common violations.

11.24 Federal Level Oversight Hydraulic fracturing is subject to many federal regulations (as is the case for other oil and gas operations), but also receives a great number of exemptions that normally would have been applicable. This is partly to do with “process knowledge” associated with the industry, which means if processes are continuously conducted by the same protocols, then the same results with wastes and regulations; therefore, it can self-regulate. This is meant as a time- and resource-saving area for regulatory agencies as much as anything else. This has also led to cooperative efforts between regulatory agencies and the industry to optimize the effectiveness of regulations. However, in some states, similar requirements that are exempted from federal regulation are imposed at the state level.

11.25 State Level Oversight As stated earlier, states have been delegated a great deal of oversight and management for hydraulic fracturing regulations and enforcement.

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However, with a great deal of regulations having been enacted prior to hydraulic fracturing becoming the topic it is today (particularly in states not having previous extensive oil and gas development), new or additional industry-specific regulations, such as chemical management requirements, may be needed to minimize surface and subsurface disturbances and impacts on environmentally sensitive areas. To help alleviate this, a number of organizations and activities are underway, including the Groundwater Protection Council (GWPC) and State Review of Oil and Natural Gas Environmental Regulations (STRONGER), to research and develop state regulation of oil and gas operations.

11.26 Municipal Level Oversight Municipal oversight is provided for mostly secondary processes related to oil and gas developments that are not regulated by state and/or federal entities: these include traffic management, road maintenance and repair, and usage and bridge zoning.

11.27 Examples of Legislation and Regulations The following laws and regulations are associated with varying phases and protocols of shale gas development: Clean Water Act (CWA): Oil and gas operators must obtain a storm water permit under the Clean Water Act for the construction and operation of a well pad and access road that is one acre or greater. Also, the Clean Water Act prohibits the dumping of any pollutant into U.S. waters without a permit. Typically, facilities that may generate storm water runoff must obtain a storm water permit for this runoff. However, the Clean Water Act does not require oil and gas operators to obtain a permit for uncontaminated “discharges of storm water runoff from . . . oil and gas exploration, production, processing, or treatment operations.” Clean Air Act (CAA): Recently-proposed Clean Air Act regulations are intended for operators to control volatile organic compound emissions from flowback during the fracturing process by using volatile organic compound capture techniques called “green completion.”

Common Objections to Drilling Operations 81 Endangered Species Act (ESA): Operators must consult with the Fish and Wildlife Service and potentially obtain an incidental “take” permit if their operations may affect endangered or threatened species by well development. Migratory Bird Treaty Act (MBTA): Operators are held strictly liable for any harm to migratory birds, and must ensure that maintenance of surface pits or use of rigs does not attract and harm these birds. Emergency Planning and Community Right-to-Know Act (EPCRA) and Occupational Safety and Health Act (OSHA): Operators must meet safety requirements in a myriad of work processes such as working at heights, tank entry, excavation, medical surveillance, first aid, and chemical storage. Operators must also maintain material safety data sheets for certain hazardous chemicals that are stored on site in threshold quantities. Comprehensive Environmental Responsibility, Compensation, and Liability Act (CERCLA): Operators must report releases of hazardous chemicals of threshold quantities and may potentially be liable for cleaning up spills. Resource Conservation and Recovery Act (RCRA): Most wastes from hydraulic fracturing and drilling are exempt from the hazardous waste disposal restrictions, meaning that states – not the federal government – have responsibility for disposal procedures for the waste. Safe Drinking Water Act (SDWA): Hydraulic fracturing operators also are exempt from the Safe Drinking Water Act, which requires that entities that inject substances underground prevent underground water pollution. The SDWA applies only to waste from fracturing and drilling that is disposed of in underground injection control wells. If operators use diesel fuel in fracturing, however, they are not exempt from SDWA.

11.28 Frack Fluid Makeup Reporting Of all the issues related to hydraulic fracturing, the issue of frack fluid makeup reporting may be the one that generates the most attention from state legislators and the concerned public. As discussed in earlier in this section, an overriding reason for this level of concern is greatly related to

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semantics and the inexplicable refusal of many companies to openly disclose frack fluid makeup sooner and with more sincerity. The detailed composition of the additives has been controversial because, until recently, companies that manufacture fracturing fluid components have insisted the exact composition was proprietary, and some components should therefore not be reported. Over the last few years, however, a greater number of voluntary disclosures and state-based disclosure laws have resulted in increased disclosure in the details of frack fluid composition. In spite of a great deal of positive ground made in the pursuit of full disclosure of frack fluid ingredients, there is not yet a clear understanding of what the full list of chemicals or their impact on the environment might be. In a helpful compromise between industry and the concerned public, recently enacted frack fluid make-up reporting regulations have stipulations that not only address the disclosure of chemicals used, but also provide some level of protection for proprietary trade secrets. The energy industry as a whole has supported this approach (see e.g., www.Fracfocus. org) and generally agrees the disclosure of the chemicals used in frack fluid makeup is appropriate and necessary; however, industry maintains that proprietary information should not be forced into publication. Continued movement toward detailed disclosure of chemicals present in hydraulic fracturing fluid will enable a continued analysis of the chemicals’ potential impact and will help address and alleviate public concern over their risk to water resources.

11.29

FracFocus

As stated on the website, FracFocus is a national hydraulic fracturing chemical registry managed by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission, two organizations whose missions both revolve around conservation and environmental protection. The site was created to provide the public access to reported chemicals used for hydraulic fracturing within their area. To help users put this information into perspective, the site also provides objective information on hydraulic fracturing, the chemicals used, the purposes they serve, and the means by which groundwater is protected. The stated primary purpose of FracFocus is to provide factual information concerning hydraulic fracturing and groundwater protection. It is not intended to argue either for or against the use of hydraulic fracturing as a technology. It is also not intended to provide a scientific analysis of risk

Common Objections to Drilling Operations 83 associated with hydraulic fracturing. While FracFocus is not intended to replace or supplant any state governmental information systems, it is being used by a number of states as a means of official state chemical disclosure. Currently, eight states, Colorado, Oklahoma, Louisiana, Texas, North Dakota, Montana, Mississippi, and Pennsylvania, use FracFocus in this manner. 

11.30 Atmospheric Emissions Air emissions from shale gas operations occur at the drill site during drilling and fracturing and at ancillary off-site facilities such as pipelines and natural gas compressors. The on-site emissions include dust, diesel fumes, fine particulate matter (PM 2.5), and methane. Air emissions have become a major component of the shale gas controversies. A principal concern for shale gas emissions is related to the volatile organic carbon (VOC) compounds. Depending on the composition of the gas produced from the shale, VOCs are typically rich in the BTEX (benzene, toluene, ethylene, xylene) compounds. However, the role of VOCs as smog precursors – they combine with NOx in the presence of sunlight to form smog – is the main source of concern with these compounds. Ozone, a primary constituent of smog, and NOx are two of the five “criteria pollutants” of the Clean Air Act (CAA). The Fort Worth area in the Barnett shale play has been designated “non-attainment” for ozone under the CAA, which means that the established standard is not met for ozone concentration in the atmosphere. The role of VOCs in forming smog and their contribution to the elevated levels of ozone is the reason for the focus on VOC emissions from shale gas activities. However, the contribution of shale gas activities to ozone levels is highly controversial. For example, investigations in the Fort Worth area have found that most VOCs are not associated with natural gas production or transport. Allegations that VOC and NOx emissions from natural gas production from Barnett shale activities play a significant role in ozone formation have been strongly contested. Records of the Texas Commission on Environmental Quality (TCEQ) monitoring program since 2000 actually show overall decreases in the annual average concentration of benzene, one of the VOCs, during the period of early shale gas development in the Fort Worth area. Public concern over air quality and the need for more precise information led to more focused emissions studies sponsored by local governments or private foundations. The first – and most controversial – of these studies

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was at DISH, Texas, where elevated levels of benzene, xylene, and naphthalene were found from a set of 24 samples and four residences. DISH was originally named Clark. In November 2005, the community accepted an offer to rename itself “DISH” (all capital letters) as part of a commercial agreement with a satellite television company. Another study in a very active area of shale gas production located about seven or eight miles from DISH found that shale gas was responsible for less than half of the VOCs (43%) in the atmosphere, with motor vehicle emissions contributing most of the rest (45%). Modeling studies indicate that 70 to 80% of benzene is from fugitive emissions of natural gas, but that other VOC constituents are from motor vehicle emissions. In portions of Western states such as Wyoming, air emissions from oil and gas activities are the largest source of VOCs and related high ozone levels. In Sublette County, Wyoming, for example, ozone levels in the winter routinely exceed the EPA 8-hour standard, resulting in air quality that is sometimes worse than in Los Angeles. Allegations that the emission of VOC constituents such as benzene in “widespread” or “prevalent” amounts in shale gas operations appear not to be supported when comparisons are made with air quality standards or when the relative amounts are compared to other sources such as vehicle exhausts. The relative contribution of shale gas activities in relation to conventional oil and gas development and other sources such as vehicle exhaust emissions must be taken into account in reports such as those from Wyoming and Fort Worth. Emissions of methane have caused public concerns over global climate change, since methane is a strong greenhouse gas. Venting or flaring of natural gas may take place during the fracturing and flowback phase of shale gas well development. However, many operators use “green completions” to capture and sell rather than vent or flare methane produced with flowback water. Onsite fugitive emissions of methane may take place from other sources as well, such as pressure relief valves of separators, condensate tanks, and produced water tanks. Although natural gas is confined in pipelines from production wells to the point of sale, methane emissions may also occur from offsite gas processing equipment and compressors notwithstanding the economic motive to minimize loss of natural gas. It is not known in the public realm the extent to which Best Management Practices, which is an industry term, (e.g., low-emissions completions, low-bleed valves) result in reduced methane and fugitive losses of methane.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

12 Air Emissions Controls

Shale gas development is subject to both federal and state air emissions regulations established by the Clean Air Act (CAA) and state-level legislation. Many of the CAA provisions are delegated from the U.S. EPA to the various states’ environmental agencies. The major air pollutant sources of shale gas drilling and fracturing are the drilling and associated equipment, tanks and pits for flowback water, flared gas, and methane sources at the wellhead and from pipelines and compressors. Oil, gas, and shale gas operations in particular are subject to regulations for “criteria pollutants” (sulfur dioxide, nitrogen oxides, ozone, particulate matter, carbon monoxide, and lead) and “hazardous air pollutants” (HAPs, including 187 compounds). However, these regulations focus on “major” sources, which generally do not include oil and gas operations for the sources listed above specifically. If regulated at all, oil and gas sources of criteria pollutants and HAPs fall under state minor source programs. The strictest criteria air pollutants regulations apply to areas not meeting established maximum ambient air standards, which are referred to as “nonattainment” areas. Air quality air regulations are, far and away, the most cumbersome regulations related to the oil and gas industry. Unfortunately, sitting in on an air regulation discussion will invariably result in the use of the phrase “it depends” being used more than in pretty much any other 85

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discussion one could possibly have. Most confusion related to air regulations stems from the way they are written: they can and often are based on any combination of equipment type, locations, date of manufacture, date of equipment order, date of reconstruction, whether the equipment is considered mobile or not, etc. These regulations are written such that one piece of equipment may be covered by several different regulations, to the point that even the regulatory employees are often as confused as industry personnel. A review of regulations brings to mind two things: the interaction between Peter Gibbons and “the Bobs” in the movie Office Space and the interaction between Abbot and Costello in the equally brilliant skit Who’s on First?

Peter Gibbons: And here’s something else, Bob…I have eight different bosses right now. Bob Slydell: I beg your pardon? Peter Gibbons: Eight bosses. Bob Slydell: Eight? Peter Gibbons: Eight, Bob. So that means that when I make a mistake, I have eight different people coming by to tell me about it. Office Space –written and directed by Mike Judge Abbott: Now, on the St. Louis team we have Who’s on first, What’s on second, I Don’t Know is on third-Costello: That’s what I want to find out. I want you to tell me the names of the fellows on the St. Louis team. Abbott: I’m telling you. Who’s on first, What’s on second, I Don’t Know is on third-Costello: You know the fellows’ names? Abbott: Yes. Costello: Well, then who’s playing first? Abbott: Yes. Costello: I mean the fellow’s name on first base. Abbott: Who. Costello: The fellow playin’ first base. Abbott: Who. Costello: The guy on first base. Abbott: Who is on first. Costello: Well, what are you askin’ me for? Abbott: I’m not asking you--I’m telling you. Who is on first. Costello: I’m asking you--who’s on first? Abbott: That’s the man’s name. Costello: That’s who’s name?

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Abbott: Yes. Who’s on First? – performed by Abbott and Costello Yes, the best way to describe air regulations is to imagine the unholy combination of the two discussions above. Some states cannot, it seems, even maintain constant definitions within their own regulations. For example, in Texas, something as mundane as the definition for “start of construction” varies with differing types of permits. In one type of permit, “start of construction” refers to the beginning of operations, while in others, “start of construction” is completely different, and refers to time before the start of construction of a tank battery. In an attempt to clear up some of the confusing points of air regulations, the following section is broken into discussions on some common sources and types of air emissions and an overview of a few of the common air regulations and permits related to the oil and gas industry.

12.1

Common Sources of Air Emissions

Air emissions can come from any number of sources, both related to and not related to the oil and gas industry. Non-industry examples are large sources such as refineries, factories, and power plants, smaller sources such as dry cleaners and gas stations, mobile sources such as cars, buses, planes, trucks, and trains, and naturally occurring sources such as natural windblown silt/ sand/dust, and even volcanic eruptions. All of these sources contribute to the overall breakdown of air quality. However, keeping in line with the overall context of this book, the discussion in this section will be concentrated on air emissions and regulations related to the oil and gas industry. Air emissions from shale gas operations can occur at the drill site during drilling and fracturing operations. Air emissions, including diesel fumes, fine particulate matter, and methane, also occur at off-site facilities such as pipelines, natural gas compressors, evaporation pits, and pig launch receiver/launchers. In addition to those emissions linked directly to oil and gas facilities, air emissions are also attributed to trucks used to transport equipment, fracturing fluid ingredients, and water to the wellpad, drilling rigs, compressors, tanks, and pumps. A principal concern for shale gas emissions is volatile organic compounds (VOC) such as propane, BTEX (benzene, toluene, ethylene, and xylene) constituents, and the six principal criteria pollutants classified by the EPA, nitrogen dioxide (NO2), ozone (O3), sulfur dioxide (SO2), particulate matter (PM), carbon monoxide (CO), and lead (Pb).

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12.2 Fugitive Air Emissions Fugitive air emissions are air emissions that escape from equipment through normal use, routine maintenance, or small leaks. This can be through equipment such as pumps, valves, flanges, compressors, and process drains. There are generally four categories of emissions: Normal operations: emissions during expected operating scenarios Planned maintenance, start-up and shut-down: emissions during normal operations that are expected and predictable Scheduled maintenance start-up and shut-down: unexpected emissions that are expected but not necessarily predictable Emission events: emission events that are not authorized, scheduled, or planned Three sources of emissions commonly related to fracking operations are flare emissions, liquid storage tank emissions, and loading/unloading emissions: Flare emissions: flare emissions result from the pilot light, combusted waste, and uncombusted waste (depending on flare efficiency). These can result in the release of NOx, CO, VOCs, SO2, H2S (in some areas), HAPs, CO2, and methane. Liquid storage tank emissions: liquid storage tank emissions are categorized as working, breathing, and flash emissions. These can result in the release of VOCs, HAPs, H2S (in some areas), CO2, and methane. Liquid storage tank emissions are most commonly controlled utilizing vapor-recovery units and condensers. Working emissions occur during tank filling and draining Breathing emissions result from normal daily fluctuations in temperature and pressure Flash emissions result from a high pressure stream being directed into an atmospheric tank. Loading/Unloading emissions: loading/unloading emissions result from hose disconnects when petroleum liquids are loaded into trucks, rail cars, tankers, or even ships, and can also occur when the vapor space in a tanker truck is displaced by fluids. These can also result in the release of VOCs, HAPs,

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H2S (in some areas), CO2, and methane, and are normally controlled utilizing vapor recovery units, incineration through flaring or thermal oxidizers, and carbon systems. In addition to emissions related directly to fracking operations, emissions related to the oil and gas industry also include fugitive emissions of methane from other sources as well, such as pressure relief valves of separators, condensate tanks, and produced water tanks. Controls to prevent and mitigate fugitive emissions are generally comprised of a leak detection and repair program (commonly referred to as LDAR) and maintenance. Emissions from gas production come from: Direct emissions (methane venting during frack cleanup, lost gas or fugitive emissions, and CO2 from fuel combustion) Indirect emissions from trucks (pumpers and processing equipment used in drilling, fracturing and production) Offsite gas processing equipment such as natural gas in pipelines and compressors from production wells to the point of sale

12.3 Silica Dust Exposure Silica dust is an emission source that is becoming more of a fracking industry concern. As discussed throughout this book, fracking commonly requires large volumes of sand and water to be pumped into wells at high pressures to break up tight formations, like shale, which have trapped oil and gas. Therefore, many truckloads of sand must be off loaded and transferred before being mixed with water and other chemicals and pumped downhole. The dust produced, which may contain up to 99% crystalline silica, is a health concern due to the risk of silicosis, a progressive and disabling lung disease.

12.4 Stationary Sources A “stationary source” is, as the name suggests, a non-mobile piece of equipment that emits an air pollutant. Some states have specified time periods, such as six months, that are also used to define a stationary source. While not specific to fracking operations, common stationary sources in the natural gas industry as a whole include compressor engines, turbines,

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generators, tanks, reboilers or associated equipment, boilers, vaporizers, flares, etc. Stationary sources may be subject to different requirements depending on the amount and type of air pollutant emitted and the quality of the air in the vicinity of the source.

12.5

The Clean Air Act

The Federal Clean Air Act (Clean Air Act) provides the principal framework for national, state, and local efforts to protect air quality. Under the Clean Air Act, the Office of Air Quality Planning and Standards Organization (OAQPS) is responsible for setting standards known as national ambient air quality standards (NAAQS), for pollutants that are considered harmful to people and the environment. As with other types of regulations, state and local agencies take the lead in carrying out the requirements of the Clean Air Act. Each state has to develop and implement plans that outline how to control air pollution as required by Clean Air Act. In doing this, state and local governments will need to conduct air monitoring, facility inspections, and conduct permit management and enforcement. Also, as with other types of regulations, individual states may have stronger air quality laws than the federal regulation, but they may not have weaker pollution limits than those set by the EPA. The Clean Air Act regulates many aspects of the construction and operation of oil and gas facilities, including compressors engines, flares, and other emission sources. Under the Clean Air Act, many stationary sources of air pollution cannot legally operate until an air permit is obtained and compliance requirements are in place and met. The Clean Air Act has several programs to protect public health and welfare and enhance the quality of the nation’s air resources, including New Source Performance Standards (NSPS – found in 40CFR Part 60), National Emission Standards for Hazardous Air Pollutants (NESHAP – found in 40CFR Part 63), NSR, and Prevention of Significant Deterioration (PSD). Depending on the level and source of emissions, various types of air permits may be required.

12.6 Regulated Pollutants Regulated pollutants that result from emissions at oil and gas locations are generally separated into two main categories:

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National Ambient Air Quality Standard (NAAQS) Criteria Pollutants: there are six NAAQS criteria pollutants that are generally regulated by county and pollutant National Emission Standards for Hazardous Air Pollutants (NESHAP): there are 187 HAPS that are regulated on a “source by source” basis, and are considered more difficult to monitor than criteria pollutants

12.7 NAAQS Criteria Pollutants As discussed earlier, there are six principal criteria pollutants classified by the EPA as criteria pollutants: nitrogen dioxide (NO2), ozone (O3), sulfur dioxide (SO2), particulate matter (PM), carbon monoxide (CO), and lead (Pb). Criteria pollutants are more of an “industry based regulation,” or in other words, government regulation of an industry as a whole. Criteria pollutants are also monitored on a “not to exceed” level by county and pollutant requiring regional attainment of established levels.

12.8 Attainment Versus Non-attainment “Attainment” and “non-attainment” are terms to describe the air quality in a given area (usually broken down by county) for any of the six established criteria pollutants. An area with levels below the established standards for all six criteria pollutant is referred to as an attainment area; a county that does not meet the standards, or is considered to contribute to elevated levels in nearby areas that do not meet the standards, is called a non-attainment area. Industry located in non-attainment areas are held to much more stringent air emission standards than those located in attainment areas. Since an area is compared to established levels for all six criteria pollutants, an area may be designated attainment for some pollutants and nonattainment for others. Once an area is determined to be non-attainment, it is then further broken into tiered levels of non-attainment: marginal, moderate, serious, severe, and extreme. This further classification is determined based on number of criteria pollutants exceeded and levels of exceedance. In addition to “attainment” and “non-attainment,” two more possible classifications for NAAQS criteria pollutants are “unclassified” and “maintenance.” Areas that move from non-attainment to attainment retain many of the more stringent rules of attainment areas and are referred to as maintenance areas and areas with insufficient air quality data for classification

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are referred to as unclassified areas and are treated the same as attainment areas.

12.9

Types of Federal Regulations

There are various types of Clean Air Act regulations and permits. Oil and gas operations, and shale gas in particular, are subject to numerous regulations such as those related to the six criteria pollutants and 187 hazardous air pollutants mentioned earlier. The following is a brief discussion of some of the most common types related to the oil and gas industry.

12.10

MACT/NESHAP HAPs

Unlike the relatively small number of criteria pollutants, there are 187 separate designated hazardous air pollutants – listed pollutants that increase mortality of serious, irreversible, or incapacitating illness. MACT/ NESHAP hazardous air pollutant regulations are “risk-based regulation” and are established on “source by source” criteria for each separate piece of equipment; for example, boiler MACT and reciprocating internal combustion engine MACT (NESHAP Quad ZZZZ). Also, since these are riskbased regulations of separate pieces of equipment, there are no established attainment designations of across the board acceptable levels.

12.11

NSPS Regulations: 40 CFR Part 60

In accordance with the Clean Air Act, reconstructed or modified sources are potentially subject to a New Source Performance Standard (NSPS), which is exactly what the name describes, standards set up to manage and determine possible new sources for emissions. If a facility is a new, reconstructed, or modified source, it could be considered a potentially affected source under the NSPS. NSPS standards are in place to create higher standards of performance and maintenance as new equipment is brought into service. New equipment is automatically covered by NSPS and additional sources are added as reconstructed or modified. A source is “reconstructed” if the components of an existing stationary source are replaced and/or repaired and the fixed capital costs exceed a specified percentage of the cost of constructing a comparable new source. The specified percentage is determined by the applicable air regulation.

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New-source performance standards may be applied to sources reconstructed after the proposal of the standard if it is technologically and economically feasible to meet the standards. A source is “modified” if any physical or operational change to an existing facility is made that results in an emission increase of any pollutant to which the standard applies, such as horsepower increase or engine conversion. Consequently, an existing facility containing an existing (older) emission unit, which might not be subject to the NSPS due to the age of the unit, could still become subject to regulation under NSPS if reconstructed or potentially modified.

12.12 NSPS Subpart OOOO NSPS Subpart OOOO (Quad OOOO) regulations, finalized by the EPA on August 16, 2012, centered on gas production, transmission and distribution, are generally considered the most concentrated on fracking operations. Therefore, this regulation will be discussed in greater detail than those regulations centered on oil and gas as a whole.

12.13 Facilities/Activities Affected by NSPS OOOO The following is a brief overview of activities/equipment requirements regulated under NSPS OOOO to reduce VOC emissions from sources constructed, reconstructed or modified after August 23, 2011: Natural gas well completions For natural gas wells that use hydraulic fracturing, new regulations require companies to control and reduce emissions during flowback. The goal of the new standard is to reduce VOC emissions generated during flowback activity. In the past, the general industry practice was to vent the gas generated during flowback. Starting October 15, 2012, these new standards require flowback emissions to be routed to a completion combustion device, usually a flare. After January 1, 2015, flowback will be required to implement “green completions” where flowback vapors will be routed to the gas gathering line. If this infeasible due to lack of infrastructure, vapors will be routed to completion combustion device (i.e.,

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Fracking 2nd Edition flare). The only exceptions to implementing this regulation are if the completion could potentially result in a fire hazard or explosion or if local ordinances restrict the use of flares, such as during a burn ban. Storage vessels EPA regulates storage vessels that handle crude oil, condensate, and produced water at production and gathering/booster stations to reduce emissions by 95%. Storage vessels with VOC emissions of greater than 6 tons per year (tpy) must install emission controls to reduce emissions to less than 6 tpy. Operators must demonstrate compliance by developing emission calculations and include them in annual reports submitted to EPA or the delegated state agency. A  storage vessel is exempt, however, if skid mounted (i.e., mobile) and is at the site less than 180 consecutive days. Pneumatic controllers Pneumatic controllers at processing plants and production facilities also have requirements under this new EPA regulation. At the gas processing plants, each continuous bleed natural gas driven pneumatic controller must operate at a zero bleed rate (i.e., instrument air) by October 15, 2012. At production facilities, each continuous bleed natural gas driven pneumatic controller must operate at a bleed rate of 6 standard cubic feet per hour (SCFH) or less. Intermittent bleed and no-bleed controllers are exempt from this regulation. The goal of this part of the regulation is to encourage controllers to use low bleed, intermittent-bleed or non-gasdriven devices in the future. Operators can claim exceptions if a high continuous bleed rate controller is required for functional needs, including but not limited to response time, safety, and positive actuation. Compressors The compliance date for both centrifugal and reciprocating compressors was October 15, 2012. For wet seal centrifugal compressors, the regulation stipulates that operators reduce emissions from each centrifugal compressor wet seal fluid degassing system by 95% through routing gas to controls. For reciprocating compressors, the new rule requires operators to replace rod packings before the compressor has operated 26,000 hours or prior to 36 months from last replacement or date of startup for the unit, whichever is later.

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12.14 Other Types of Federal NSPS and NESHAP/ MACT Regulations In addition to Quad OOOO, which directly relates to affects hydraulic fracturing operations, there are several regulations that affect the oil and gas industry as a whole. The following is a quick discussion of a few of the other regulations that affect industry.

12.15 NSPS Subpart IIII NSPS Subpart IIII (Quad IIII) establishes regulation of criteria pollutants from compressed ignition combustion engines. This regulation applies to engines operated by diesel or liquefied petroleum gas. It also regulates all sizes of internal combustion engines in emergency and non-emergency use.

12.16 NSPS Subpart JJJJ NSPS Subpart JJJJ (Quad JJJJ) establishes regulation of criteria pollutants for spark injection internal combustion engines. Quad JJJJ applies to manufacturers, owners, and operators of stationary spark ignition internal combustion engines based on the date the engine was constructed. Engines subject to this rule include natural gas engines and gasoline engines greater than 25hp, including those which are new, reconstructed, and modified.

12.17 NSPS Subpart KKK NSPS Subpart KKK (Triple K) establishes regulation for equipment at onshore natural gas processing plants constructed, reconstructed or modified after January 10, 1984 and on or before August 23, 2011. It includes equipment leaks from natural gas processing plants from compressors, pumps, open-ended valves, flanges, and connecters.

12.18 MACT Subpart HH and Subpart HHH MACT Subpart HH (Double H) establishes emission standards of HAPs related to dehydration units located at oil and natural gas production

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facilities, while MACT Subpart HHH (Triple H) establishes emission standards of HAPs related to dehydration units located at oil and natural gas transmission and storage facilities.

12.19 MACT Subpart ZZZZ MACT Subpart ZZZZ (Quad ZZZZ) sets national emission standards and operating limitations for HAP emissions from stationary reciprocating internal combustion and operating limitations for hazardous air pollutants from stationary engines (including compressor station engines) with greater than 500 horsepower put in place prior to June 12, 2006 (Quad JJJJ applies for engines put in place after June 12, 2006).

12.20 Construction and Operating New Source Review Permits In addition to federal air regulations, there are also several differing types of permits governing new source construction compliance which vary by state. These include construction permits, used to regulate construction and modification of sources and prevent significant deterioration affects to non-attainment areas, and operating permits, authorizing the operation of larger emission sources and to keep these sources more accountable to federal standards. Prevention of significant deterioration (PSD) is a construction air pollution permitting program designed to ensure that air quality does not degrade beyond the NAAQS levels. The PSD permit includes a requirement to comply with ambient air quality levels and to install “best available control technology” (BACT) for criteria pollutants emitted in significant levels.

12.21 Title V Permits Title V permits are operating permits that grant larger air emission sources the permission to operate. Title V permits include all air standards and requirements that apply to that source, including emissions limits, monitoring protocol, and record keeping requirements. This permit is used to identify all of the applicable air quality requirements for a site. It also requires that the site demonstrate compliance with the

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requirements on an ongoing basis, often semi-annually. The main purpose of a Title V permit is intended to be a single point of reference for all regulations at the permitted location. However, along with the intended gathering of all the regulations in one document, Title V permits also include a great deal of additional administrative protocols that more than negate any intended ease of review the document may provide.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

13 Chemicals and Products on Locations

A common point of contention for residents in oil producing areas is onsite storage of chemicals and products. For decades, one of the biggest drivers for public concern has been the identity and amounts of chemicals stored on pad locations during all phases of the well completion and production process. This can include fuels used on location, the makeup of drilling fluids (water-based, oil-based or synthetic), fracking chemicals and additives stored on locations, chemicals kept on site during ongoing production, and even the products – produced water and/or oil – stored on site as recovered from the well during operations. People safely use chemicals everyday: dish soap, gasoline, motor oil, bleach, hydrogen peroxide, and vinegar are some examples. The same chemicals are frequently used in workplaces, but are often in a higher concentration and volume, which could pose a higher risk for individuals. As an example, 3% hydrogen peroxide is used to clean skin abrasions or as a mouthwash at home, and some folks use concentrations as high as 35% for treating swimming pool water. Companies produce and distribute products with concentrations of hydrogen peroxide at levels between 3% and 35%, so one must be able to 99

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recognize which products are generally safe and which products require precautions to be handled and used safely. The important information to take away from this section includes: How to recognize that a chemical product may present a hazard Know where to get information that explains the hazards Know who to ask for help and assistance at any time Understand what GHS means and the reason for its implementation Understand the difference between GHS and HCS 2012 It is also important that one is able to recognize the changes to hazard communication in the U.S. The most important among these are: Label information and changes Safety data sheet information and format The difference between the numerical rating systems Chemical hazards and classification Chemical Labels Safety Data Sheets (Formerly known as Material Safety Data Sheets) Detection of and protection from hazardous chemical exposure Many people in the chemical industry, as well as those directly or even indirectly related to the industry, should understand what Hazard Communication is. What is Hazard Communication? OSHA’s Hazard Communication standard is published in the Code of Federal Regulations at 29 CFR 1910.1200. The standard was first published in 1983. The standard has been revised since then, with the most recent and sweeping changes made in March 2012 to conform to the United Nations Globally Harmonized System of Classification and Labeling of Chemicals (or GHS). Hazard Communication is designed to ensure that employers and employees are equipped with proper information to facilitate safe storage and handling of chemicals. The general public would be pretty surprised at how little chemical and products are stored on site during construction, drilling, and frack operations. For the most part, oilfield operations have become such a streamlined and efficient operation that operators will know how much of a given chemical product will be necessary and, for the most part, make all

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attempts to have the chemicals arrive on location as close to when needed as possible to avoid storage. This process is beneficial to the operator in that it cuts down on the time taken up by storing chemicals only to return for them when needed, cuts down on waste from unused or outdated chemicals, cuts down on equipment needed to maneuver chemicals if they are delivered directly to point of need, allows for more working space on the pad, and also helps avoid a great deal of logistical problems related to maneuvering equipment around storage areas. Once production operations are in place and wells begin producing the fluids – produced water and oil – are often stored on site in large tanks while awaiting transport off-site. Safeguards put in place to protect the environment and public from tank releases include consistent measurements by pumpers, high level shut down sensors, continued equipment observations and maintenance, and secondary containments in place around the tanks to contain any fluids that may release from tank. Secondary containments may be constructed of properly packed and integrity-tested earthen materials or up to specifically designed and manufactured metal containments with plastic liners. No matter the materials used in construction, secondary containments must be sufficiently large enough to contain all the fluids that could possibly escape the tanks plus sufficient extra space for “waste case scenario” rainfall. This amount is calculated for each region of the country based on historic rainfall amounts. Even with attempts to minimize the amount of on-site storage, some chemical and product storage is unavoidable, and there are very valid concerns, including potential spills, leaks, tank or container overfill, and even the chance of traffic accidents on location or roadways leading to releases of chemicals and/or products. Release events could range from relatively small amounts from equipment leaks to possibly hundreds of barrels from tank release. Two regulatory measures in place to manage and oversee on-site chemical storage conditions are requiring Spill Prevention Countermeasure and Control (SPCC) plans and SARA reporting. SPCC plans are documents required by all facilities having the potential to discharge oil to navigable waters of the U.S. and meeting one or both of the following: greater than 1,320 gallons (31.4 brls) aggregate aboveground storage in equipment, drums, tanks, totes, tanks greater than 55 gallons in size, or greater than 42,000 gallons total underground storage capacity. Just to clarify, aggregate refers to adding up separate amounts of all storage vessels. There can be one 1,320-gallon tank or ten 132-gallon tanks, and they would be equal under the SPCC requirements. Also, the “having potential to discharge oil to navigable waters of the U.S.” is left up to regulatory discretion to calculate, and has come to include pretty much

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anywhere in the U.S. one could imagine. SPCC plans are, to keep it simple, engineer-stamped documents that must be created for all facilities meeting the above conditions that include a list of spill response procedures, an emergency notification phone list, inspection procedures and schedule, training requirements, site figures, site chemical and product storage vessel types and sizes, and containment calculations to prove sufficient containment is given to contain the largest possible spill amount. SARA reporting, or possibly better known as the federal “right to know,” requires quarterly and annual reporting of chemical storage details (types of chemicals, amounts, and dates of storage) for all facilities that used more than 10,000 pounds per year of the chemical exceeding the threshold quantity. This requirement means a facility storing more uses more than 10,000 pounds of a given chemical in a year must report that chemical and amount. This program is intended as the “right to know” for emergency responders and emergency services that may respond to an emergency situation on the location so they will be able to adequately prepare for what may be stored on site. The drawback of this program as related to the oil and gas industry is that, with quarterly reporting, by the time a chemical has been reported, the oilfield function requiring the chemical has normally been long complete and the chemicals are no longer on site. This basically means that once the chemical is reported as being on a location, it is no longer there; however, as previously stated, oilfield operations have become such a streamlined process that if one knows what has been reported for a previous location by a specified operator one can, for the most part, expect much the same chemicals and products stored at following locations. If one is really curious about all the chemicals used at a site, ask to receive a copy of the Material Safety Data Sheet of the chemicals used.

13.1

Material Safety Data Sheets (MSDS)

Any time a company produces for sale or uses a chemical, a Material Safety Data Sheet (MSDS) has to be written on the product and on file when used. Occupational Safety and Health Administration (OSHA) estimates that there are over 650,000 hazardous chemicals used daily in the United States, and that hundreds more will be added this year alone. To address the physical and health hazards of these chemicals, OSHA finalized the Hazard Communication Standard (HCS) on November 25, 1983. The purpose of the HCS is to “ensure that the hazards of all chemicals produced or imported are evaluated, and that information concerning their hazards is transmitted to employers and employees.” (29 CFR 1910.1200(a)(1))

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Employers are under obligation to use labels, MSDS, and other information to evaluate both the physical and health hazards created by the use of chemicals in their workplace, establish a program that addresses these hazards, and train workers to minimize their exposure. According to an OSHA Executive Summary: “Chemical information is the foundation of workplace chemical safety programs. Without it, sound management of chemicals cannot occur. The HCS has made provision of hazard information about chemical products an accepted business practice in the United States. There is now a whole generation of employers and employees who have never worked in a situation where information about the chemicals in their workplace is not available.” Manufacturers or importers of chemicals must create or obtain a MSDS for every hazardous chemical that they produce or import (29 CFR 1910.1200(g)), and supply the appropriate one with a customer’s first purchase, and any time the MSDS changes (29 CFR 1910.1200(g)(6)(i)). Employers are not required to evaluate information on a MSDS (29 CFR 1910.1200(d)(1)). They do, however, have a duty to study and to use it to “develop, implement and maintain... a written hazard communication program” to ensure the safety of their workers (29 CFR 1910.1200(e)(1)). To help address worker safety “at all times,” OSHA requires employers to make MSDS “readily accessible during each work shift to employees when they are in their work area(s)” (29 CFR 1910.1200(g)(8)). OSHA permits electronic and other forms of access to MSDS, as long as there are “no barriers to immediate employee access in each workplace” (29 CFR 1910.1200(g)(8)).

13.2 Contents of an MSDS Frack site workers, as well as anyone working in an industry or market that uses chemicals, will have access to an MSDS for any chemical with which they may have contact. Interestingly enough, consumer products also have MSDSs. In fact, the local hardware store has a complete file of MSDSs for all the consumer chemicals they sell, and many department stores do as well. If the reader ever wants to know the dangerous effects of a particular insecticide or cleaner, he can refer to the MSDS for detailed information. Beware though; the information contained within an MSDS can be a bit foreboding. Like pharmaceuticals and over-the-counter medications, the warnings typically are meant to take into consideration any and all dangers that may happen upon exposure. Without a working knowledge of the terms and criteria put forth in the MSDS, the layperson could quickly become horrified with the prospect of using a product only to experience

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dizziness, dry mouth, or shortness of breath (which seems to be the universal response to everything from aspirin to Zoloft®). The following is an explanation that is provided to help interpret the information found on manufacturers’ MSDSs. While the format of these data sheets varies from manufacturer to manufacturer, certain components appear on each sheet.

13.3 Product Identification This section gives the name and address of the manufacturer and an emergency phone number where questions about toxicity and chemical hazards can be directed. Product Name: Commercial or marketing name. Synonym: Approved chemical name and/or synonyms. Chemical Family: Group of chemicals with related physical and chemical properties. Formula: Chemical formula, if applicable; i.e., the conventional scientific definition for a material. CAS Number: Number assigned to chemicals or materials by the Chemical Abstracts Service.

13.4 Hazardous Ingredients of Mixtures This section describes the percent composition of the substance, listing chemicals present in the mixture. If it was tested as a mixture, it lists chemicals which contribute to its hazardous nature. Otherwise, it lists ingredients making up more than 1% and all carcinogens. The OSHA permissible exposure limit (PEL), National Institute for Occupational Safety and Health (NIOSH) recommended exposure limit (REL), and/or the American Conference of Governmental Industrial Hygienists (ACGIH) threshold limit value (TLV) will also be listed, if appropriate. The OSHA PEL is the regulated standard, while the others are recommended limits. The PEL is usually expressed in parts per million parts of air (ppm) or milligrams of dust or vapor per cubic meter of air (mg/m3). It is usually a time weighted average (TWA), concentration averaged over an eight-hour day. Sometimes, a STEL or short term exposure limit may be listed. The STEL is a 15-minute TWA that should not be exceeded. A ceiling limit, (c), is a concentration that may not be exceeded at any time.

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A skin notation means that skin exposure is significant in contributing to the overall exposure.

13.5 Physical Data This section outlines the physical properties of the material. The information may be used to determine conditions for exposure. For example, one can determine whether or not a chemical will form a vapor (vapor pressure), whether this vapor will rise or fall (vapor density), and what the vapor should smell like (appearance and odor). This could help determine whether to use a fume hood or where to place ventilators. The following information is usually included: Boiling Point: temperature at which liquid changes to vapor state Melting Point: temperature at which a solid begins to change to liquid Vapor Pressure: a measure of how volatile a substance is and how quickly it evaporates. For comparison, the VP of water (at 20o C) is 17.5 mm Hg, Vaseline (non-volatile) is close to 0 mm Hg, and diethyl ether (very volatile) is 440 mm Hg. Vapor Density (air=1): weight of a gas or vapor compared to weight of an equal volume of air. Density greater than 1 indicates it is heavier than air, while less than 1 indicates it is lighter than air. Vapors heavier than air can flow along just above ground, where they may pose a fire or explosion hazard. Specific Gravity (water=1): ratio of volume weight of material to equal volume weight of water. Solubility in Water: percentage of material that will dissolve in water, usually at ambient temperature. Since the much of the human body is made of water, water soluble substances more readily absorb and distribute. Appearance/Odor: color, physical state at room temperature, size of particles, consistency, and odor, as compared to common substances. Odor threshold refers to the concentration required in the air before vapors are detected or recognized. % Volatile by Volume: Percentage of a liquid or solid, by volume, that evaporates at a temperature of 70°F.

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Fracking 2nd Edition Evaporation Rate: usually expressed as a time ratio with ethyl ether = 1, unless otherwise specified. Viscosity: internal resistance to flow exhibited by a fluid, normally measured in centistokes time or Saybolt Universal Secs. Other Pertinent Physical Data: information such as freezing point is given, as appropriate.

13.6 Fire and Explosion Hazard Data This section includes information regarding the flammability of the material and information for fighting fires involving the material. Flashpoint: the lowest temperature at which a liquid gives off enough vapor to ignite when a source of ignition is present. Auto-ignition Temperature: the approximate temperature at which a flammable gas-air mixture will ignite without spark or flame. Vapors and gases will spontaneously ignite at lower temperatures in oxygen than in air. Flammable Limits: the lower explosive limit (LEL) and upper explosive limit (UEL) define the range of concentration of a gas or vapor in air at which combustion can occur. For instance, an automobile carburetor controls this mixture: too lean (not enough chemical) or too rich (not enough air, as when you flood your engine), and it will not ignite. Extinguishing Media: appropriate extinguishing agent(s) for the material. Fire-fighting Procedures: Appropriate equipment and methods are indicated for limiting hazards encountered in fire situations. Fire or Explosion Hazards: Hazards and/or conditions that may cause fire or explosions are defined.

13.7

Health Hazard Data

This section defines the medical signs and symptoms that may be encountered with normal exposure or overexposure to this material or its components. Information on the toxicity of the substance may also be presented. Results of animal studies are most often given, i.e., LD50 (mouse) = 250

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mg/kg. The terms are usually expressed in weight of chemical per kg of body weight. LD50 or lethal dose 50 is the dose of a substance that will cause the death of half of the experimental animals. LC50 is the concentration of the substance in air that will cause the death of half of the experimental animals. Health hazard information may also distinguish the effects of acute (short-term) and chronic (long-term) exposure.

13.8 Emergency and First Aid Procedures Based on the toxicity of the product, degree of exposure, and route of contact (eye, skin, inhalation, ingestion, injection), emergency and first aid procedures are recommended in this section. Additional cautionary statements, i.e., note to physician, for first aid procedures, when necessary, will also appear here.

13.9

Reactivity Data

This section includes information regarding the stability of the material and any special storage or use considerations. Stability: “unstable” indicates that a chemical may decompose spontaneously under normal temperatures, pressures, and mechanical shocks. Rapid decomposition produces heat and may cause fire or explosion. Conditions to avoid are listed in this section. Incompatibility: certain chemicals, when mixed, may create hazardous conditions. Incompatible chemicals should not be stored together. Hazardous Decomposition Products: chemical substances that may be created when the chemical decomposes or burns. Hazardous Polymerization: rapid polymerization may produce enough heat to cause containers to explode. Conditions to avoid are listed in this section.

13.10

Spill, Leak, and Disposal Procedures

This section outlines general procedures, precautions, and methods for cleanup of spills. Appropriate waste disposal methods are provided for safety and environmental protection.

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13.11 Personal Protection Information This section includes general information about appropriate personal protective equipment for handling this material. Many times, this section of the MSDS is written for large-scale use of the material. Appropriate personal protection may be determined by considering the amount of the material being used and the actual manipulations to be performed. Eye Protection: recommendations are dependent upon the irritancy, corrosiveness, and special handling procedures. Skin Protection: describes the particular types of protective garments and appropriate glove materials to provide personnel protection. Respiratory Protection: appropriate respirators for conditions exceeding the recommended occupational exposure limits. Ventilation: air flow schemes (general, local) are listed to limit hazards. Another important term used recently is GHS. What is GHS? GHS stands for Globally Harmonized System of Classification and Labeling of Chemicals. GHS was conceived in 1992 and adopted by the United Nations Economic Commission for Europe (UNECE) in 2002. GHS is a harmonized classification system for chemical substances and mixtures according to their health, environmental, and physical hazards. The stakeholders for GHS information include workers, employers, consumers, transport workers, and emergency responders. Currently, the regulatory schemes for hazard communication vary between countries and even between agencies in the same country. Because these different systems use different wording, classifications, symbols, shapes, colors, etc., there are many opportunities that can, and do, lead to confusion and even trade barriers. GHS is an attempt to reduce the differences, especially those between countries, so information on the hazards of chemicals is transmitted more efficiently. Hazard Communication Standard 2012 (or HCS 2012) is OSHA’s revised Hazard Communications standard. OSHA published the final rule for the modified HazCom standard on March 26th, 2012. It went into effect on May 25th, 2012 with a multi-year phase-in schedule. This modification is intended to conform the standard’s requirements with the standard language and methodologies established by the GHS. The major modifications to the Hazard Communication standard include the following:

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Revised criteria for classification of chemical hazards Revised labeling provisions that include requirements for use Standardized signal words, pictograms, hazard statements, and precautionary statements A specified format for safety data sheets Related revisions to definitions of terms used in the standard, and requirements for employee training on labels and safety data sheets. By June 1, 2015, chemical manufacturers and importers must comply with all the requirements of the new rule. By December 1, 2015, chemical distributors must include compliant labels on all shipments of chemical containers. By June 1, 2016, all employers that use, handle, or store chemicals must update their workplace hazard communication program as necessary, and provide additional employee training for newly identified physical or health hazards. The revised hazard communications standard (HCS 2012) requires chemical manufacturers and importers to classify their chemicals according to the hazards laid out in the standard. This is a change from the hazard determinations/evaluations performed under the previous HazCom standard. First, a chemical is hazardous if it can be classified as a Physical hazard A health hazard An environmental hazard, or simple asphyxiant Combustible dust Pyrophoric gas Or hazard not otherwise classified (HNOC) A hazard class is a subset of a chemical hazard. Hazard class is the nature of the physical or health hazards. For example: a flammable solid is a class of physical hazard. A hazard category is a subcategory of a hazard class. Each hazard class has 1 to 4 categories to denote the division of severity within each hazard class. For example: oral acute toxicity is broken up into 4 different categories, with 1 being the most hazardous, and 4 being the least hazardous. Hazard categories compare hazard severity within a hazard class.

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A chemical is considered a physical hazard if it is classified as possessing one of the following hazards: Explosives: An explosive chemical is a solid or liquid chemical that is in itself capable by chemical reaction of producing gas at such a temperature and pressure and at such a speed as to cause damage to the surroundings. Pyrotechnic chemicals are included even when they do not evolve gases. Flammable gases: Flammable gas means a gas having a flammable range with air at 20°C (68°F) and a standard pressure of 101.3 kPa (14.7 psi). Flammable aerosols: Aerosol means any non-refillable receptacle containing a gas compressed, liquefied, or dissolved under pressure, and fitted with a release device allowing the contents to be ejected as particles in suspension in a gas, or as a foam, paste, powder, liquid, or gas. Oxidizing gases: Oxidizing gas means any gas that may, generally by providing oxygen, cause or contribute to the combustion of other material more than air does. Gases under pressure: Gases under pressure are gases that are contained in a receptacle at a pressure of 200 kPa (29 psi) or more, or that are liquefied or liquefied and refrigerated. They are comprised of compressed gases, liquefied gases, dissolved gases, and refrigerated liquefied gases. Flammable liquids: Flammable liquid means a liquid having a flash point of not more than 93°C (199.4°F). Flash point means the minimum temperature at which a liquid gives off vapor in sufficient concentration to form an ignitable mixture with air near the surface of the liquid. Flammable solids: Flammable solid means a solid that is a readily combustible solid, or that may cause or contribute to fire through friction. Readily combustible solids are powdered, granular, or pasty chemicals that are dangerous if they can be easily ignited by brief contact with an ignition source, such as a burning match, and if the flame spreads rapidly. Self-reactive substances: Self-reactive chemicals are thermally unstable liquid or solid chemicals liable to undergo a strongly exothermic decomposition even without

Chemicals and Products on Locations participation of oxygen (air). This definition excludes chemicals classified under this section as explosives, organic peroxides, oxidizing liquids, or oxidizing solids. A self-reactive chemical is regarded as possessing explosive properties when in laboratory testing the formulation is liable to detonate, to deflagrate rapidly, or to show a violent effect when heated under confinement. Pyrophoric liquids: Pyrophoric liquid means a liquid that, even in small quantities, is liable to ignite within five minutes after coming into contact with air. Pyrophoric solids: Pyrophoric solid means a solid that, even in small quantities, is liable to ignite within five minutes after coming into contact with air. Self-heating substances and mixtures: A self-heating chemical is a solid or liquid chemical, other than a pyrophoric liquid or solid, that, by reaction with air and without energy supply, is liable to self-heat; this chemical differs from a pyrophoric liquid or solid in that it will ignite only when in large amounts. Substances and mixtures that in contact with water emit flammable gases: Chemicals that, in contact with water, emit flammable gases are solid or liquid chemicals that, by interaction with water, are liable to become spontaneously flammable or to give off flammable gases in dangerous quantities. Oxidizing liquids: Oxidizing liquid means a liquid that, while in itself not necessarily combustible, may, generally by yielding oxygen, cause, or contribute to, the combustion of other material. Oxidizing solids: Oxidizing solid means a solid that, while in itself is not necessarily combustible, may, generally by yielding oxygen, cause, or contribute to, the combustion of other material. Organic peroxides: Organic peroxide means a liquid or solid organic chemical that contains a double oxygen structure – it is considered a derivative of hydrogen peroxide. The term organic peroxide also includes organic peroxide mixtures containing at least one organic peroxide. Organic peroxides are thermally unstable chemicals that may undergo exothermic self-accelerating decomposition.

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In addition, it may have one or more of the following properties: Be liable to explosive decomposition; Burn rapidly; Be sensitive to impact or friction; React dangerously with other substances; or Corrosive to metals: A chemical that is corrosive to metals means a chemical which by chemical action will materially damage, or even destroy, metals A chemical is considered a heath hazards class if it is classified as one of the following hazards: Acute toxicity: Acute toxicity refers to those adverse effects occurring following oral or dermal administration of a single dose of a substance, or multiple doses given within 24 hours, or an inhalation exposure of 4 hours. Skin corrosion or irritation Skin irritation is the production of reversible damage to the skin following the application of a test substance for up to 4 hours. Skin corrosion is the production of irreversible damage to the skin; namely, visible necrosis through the epidermis and into the dermis, following the application of a test substance for up to 4 hours. Serious eye damage and eye irritation Serious eye damage is the production of tissue damage in the eye, or serious physical decay of vision, following application of a test substance to the anterior surface of the eye, that is not fully reversible within 21 days of application. Eye irritation is the production of changes in the eye following the application of test substance to the anterior surface of the eye that is fully reversible within 21 days of application. Respiratory or skin sensitization Respiratory sensitizer means a chemical that will lead to hypersensitivity of the airways following inhalation of the chemical. Skin sensitizer means a chemical that will lead to an allergic response following skin contact. Germ cell mutagen (cause genetic defects): Mutation is defined as a permanent change in the amount or

Chemicals and Products on Locations structure of the genetic material in a cell. The term mutation applies both to heritable genetic changes and to the underlying DNA modifications when known. The term mutagenic and mutagen will be used for agents giving rise to an increased occurrence of mutations in populations of cells and/or organisms. Carcinogen (cancer causing agent): Carcinogen means a substance or a mixture of substances that induce cancer or increase its incidence. Substances and mixtures that have induced benign and malignant tumors in well-performed experimental studies on animals are considered also to be presumed or suspected human carcinogens unless there is strong evidence that the mechanism of tumor formation is not relevant for humans. Reproductive toxin: Reproductive toxicity includes adverse effects on sexual function and fertility in adult males and females, as well as adverse effects on development of the offspring. Some reproductive toxic effects cannot be clearly assigned to either impairment of sexual function and fertility or to developmental toxicity. Nonetheless, chemicals with these effects shall be classified as reproductive toxicants. Specific target organ systemic toxicity: Single and repeated exposures that are toxic to specific organ(s). Specific target organ toxicity: single exposure (STOT-SE) means specific, non-lethal target organ toxicity arising from a single exposure to a chemical. All significant health effects that can impair function, both reversible and irreversible, immediate and/or delayed. Specific target organ toxicity: repeated exposure (STOT-RE) means specific target organ toxicity arising from repeated exposure to a substance or mixture. All significant health effects that can impair function, both reversible and irreversible, immediate and/or delayed. Aspiration hazard (chemical pneumonia): Aspiration means the entry of a liquid or solid chemical directly through the oral or nasal cavity, or indirectly from vomiting, into the trachea and lower respiratory system. Aspiration toxicity includes severe acute effects such as chemical pneumonia, varying degrees of pulmonary injury, or death following aspiration.

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The effects of health hazards are normally classified as acute or chronic. Acute hazards are those whose effects occur rapidly after exposure. Example: a skin corrosive will begin to burn the skin immediately upon contact. Chronic hazards are those whose effects take prolonged or repeated exposure. Example: repeated exposure to benzene over several years has been shown to increase the risk of cancer. For hazardous chemicals that do not meet the specific criteria for a physical or health hazard classes that were previously shown, a separate classification, Hazards Not Otherwise Classified (HNOC) was created. HNOC classification is available for chemicals whose hazards fall below an assigned or cut-off value or concentration limit of the hazard class or provides a place for assignment to a GHS hazard category that has not been adopted by OSHA. Labels are required on almost all containers of hazardous chemicals in the work place, including well sites. The label is the most immediate source of information on hazardous chemicals, so it is important to understand what information can be found on the label that will help you to safely use the chemical. Under the new Hazard Communication guidelines, most hazardous chemical labels must include the following information: Product Identifier Pictograms Signal words Hazard Statements Precautionary Information Supplier Identification Under the new requirements, pictograms are required on most chemical labels. Pictograms are to be black symbols on a white background within a red frame. Signal words and hazard statements will now be included in Labels and Safety Data Sheets. Signal words will be used to emphasize and distinguish hazard levels. The word “CAUTION” will no longer be used as a signal word. Only two words will be used as signal words. WARNING: used for less severe hazards DANGER: used for more severe hazards In addition, each hazard classification and category will have a specific hazard statement.

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Here are four examples from the Flammable classification with the appropriate hazard statement for each category. Category 1: Extremely flammable liquid and vapor Category 2: Highly flammable liquid and vapor Category 3: Flammable liquid and vapor Category 4: Combustible liquid Labels may also contain information from other hazard ranking systems. These rating systems are widely used and commonly found on hazardous chemical labels. The severity of these hazards are listed on a scale of 0 – 4, with 0 being least hazardous and 4 being most hazardous. Note that this scale is the opposite order of hazard potential used by OSHA. The HMIS label is similar to NFPA in that it has color-coded boxes for hazardous chemicals. In this system: Blue Square: Health hazards Red Square: Flammability hazards Yellow Square: Reactivity hazards White Square: Personal protection needed when handling HMIS also rates the hazards on a scale of 0 - 4 (0 being least hazardous, 4 being most hazardous), similar to NFPA, and is also the opposite order of hazard potential selected by OSHA. GHS uses categories for each hazard class to rate the hazard severity. These categories are typically divided using a scale from 1-4 where 1 is the most hazardous and 4 is the least hazardous. The severity rating is in opposite order of the existing NFPA/HMIS hazard rating system that uses categories 0-4. In these systems, “0” is the least hazardous and “4” is the most hazardous. Since the HCS 2012 hazard rating does not replace NFPA/HMIS hazard ratings, you may see hazardous chemical container labels and SDS with OSHA and NFPA/ HMIS ratings. Since the rating systems are opposite in scale, it is important to understand how both rating scales work as to not be confused. Labels are also required to include precautionary statements to provide instructions on proper handling of the chemical. There are four types of precautionary statements presented Prevention: Protective equipment, safe handling and use Response: First aid and spill cleanup Storage: Proper storage procedures Disposal: Proper disposal procedures

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(a) GHS Explosive hazard

(b) GHS Flammable hazard

(c)GHS oxidizer hazard

Pictogram

Pictogram

Pictogram

(d) GHS Toxic hazard

(e) GHS Health hazard

(f) GHS Corrosive hazard

Pictogram

Pictogram

Pictogram

(g) GHS Exclamation point

(h) GHS Environment

(i) GHS Compressed gas

Hazard pictogram

Hazard pictogram

Hazard pictogram

A HCS 2012 label should contain: The product identifier The supplier information Precautionary Statements Signal Word Hazard Pictograms Hazard Statements and Other supplemental information for the user. It is important to note that while HCS 2012 is phased in over the next few years, one may still encounter labels meeting previous HazCom rules.

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They may not have the same amount of information or pictograms as with new labels, but will still require certain safety information: Identity of hazardous chemical Appropriate hazard warnings Name and address of manufacturer, importer, or other responsible party Many hazardous chemical labels are complaint with the previous Hazard Communication Standard. Hazardous chemicals in the workplace must be labeled with important information that one needs to know. Each product container used shall be labeled with the product name including: Major hazards using words and pictograms Precautionary information for protection against hazards Name of the manufacturer Contact information for the manufacturer

13.12

HCS 2012 Safety Data Sheets (SDS)

Like the MSDS with which the reader is familiar, the Safety Data Sheet (SDS) shall be available for every hazardous chemical product. The SDS (formerly MSDS or Material Safety Data Sheet) is intended to provide comprehensive safety information about a chemical substance or mixture. The revised hazard communications standard now requires a standardized format for all safety data sheets. Changes to Safety Data Sheets include the following: Name changed from Material Safety Data Sheets (MSDS) to Safety Data Sheets (SDS), Require the information to be placed in a standard 16 section format, Use of the new Hazard classifications just discussed, Symbol(s), or a description of symbol(s), in section 2, A Signal word (Warning or Danger, as previously discussed), Hazard and Precautionary (H&P) statements, and The percentages of each hazardous ingredients in the product unless that data is classified as a trade secret

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OSHA now requires that the SDS adhere to a standard 16 section format. Section 1, Identification includes the product identifier or name; manufacturer or distributor name, address, phone number; emergency phone number; recommended use; and restrictions on use. Section 2, Hazard(s) identification includes all covered hazards regarding the chemical; required label elements. Section 3, Composition/information on ingredients includes information on chemical ingredients; trade secret claims. Section 4, First-aid measures includes important symptoms/effects, acute, delayed; required treatment. Section 5, Fire-fighting measures lists suitable extinguishing techniques, equipment; chemical hazards from fire. Section 6, Accidental release measures lists emergency procedures; protective equipment; proper methods of containment and cleanup. Section 7, Handling and storage lists precautions for safe handling and storage, including incompatibilities. Section 8, Exposure controls/personal protection lists OSHA’s Permissible Exposure Limits (PELs); Threshold Limit Values (TLVs); appropriate engineering controls; personal protective equipment (PPE). Section 9, Physical and chemical properties lists the chemical’s characteristics such as the following: Chemical appearance Odor, odor threshold Physical properties (pH, flash point, flammability limits, vapor pressure and density, auto-ignition temperature, decomposition temperature, viscosity, etc.) Section 10, Stability and reactivity lists chemical stability, hazardous decomposition products, and conditions to avoid. Section 11, Toxicological information includes routes of exposure; acute and chronic effects; toxicity data; carcinogenicity. Section 12, Ecological information Ecotoxicity Biodegradability Section 13, Disposal considerations Waste description Waste handling and disposal

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Section 14, Transport information DOT shipping name, hazard class, packing group UN number Section 15, Regulatory information lists product specific safety, health, and environmental regulations. Section 16, Other Information includes the date of preparation or last revision. Sections 12, 13, 14 and 15 have been allotted to contain information not regulated by OSHA, but agencies, such as EPA, may regulate this information. As a result, OSHA will not enforce compliance on these sections, so these sections may be found blank. It is important to note that while HCS-2012 is phased in over the next few years, employees will still encounter MSDS with information meeting previous HazCom rules. For this reason, it will be important to understand the information in both an MSDS and SDS. The difference between the two by looking at what each is required to contain. MSDS are required to include certain information for the hazardous chemical: Chemical ID Physical and chemical characteristics Physical and health hazards Primary routes of entry Applicable exposure limits Handling, disposal, and spill procedures Control measures (Engineering, administrative, PPE) First aid Preparation date Name and contact information of manufacturer A Safety Data Sheet (SDS) will contain the following information: Product specific information on the hazards of the product Measures that one can take to protect oneself, others, and the environment, Guidelines for proper storage, transportation and disposal procedures, Manufacturer contact information, and

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Fracking 2nd Edition Guidelines on emergency response measures that may be taken by trained and equipped personnel

Before using any hazardous chemical, you should read the SDS and be come familiar with properties of the chemical such as: Appearance and odor Odor is normally the first indication on whether one is being exposed to a chemical. For many hazardous chemicals, if one can smell it, one is already overexposed. Physical Properties: Is it a liquid or solid? Will it give off a large amount of vapor? Chemical Hazards: Unknown chemicals should be considered hazardous, until otherwise specified. Personal protective equipment (or PPE) is used when hazards may not be completely controlled or eliminated by other control measures (e.g., ventilation). Types of PPE normally used include Chemical-resistant goggles Face shield Chemical gloves Apron Respirator PPE should be checked prior to use. Damaged or malfunctioning PPE must not be used. PPE selection is based on hazard assessment and effectiveness of PPE. The SDS should also contain basic first aid measures to be taken in the event that a person is exposed to the hazardous chemical. These are actions that can be taken to reduce the damage that the exposure may cause. Here are some examples actions that may be recommended on the SDS: If hazardous chemicals come into contact with the skin or eyes from spills or splashes: flush the affected area immediately with water for at least 15 minutes. If a large amount of chemical is inhaled: move away from the source to an area of fresh air. If a hazardous chemical is ingested: contact a medical service provider such as a Poison Control Center, Emergency

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Room, or other Emergency Service provider immediately. Remember, for any hazardous chemical exposure, seek medical attention as soon as possible. In emergencies when there is no other help available, one can call CHEMTREC (1-800-424-9300). Many hazardous chemical manufacturers include this number on their label and SDS. CHEMTREC is available 24/7/365 days a year. CHEMTREC can provide SDS information on many products and information to Emergency Responders.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

14 Public Perception, the Media, and the Facts

In a report published by Energy Institute Fact-Based Regulation for Environmental Protection in Shale Gas Development by Charles G. Groat, Ph.D., Principal Investigator and Thomas W. Grimshaw, Ph.D., Co-Principal Investigator of the University of Texas at Austin), researchers analyzed print, broadcast, and online news media coverage of shale gas development in the Marcellus, Haynesville, and Barnett shale areas. They found that the tone of media coverage has been overwhelmingly negative in all forms of media. Roughly two-thirds of the articles and stories examined were deemed negative, a finding that was consistent nationally and at local levels. Researchers also found that less than 20% of newspaper articles on hydraulic fracturing mention scientific research related to the issue. Similarly, only 25% of broadcast news stories examined made reference to scientific studies, and about 33% of online news coverage mentioned scientific research on the issue.

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Table 14.1 Tone of media coverage. Media Coverage

Negative

Neutral

Positive

National Newspapers

64%

25%

12%

Local Newspapers

65%

23%

12%

National Television & Radio

64%

19%

18%

Local Television

70%

27%

3%

Online News

63%

30%

7%

Hydraulic fracturing of shale formations to extract natural gas has no direct connection to reports of groundwater contamination, based on evidence reviewed in a study released by the Energy Institute at The University of Texas at Austin. The study, released at the annual meeting of The American Association for the Advancement of Science (AAAS) in Vancouver, British Columbia, found that many problems ascribed to hydraulic fracturing are related to processes common to all oil and gas drilling operations, such as casing failures or poor cement jobs. University researchers also concluded that many reports of contamination can be traced to above-ground spills or other mishandling of wastewater produced from shale gas drilling, rather than from hydraulic fracturing. Charles “Chip” Groat, one of the authors of the study and the Energy Institute associate director said “These problems are not unique to hydraulic fracturing.” The controversies surrounding shale gas development have received considerable media coverage. Public perceptions have been influenced by the controversies and media coverage. For these reasons, both media coverage and public perception of shale gas development have been investigated. All three shale gas areas were assessed for media coverage. Public perception was determined for the Barnett Shale area. Media coverage of hydraulic fracturing, a critical and distinctive component of shale gas development, was assessed for tonality (negative or positive) and reference to scientific research. The assessment covered the period from June 2010 to June 2011 and included three areas: Barnett shale area (Dallas, Tarrant, and Denton counties, Texas) Haynesville shale area (Shreveport, Louisiana) Marcellus shale area (six states)

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The six Marcellus locations were Pennsylvania (Pittsburgh), New York (Buffalo), West Virginia (Charleston), Maryland (Hagerstown), Ohio (Cleveland), and Virginia (Roanoke). Four types of media – newspapers (national and metropolitan), television (national and local), radio (national and local), and online (Google News) – were included using searches for keywords for hydraulic fracturing in 14 groups as follows: Well Blowout Pipeline Leaks Water Well Contamination Regulatory Enforcement Frac Fluid (Frack Fluid) Local Government Response Surface Spills or Accidental Release Public Interest and Protest Groups Flow-Back Water Barnett Shale Groups Water Disposal Wells Wyoming Groups Atmospheric Emissions and Air Quality Marcellus Group Media coverage of shale gas development was assessed in the Marcellus, Haynesville, and Barnett shale areas. The analysis of the tonality of articles and broadcasts included 13 newspapers (three national and 10 metropolitan), 26 broadcast media (seven national and 18 metropolitan television stations and one national radio station), and one online news source. For the nation as a whole, the attitudes were found to be uniformly about two-thirds negative.

National Newspapers (3) Metropolitan Newspapers (10) National Television & Radio (7) Metropolitan Television (18) Online News (1)

Negative 64% 65% 64% 70% 63%

Neutral 25% 23% 19% 27% 30%

Positive 12% 12% 18% 3% 7%

The local media coverage for each of the shale areas shows similarity to the national results for the Barnett and Marcellus shale areas; the Haynesville area may be anomalous because only one newspaper and one television source were available.

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Neutral

Positive

Barnett Shale Area Newspapers (3) Television (6)

79% 70%

6% 30%

16% 0%

Marcellus Shale Area Newspapers (6) Television (11)

67% 74%

25% 20%

8% 6%

Haynesville Shale Area Newspapers (1) Television (1)

8% 0%

46% 100%

46% 0%

With respect to reference to scientific research, the search found that few articles referenced research on the topic of hydraulic fracturing: Percent Referencing Newspaper Articles Scientific Research 18% Television Reports 25% Radio Coverage 15% Online Coverage 33% Public perception of hydraulic fracturing was assessed specifically in the Barnett shale area, utilizing an online survey method that included 75 questions in six categories: Thoughts about hydraulic fracturing Perceptions about hydraulic fracturing Knowledge of hydraulic fracturing behaviors Media use demographics The area included was expanded to 26 counties in Texas, and the survey included nearly 1500 respondents. The results of the survey indicate a generally positive attitude toward hydraulic fracturing, with more favorable responses for the following descriptors: good for the economy, important for U.S. energy security useful, important, effective, valuable, and productive. Attitudes were neutral to slightly positive as indicated by response to several descriptors for hydraulic fracturing: importance for U.S. energy security, safety, beneficial or good, wise, and helpful.

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There was a more negative attitude, however, about environmental concerns. Hydraulic fracturing was felt to be bad for the environment by about 40% of the respondents. Another 44% were neutral, and only 16% were positive. With respect to knowledge of hydraulic fracturing, many respondents were found to have some general knowledge about the process of hydraulic fracturing, but they tend to lack an understanding of regulation and the cost-benefit relationship of production: Most respondents overestimate the level of hydraulic fracturing regulation; for example, 71% were not aware that the Railroad Commission does not regulate how close a gas well can be drilled to a residential property. Many respondents (76%) overestimate annual water consumption for shale gas usage and underestimate (75%) the amount of electricity generated from natural gas. Most generally understand the process of fracturing and gas development surrounding the fracturing of wells, but the scope and technical aspects of fracturing are less well understood. For example, 49% were unaware of proppants, and 42% overestimated scientific evidence surrounding the issue of hydraulic fracturing and water contamination. Knowledge of policy issues related to groundwater contamination, such as the disclosure of chemicals used in fracturing and active groups affiliated with groundwater issues, was high. Knowledge of the occurrence of well blowouts in hydraulic fracturing was high (73%), as well as the impact of blowouts comparison to surface spills (72%). 54% understand the frequency that blowouts have occurred in the Barnett shale. Hydraulic fracturing knowledge was also assessed for the following five areas: 1. Awareness of Hydraulic Fracturing: 50% of the respondents consider themselves to be somewhat aware or very aware hydraulic fracturing. The other 50% were not very aware or were not aware at all. 2. Concern about Water Quality: 35% indicated they were very concerned, and 40% were somewhat concerned, 24% were not very concerned or not at all concerned.

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Fracking 2nd Edition 3. Disclosure of Chemicals Used in Hydraulic Fracturing: Regarding whether state and national officials are doing enough to require disclosure, 12% thought that the officials are doing everything they should, and 32% indicated that officials were doing some of what they should. 47% indicated not as much as should be done was being done. 9% thought that nothing at all was being done. 4. Message to Politicians: When asked about relative priorities of energy production on the one hand and public health and the environment on the other, 67% indicated higher priority on public health and the environment. 5. America’s Future Energy Production: The survey also included an assessment of the degree of willingness to get involved in community efforts, such as organizing, protesting, calling legislators, and petitioning.

The results indicate that people are either undecided or ambivalent, or they sense two equal points of view and are not sure which one to accept. It also appears that respondents sense that it is not desirable to get involved: they are mostly unwilling to participate in any events in support of or against hydraulic fracturing. This could be related to their ambiguous attitudes.

14.1 Regulation or Policy Topics: Media Coverage and Public Perception Media coverage in the Barnett, Haynesville, and Marcellus shale areas is overwhelmingly negative, with about twothirds of coverage – including all media and all shale areas – on the negative side. Much of the coverage has focused on environmental issues such as groundwater contamination. Most residents understand the general process of hydraulic fracturing but lack a strong comprehension of its cope and technical aspects, such as the depth of wells and the role of proppants. Reference to shale gas research is understated in the media, with only 15 to 30% of articles and reports containing such references.

Public Perception, the Media, and the Facts Public perception in the Barnett shale area is somewhat more balanced on the positive and negative side, but a view is held by many (40%) that hydraulic fracturing is bad for the environment. Only 16% have a favorable view. Residents in the Barnett shale area are generally informed about hydraulic fracturing, but they tend to overestimate existing regulations and the amount of water used and under estimate the importance of natural gas in electric power production. Negative media reporting and public perceptions must be addressed by both regulators and the shale gas industry as regulations are developed or added. Comparison of the assessment of public knowledge of hydraulic fracturing in the Barnett shale area with a national survey found that more residents perceived themselves to be more aware of hydraulic fracturing than is the case nationally. But the Barnett area residents and national survey populations are similar in their concerns about water quality and what politicians are doing about the issue.

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When

2009/2010

Well location

Dimock Township, north central PA

Table 14.2 Fracking Incidents.

CABOT OIL & GAS. Issues began with a water well explosion. Gas escaped into aquifer and built up until pressure caused explosion. Residents and national environmental groups alleged Cabot drilling contaminated this and other wells and complained of foul smells and flammable water. Cabot said deep-underground fracking could not have been the cause and on this point PA regulators agree: they told us it was “not Marcellus gas.” Cabot provided water to residents involved and litigation is ongoing. Attracted intense national media coverage and attention from environmentalists.

Incident and company involved PA regulators blamed Cabot’s well design and cement job for allowing naturally-occurring shallow gas to migrate into water supplies of 14 homes; it pointed out last year that despite finding well problems, “hydro fracturing activity has not impacted local wells.” It forced Cabot to plug three wells in April, fined the company, barred it from drilling new wells in Dimock for a year, and criticized its slow response. Cabot acknowledges it did not test water wells for pre-existing gas (common in this region). It says it believes its operations did not cause the gas migration, and subsequent tests show that a majority of area wells contain measurable quantities of naturally occurring gas.

Assessment of incident NO

Is underground hydraulic fracturing a direct cause? YES

Are other drilling practices at issue?

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When

2010

2007

Well location

Caddo Parish, near Shreveport, LA

Bainbridge Township, Geauga County, OH

OHIO VALLEY ENERGY SYSTEMS CORP. Natural gas seeped into an aquifer and led to an explosion in the basement of a home. The discovery of gas in water supplies drew allegations that fracing by Ohio Valley Energy Systems Corp. had pushed gas to the surface. Residents were not injured and the company worked with regulators to evacuate and house the displaced residents, and stop gas flow.

EXCO RESOURCES. EXCO Resources contacted authorities and over 100 homes were temporarily evacuated at company expense in April when the company struck a layer of gas thousands of feet above the Haynesville shale and it escaped into the air and bubbled up through the ground. EXCO had not yet done any fracking of the well.

Incident and company involved

OH regulators concluded in a lengthy report that the cause was a defective cement job in the well casing, compounded by operator error. The investigation found no evidence of hazardous drilling chemicals in the wells and said the problem would have occurred even if the well had never been hydraulically fractured.

LA regulators worked with company to investigate cause of gas migration; officials told us they believe a cement job from an adjacent well is at fault. EXCO has agreed to plug 2 wells and says it is continuing to test the water; it says it will incorporate lessons learned into new well designs.

Assessment of incident

NO

NO

Is underground hydraulic fracturing a direct cause?

(Continued)

YES

YES

Are other drilling practices at issue?

Public Perception, the Media, and the Facts 131

When

2010

2001 and 2004

Well location

Clearfield County, PA

Garfield County, CO

Table 14.2 Cont.

ENCANA. A resident, Laura Amos, alleged her water well was contaminated by frack fluids from wells near her house and that the fluids caused an adrenal tumor. Her case has been extensively publicized and she has appeared in a number of environmental groups’ reports. Fracking operations near her home occurred 2,000 feet underground and her well is 225 feet deep. (This depth is considerably shallower than shale wells in PA, LA, TX, and AK.)

EOG RESOURCES. A June 3 blowout of a gas well sent gas and at least 35,000 gallons of drilling wastewater into the sky and over the ground for 16 hours. This incident occurred during the post- frack flowback period. The incident occurred in a rural, relatively unpopulated area.

Incident and company involved

CO regulators tested her water repeatedly and did not find contaminants associated with frack fluids, including benzene. Encana denied fracking contaminated her water, but Colorado regulators found it in violation of state rules preventing freshwater contamination by gas. Amos has settled with Encana. A study has found correlation of oil and gas drilling with the country’s water characteristics.

PA regulators temporarily suspended EOG’s drilling and fracking activities statewide until it investigated the cause and have allowed drilling to resume. EOG said its preliminary assessment was that the seal integrity between the pipe rams of a blow- out preventer and tubing was compromised.

Assessment of incident

NO

YES – CONTROL OF FLOWBACK WASTE

Is underground hydraulic fracturing a direct cause?

UNCLEAR

YES

Are other drilling practices at issue?

132 Fracking 2nd Edition

When

Past 10 years

2009

Well location

Pavillion, WY

Caddo Parish, near Shreveport, LA

CHESAPEAKE ENERGY. Seventeen cattle were found dead near a Chesapeake Energy drilling site. Chesapeake said Schlumberger was the service company on the job. Both companies denied wrongdoing. The incident attracted extensive coverage; one company not involved told us that when it happened, “nobody wanted to talk about anything else” when it called on state and local officials. Witnesses reported hearing cows bellow before they fell over dead.

ENCANA. EPA tested wells in an area where residents have complained over a decade about effects of gas drilling on their water. In 2009, EPA said it had found chemicals that environmental groups allege are used in the hydraulic fracturing process. EPA says the chemicals “might not be attributable to well components” and also noted agricultural activity nearby.

Incident and company involved

LA regulators concluded fluid leaked from a well pad and ran into an adjacent pasture. It fined each company $22,000. Chesapeake says after testing that the cause of death to cattle was inconclusive. Chesapeake and Schlumberger say they have taken a leading role in “enhancing the standard” for well site construction and liquids handling.

EPA cautions it does not yet know if there is an oil and gas link and that it will release further study results in August 2010. Encana told us the chemicals at issue are not used in fracking and it needs to see additional results before commenting further.

Assessment of incident

NO, BUT HANDLING OF FLUID ABOVE GROUND AT ISSUE

ALLEGED, NOT PROVEN

Is underground hydraulic fracturing a direct cause?

(Continued)

YES

UNCLEAR

Are other drilling practices at issue?

Public Perception, the Media, and the Facts 133

When

2009

Well location

 

Table 14.2 Cont.

COMPANY LINK UNCLEAR. A fish kill along a 43-mile span of the creek due to an invasive saltwater species of golden algae was tied by a number of organizations to hydraulic fracturing. The algae thrive in salty water, and discharge of shale well “flowback water” was suspected because it has high salt content. A gas drilling organization argued drilling activity had not taken place near the relevant portion of the stream. The fish kill continues to be a heated topic among fly-fishing and outdoor enthusiasts.

Incident and company involved An interim EPA report blaming golden algae for the kill cited coal mine discharges of briny water as potential contributing causes but said the algae can also be spread by migratory birds, fishermen, and industrial equipment. PA regulators say they still have not ruled out fracking fluid as a potential contributor but mine drainage, agriculture runoff, and other industrial discharges are also a potential cause.

Assessment of incident NO, BUT HANDLING OF FLOWBACK WATER FROM FRACTURING AT ISSUE

Is underground hydraulic fracturing a direct cause? UNCLEAR

Are other drilling practices at issue?

134 Fracking 2nd Edition

When

2008

Well location

Lower Monongahala River, southwest PA

COMPANY LINK UNCLEAR. The U.S. Army Corps of Engineers sounded alarms when the salt level (or “total dissolved solids” level) spiked “dramatically” on the river in October 2008, according to a letter from the Corps to EPA. Although low rain, acid mine drainage, and industrial discharge can also increase salinity of water, it cited “increased gas drilling in the Marcellus Shale” as an aggravating factor. Earlier this year it urged PA to stiffen water treatment standards, saying “conditions are reversing on Pennsylvania’s rivers” and it was becoming apparent that the ability of some rivers to receive more salt content was near its limits “and simply cannot sustain” additional levels as a result of gas drilling.

Incident and company involved PA environmental regulators cited the Corps’ river results and the Dunkard Creek fish kill in April to call for more stringent rules on treatment of discharge water. The new, tougher standards are incentivizing more companies to recycle flowback water rather than treat and dispose of it in PA rivers and streams.

Assessment of incident NO, BUT HANDLING OF FLOWBACK WATER FROM FRACTURING AT ISSUE

Is underground hydraulic fracturing a direct cause?

(Continued)

YES

Are other drilling practices at issue?

Public Perception, the Media, and the Facts 135

When

2009

2009

Well location

Hopewell Township, southwest PA

Dimock, PA, north central PA

Table 14.2 Cont.

CABOT OIL & GAS. Cabot Oil & Gas had three spills of fracking water and gel totaling 8,000 gallons within a week. The spills entered a creek and nearby wetland, according to regulatory documents.

RANGE RESOURCES. A spill of diluted frack fluid from a Range Resources drilling operation into a small tributary killed small fish, salamanders, and frogs. A relatively small amount of fish were affected, the company said.

Incident and company involved

PA regulators fined Cabot $56,650 and urged the company to “do a better job in the future of overseeing its contractors.” Cabot said the spills were 99.5% water and the material was not hazardous. It said its policy is zero spills.

PA regulators fined Range $141,175 in May 2010 for the spill. The cause was a broken joint in a transmission line transporting the fluid.

Assessment of incident

NO, BUT HANDLING OF FLUID ABOVE GROUND AT ISSUE

NO, BUT HANDLING OF FLUID ABOVE GROUND AT ISSUE

Is underground hydraulic fracturing a direct cause?

NO

YES

Are other drilling practices at issue?

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Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

15 Notes from the Field

This work would not be balanced if it did not include concerns and complaints from those who claim fracking has affected them adversely. What follows is a small sampling of the overwhelming amount of concern that is being placed locally on the practice of fracking. The following is the synopsis of just one concerned resident, but it speaks volumes as to the depth of passion that is being applied. The following are notes from Kim Feil of Arlington, Texas. The following notes have been reprinted with permission. Content has not been edited or changed in any manner save for typeset for space continuity. Mon 12/17/2012 7:32 AM Fr: Kim Feil We had a drill spill in Lake Arlington, our drinking source, a couple of years ago during a workover. There should have been setbacks the RRC should have mandated away from our drinking water sources. There is also a compressor Station near the lake that an air test uncovered high formaldehyde a couple of years ago that the RRC should have mandated electic compressors station near people and our drinking water source...

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http://www.tceq.state.tx.us/assets/public/implementation/barnett_ shale/healthEffects/2011.03.16-healthEffectsMemo.pdf http://www.tceq.state.tx.us/assets/public/implementation/barnett_ shale/healthEffects/2011.03.16-healthEffectsMemo.pdf We also have about 100 drilling laterals under our lake that are at migration risk from seismic events and or cement failures. The RRC should have never allowed laterals to go UNDER our drinking water source. We have had maybe a dozen gas release emission events over the last couple of years that I am aware of. ...the RRC didn’t mandate the TCEQ to test for methane on their sumas so that waste is not occurring in minerals management that the RRC was to protect. 1. The RRC should have mandated electric (not diesel) rigs and compressors in ALL urban areas.... http://www.youtube.com/watch?list=FLw_o2P355EYmh7o nTqiwcEA&feature=player_embedded&v=js5vVSpWwEw 2. The RRC should have mandated that a RRC be present during every cement pour or at least video tape ALL cement casing pours when it comes back up to the top through the annulus so that there is proof of an even pour and (PER DALE HENRY) the RRC should ensure all wells have electric bond log tests. 3. The RRC should have mandated that all drilling mud farming and brine road spraying should be tested and subjected to open records of water and soil test results... http://www.youtube.com/watch?v=ZQTtI94GGd8&feature =player_embedded Brine spraying 4. We needed the RRC to seek or mandate the industry to invent technology to keep the toxic, silica dust on the padsite - those pathetic pillow case looking socks aren’t getting the job done. OSHA and NIOSH are aware of the problem...  http://blogs.cdc.gov/niosh-science-blog/2012/05/ silica-fracking/ http://www.youtube.com/watch?v=SF7fkgzmgO0&feature= youtu.be 5. We needed the RRC to mandate ventless, emission free flowback tanks by using pressurized flowback tanks instead of open hatch frack tanks.... http://www.youtube.com/watch?v=fdKoeBvUHys&feature =player_embedded

Notes from the Field 139 6. Global Warming isn’t waiting 2.5 years for the EPA mandated Green Completions equipment....  the RRC should have mandated no venting or flaring period. 7. The RRC should have mandated that the pipeline should be in place FIRST before fracturing so that flowback doesn’t sit in the ground for months festering bacterial sulfide growth to sour and damage the well and sicken people..... http://barnettshalehell.wordpress.com/2012/03/05/ slammed-with-sudden-nausea-from-flowback-odors-business-womans-blood-pressure-soars-after-vomiting/ 8. The RRC should have done health and environmental impact studies before allowing urban drilling.  The setback away from people should be substantial. Rural method drilling is not acceptable in urban areas. An environmental tester who has a Phd said that the health effects/leukemias are being seen downwind from about 1,800 – 2,500 feet.... http://barnettshalehell.wordpress.com/2012/09/05/envirtester-ph-d-master-public-health-on-fracking-emissionsfallout-distance-1800-2500-feet-of-the-downwind-effect/ 9. The RRC should have zero tolerance for underinspected, or faked Waste Disposal Injection Well casing pressure tests. Don’t risk eventual migration of toxic fluids into our drinking supplies..... http://www.propublica.org/article/trillion-gallon-loopholelax-rules-for-drillers-that-inject-pollutants 10. The RRC should regulate how close old wells are to new wells.... From: Karen Sanchez To: kim feil Sent: Mon, October 22, 2012 2:17:16 PM Subject: RE: open records needed to verify when/if well has been shut in permanently Ms. Feil: The Railroad Commission of Texas does not regulate how close fracking can occur near old wells.  Kim Feil http://barnettshalehell.wordpress.com/

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Fracking 2nd Edition TEX LG. CODE ANN. A§ 253.005: Texas Statutes – Section 253.005: LEASE OF OIL, GAS, OR MINERAL LAND “(c) A well may not be drilled in the thickly settled part of the municipality..” Texas Administrative Code, Title 30, Part 1, Chapter 101, Subchapter A,Rule 101.4, Environmental Quality, Nuisance

The following are a short list of incidents and concerns generated by Kim. Lorrie Squibb Location: Flower Mound, TX Gas Facility: Intensive gas production Exposure: Air Symptoms: Multiple myeloma, a blood cancer http://www.scribd. com/doc/75887335/CWA-Health-Workers-Letterto-GovCuomo-Fracking-2011-12121 http://www. dentonrc.com/local-news/special-projects/gas-well-drilling-headlines/20110831-breast- cancer-rate-climbs-up.ece Megan Collins Location: Dish, TX Gas Facility: Compressor station Exposure: Air Symptoms: Sinus issues, difficulty with balance and standing, headaches, fainting, dystonia and ataxia, nausea http://www.earthworksaction.org/voices/ detail/dish_texas http://www.npr.org/templates/story/story. php?storyId=120043996 Deborah Rogers Location: Forth Worth, TX Gas Facility: Chesapeake drilling operations Exposure: Water, air- benzene, dichlorodifluoromethane, chloroform, xylenes, toluene, disulfides Symptoms: Nausea from the strong odors, nose bleeds, severe headaches. Symptoms (animal): Asphyxiated goats and chickens http://www. earthworksaction.org/voices/detail/deborah_rogers http:// vimeo.com/40547126 Sandra DenBraber Location: Arlington, TX Gas Facility: Carrizo natural gas operations Exposure: Air – benzene, toluene, ethylbenzene, and xylenes Symptoms: Blood has Ethylbenzene, m,p-Xylene, Hexane, 2-Methylpentane, 3-Methylpentane; migraines http:// www.texassharon.com/2010/12/14/is-natural-gas-drillingand-production-making-you-sick/ http://blog.uta.edu/ sustainability/2008/04/02/arlington-woman-claims-drillrig-causessickness/http://www.fwweekly.com/index.

Notes from the Field 141 php?option=com_content&view=article&id=2906:breath ers- beware&catid=76:metropolis&Itemid=377 Jean Stephens Location: Arlington, TX Gas Facility: Flow back job Exposure: Air Symptoms: Sick to her stomach, disoriented and difficulty breathing http://barnettshalehell. wordpress.com/2012/03/05/slammed-with-sudden-nauseafrom-flowback- odors-business-womans-blood-pressuresoars-after-vomiting/ Tim and Christine Ruggiero and family Location: Wise County, TX Gas Facility: Gas wells Exposure: Water-methane, as well as sodium and other heavy metals Symptoms: Loss of sensation in his extremities, rashes, nausea and memory loss; asthma http://www.earthworksaction.org/voices/ detail/tim_and_christine_ruggiero Steve Birchfield Location: Johnson County, TX Gas Facility: Gas production Exposure: Water Symptoms: Sick, weak http://www.rodale.com/natural-gas-drilling?page=0,3 Lloyd Burgess Location: TX Gas Facility: Compressor station Exposure: Air Symptoms (animal): Horses- sick, death, neurological defect and blind in both eyes http://www.npr. org/templates/story/story.php?storyId=120043996 Charles Morgan Location: Dish, TX Gas Facility: Compressor station Exposure: Air pollution Symptoms: Constant low frequency roar from the compressors has twice ruptured right ear drum; a neighbor who lives on the other side of the compressor station confirmed he and his infant daughter also suffered ruptured ear drums http://www.npr.org/templates/ story/story.php?storyId=120043996 Sharon Ward (deceased 2011) Location: Dish, TX Gas Facility: compressor stations, 130 in the County Exposure: Air pollution Symptoms: Unknown, replacement water or relocated http://www.npr.org/templates/story/story. php?storyId=120043996 * Headaches, dizziness, ringing of the ears, and lack of sleep, are symptoms county wide Kenneth Bateman and son Location: Justin, TX Gas Facility: compressor station, high pressure pipeline Exposure: Air pollution; noise Symptoms: Diabetes, other health ailments http://www.elkcapital.net/screamingsilence/voices/ bateman.html Kim Davis Location: Southlake, TX Gas Facility: Gas production Exposure: Air-twenty-six chemicals, carbon

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Fracking 2nd Edition disulfide, benzene and naphthalene, carbonyl sulfide, dimethyl disulfide and Pyridine Symptoms: Unknown, replacement water or relocated http://www.dallasobserver. com/2011-11-24/news/fear-and-fracking-in-southlake/2/ Warren and Rebekah Sheffield and family Location: Dish, TX Gas Facility: Compressor station Exposure: Air, Symptoms: Sick, multiple chemical sensitivity. Vertigo; children easily winded , vomiting, hives, itchy skin, nosebleeds, seizure http://www.dentonrc.com/local-news/special-projects/gaswell-drilling-headlines/20110328- atmosphere-of-concern. ece Chuck and Geri Pegg Location: Dish, TX Gas Facility: Few hundred feet northeast of large compressor Exposure: Air – benzene, carbon disulfide, a neurotoxin. Symptoms: Unknown, replacement water or relocated http://www. dentonrc.com/local-news/special-projects/gas-welldrilling-headlines/20110328- atmosphere-of-concern.ece Jim and Judy Caplinger Location: Dish, TX Gas Facility: Compressor station Exposure: Air – noxious fumes Symptoms: Unknown, replacement water or relocatedhttp:// www.dentonrc.com/local-news/special-projects/gas-welldrilling-headlines/20110328- atmosphere-of-concern.ece Steve Lipsky Location: Parker County, TX Gas Facility: Wells, fracking under home Exposure: Water – methane Symptoms: Fatigued and nauseated http://www.dallasobserver. com/2012-04-26/news/fire-in-the-hole/ Cecil and Tyler Williams Location: Caddo Parrish, LA Gas Facility: Chesapeake spill Exposure: Oil; water – elevated chlorides, oil and grease, organic compounds in soil and water tests Symptoms (animal): 17 dead cows http://shaleshock. org/2009/08/hours-passed-before-cow-deaths-reported/ Kelly Gant Location: Bartonville, TX Gas Facility: Compressor station and a gas well near house Exposure: Air Symptoms: Severe asthma attacks, dizzy spells and headaches https://dontfractureillinois.org/Other_ communities.html Jane Lynn Location: Arlington, TX Gas Facility: Chesapeake natural gas well Exposure: Air Symptoms: Uncontrolled coughing, heart palpitations, burning noses & eyes http:// durangotexas.blogspot.com/2011/04/residents-gassedduring-last-nights.html

Notes from the Field 143 http : / / w w w. e a r t hw or k s a c t i on . or g / m e d i a / d e t a i l / arlington_residents_challenge_chesapeake_energy_to _prove_they_are_releasing Brian Beadle Location: Hill County, TX Gas Facility: Williams’ gas wells Exposure: Water- sulfates, toluene Symptoms (animal): Goats, llama- swelling, death http://archive. fwweekly.com/content.asp?article=6885 John Sayers Location: Hill County, TX Gas Facility: Williams’ gas wells Exposure: Water- sulfates, toluene, hydrocarbons Symptoms: Unknown, replacement water or relocated http://archive.fwweekly.com/content.asp?article=6885 Stevan and Charlotte Harris Location: Hill County, TX Gas Facility: Williams’ gas wells Exposure: Water- sulfates, toluene, hydrocarbons Symptoms: Unknown, replacement water or relocated http://archive.fwweekly.com/content.asp?article=6885 Doug and Diana Harris Location: Denton County, TX Gas Facility: Devon Energy gas production Exposure: Water – high levels of metals: aluminum, arsenic, barium, beryllium, calcium, chromium, cobalt, copper, iron, lead, lithium, magnesium, manganese, nickel, potassium, sodium, strontium, titanium, vanadium Symptoms: Emotional harm and mental anguish, loss of peace of mind, anxiety, and their bodies have been physically injured https://docs.google.com/viewer?a=v&q=cache:A5v6WzC WFLsJ:press.wturley.com/Harris%2520v.%2520Devon% 2520Energy.pdf+&hl=en&gl=us&pid=bl&srcid=ADGE ESicKmPV6cVx_ihmctJfgSvgEmM7YfJSLgm48mUKn_ bYfUIunRLuEgIDW5rNjtGkx4JCzXGZnjnzPaR6NBzbSkAiA1ew8QolwS0EywILW9jHoyJ1rrg06yLEnp164ycN56 5hCk&sig=AHIEtbTBhDjnA5UCHGqEJrGiBun3LTU uBA Grace Mitchell Location: Johnson County, TX Gas Facility: Chesapeake Energy gas production Exposure: Water Symptoms: Unknown, replacement water or relocated http://dfw.cbslocal.com/2010/12/15/north-texas-residentslawsuits-claim-gas-drilling-contaminated- water/130. Jim and Linda Scoma Location: Johnson County, TX Gas Facility: Chesapeake Energy gas production Exposure: Water Symptoms: Unknown, replacement water or relocated http://dfw.cbslocal.com/2010/12/15/north-texas-residentslawsuits-claim-gas-drilling-contaminated- water/

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Fracking 2nd Edition John and Jayme Sizelove Location: Denton County, TX Gas Facility: William’s drilling operations and compressor stations Exposure: Air Symptoms: headaches, respiratory problems, and other symptoms http://earthjustice.org/features/ campaigns/fracking-damage-cases-and-industry-secrecy Bob and Lisa Parr, daughter Emma Location: Wise County, TX Gas Facility: 21 gas wells Exposure: Air Symptoms: Lisa – rashes, breathing difficulties, nausea and headaches, balance and other neurological problems; Bob – nosebleeds, balance and other neurological problems; Emma – asthma, rashes and nausea http:// responsiblegold.com/TXOGAP-CaseStudy-Parr.cfm Brian Norberg (deceased) Location: Tunnel City, TX Gas Facility: Procore frack sand mining Symptoms: “He felt completely defeated that he could not protect the community from them moving in and destroying our lives,” recalls Lisa. He died of a heart attack less than a day later at the age of 52. The family is convinced his death was a result of the stress caused by the conflict. That stress is certainly all too real.” http://www.motherjones.com/environment/2012/05/ how-rural-america-got-fracked?page=2 Sinikka Dickerson, Corporal Dale Horton of Arlington Police Dept., Bonnie Billado & daughter Location: Arlington, TX Gas Facility: Unknown which drill-site, winds carried from many drill sites in that area Exposure: Air Symptoms: Disoriented, dizzy, & nauseated within a few seconds of odor, lingering headache hours afterwards http:// arlingtontx.granicus.com/ViewPublisher.php?view_id=2 Select Dec 6 2011 evening meeting, go to 1:09:17 thru 1:17:45 of City Council meeting for relevant testimonies David Hudson Location: Panola County, Texas Gas Facility: Injection wells Exposure: Water - arsenic, cadmium, lead, benzene and other substances Symptoms: Unknown, replacement water or relocated http://www.propublica.org/ article/polluted-water-fuels-a-battle-for-answers Frank and Earnestene Roberson Location: Panola County, Texas Gas Facility: Injection wells Exposure: Water arsenic, cadmium, lead, benzene and other substances Symptoms: Unknown, replacement water or relocated http://www.nytimes.com/2006/07/09/us/09deberr y. html?pagewanted=print

Notes from the Field 145 Maggie Golden (deceased) Location: Panola County, Texas Gas Facility: Injection wells Exposure: Water arsenic, cadmium, lead, benzene and other substances Symptoms: Unknown, replacement water or relocated http://www.nytimes.com/2006/07/09/us/09deberr y. html?pagewanted=print J.D. Johnson Location: Tarrant County. TX Gas Facility: Fracked well Exposure: Water Symptoms: Unknown, replacement water or relocated http://www.mcclatchydc. com/2010/09/07/100188/in-texas-search-for-truth-about. html Amber and Damon Smith Location: Denton County, TX Gas Facility: Devon Energy fracked gas well Exposure: Water arsenic, chromium, butanone, acetone, carbon disulfide, and strontium Symptoms: Unknown, replacement water or relocated http://www.dentonrc.com/local-news/specialprojects/gas-well-drilling-headlines/20110329-just- belowthe-surface.ece Carol Grosser Location: Edwards County, TX Gas Facility: Gas well Exposure: Water Symptoms: Unknown, replacement water or relocated http://www.shalegas.energy.gov/ resources/060211_earthworks_natural_gas_flowback.pdf Tom and Barbara Vastine Location: Parker County, TX Gas Facility: Gas well Exposure: Water Symptoms: Unknown, replacement water or relocated http:// www.dentonrc.com/local-news/special-projects/gas-welldrilling-headlines/20110329-just- below-the-surface.ece Catherine and Brett Bledsoe Location: Wise County, TX Gas Facility: Aruba Petroleum, fracked wells Exposure: Water benzene and very high levels of MTBE Symptoms: Water stung their eyes and had odor, animals refused to drink http://www.shalegas.energy.gov/resources/060211_earthworks_natural_gas_flowback.pdf Myra, Mike and Cameron Cerney Location: Karnes County, TX Gas Facility: Marathon gas production Exposure: Air Symptoms: Frequent headaches, nosebleeds, rashes http:// www.texassharon.com/2012/07/23/letter-from-the-eagleford-shale-tells-of-rashes-nosebleeds- and-misery/ *Many neighbors suddenly have rashes Julia Trigg Crawford Location: TX Gas Facility: Pipeline Exposure: N/A Symptoms: Land condemned by eminent

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Fracking 2nd Edition domain http://www.huffingtonpost.com/2012/08/23/keystone-pipeline-texas- crawford_n_1824939.html?utm_hp_ ref=green Michael and Susan Knoll Location: Wise County, TX Gas Facility: Gas wells Exposure: Water, spills on land Symptoms: Coughing Symptoms (animal): Dog – rare form of cancer http://fuelfix.com/blog/2011/05/23/fracking-feud-pitsprosperous-n-texans-against-energy-industry/ Kim Triolo Feil Location: Arlington TX Gas Facility: Carrizo UT Arlington pad-site & General Motors Natural Gas padsites Exposure: Air Symptoms: Increased breathing difficulty, uncontrolled eyebrow twitching/jar clenching, gastro issues, and joint pain/muscle weakness - joint pain/muscle weakness issues relieved with six month nutritionist/detox treatment Symptoms (animal): Parrot developed cough/ asthma http://barnettshalehell.wordpress.com/2011/07/24/ barnett-shale-arlington-tx-health-effects-diarynaturalgas-urban-drilling-emissions-and-the-canary-effect/ http:// www.youtube.com/watch?v=PVxPnJUCDb0 Josh Beckett Location: McAllen, Texas Gas Facility: Eagle Ford Midstream pipeline Exposure: Loss of habitat due to a failure to adopt an environmentally responsible route that will not cause a prohibited ‘take’ of the endangered ocelot Symptoms (animal): Endangered ocelot – habitat loss http://www.washingtonpost.com/sports/pitcher-joshbecketts-company-sues-pipeline-builder-over- texas-habitat-for-endangered-ocelot/2012/10/17/1e17836a-186311e2-a346-f24efc680b8d_story.html Hector Rodriguez Location: Gardendale, Texas Gas facility: Drilling pad Exposure: N/A Symptoms: Disrupted life, ruined plans for building home, property threatened http://www. youtube.com/watch?v=ioMyrTQrkTg Ron and Betty Haley Location: Gardendale, Texas Gas Facility: Drilling pad Exposure: N/A Symptoms: Ruined retirement plans for building home, stress http://www.youtube.com/watch?v=EXYZnI3xkcY&feature=relmfu Anonymous Location: Gardendale, Texas Gas Facility: Drilling operation Exposure: Land – buried waste pit benzene 40 times EPA standards Symptoms: Evacuated from fumes, water – toxic time bomb http://www.youtube.com/ watch?v=D1EFpXrN1gI&feature=relmfu

Notes from the Field 147 Anonymous Location: Gardendale, Texas Gas Facility: Drilling operation Exposure: Land; air- noise Symptoms: Sleep and health affected, dream destroyed http://www.youtube.com/watch?v=iFJvAGgWc4U&feature=relmfu Dr. Lawrence Voesack Location: Gardendale, Texas Gas Facility: Drilling operations Exposure: Silica dust, H2S fumes Symptoms: Property value destroyed, quality of life diminished http://www.youtube.com/watch?v=ZtbyudumSRU William Justiss Location: Lamar County, Texas Gas Facility: Compressor station Exposure: Air - noxious fumes; noise Symptoms: Nausea, vomiting; house shaking from noise www.supreme.courts.state.tx.us/ebriefs/10/10045106.pdf Tom and Judy Alspaugh Location: Lamar County, Texas Gas Facility: Compressor station Exposure: Air - yellowish emission, noise Symptoms: Unable to work outside, house shakes, noses burn www.supreme.courts.state.tx.us/ ebriefs/10/10045106.pdf Joe Donald Mashburn and Judy Mashburn Location: Lamar County, Texas Gas Facility: Compressor station Exposure: Air - Rotten egg smell, noise Symptoms: Exhaust burns the nose, constantly troubled by noise or smell www.supreme. courts.state.tx.us/ebriefs/10/10045106.pdf Joe Denton Mashburn and Christine Mashburn Location: Lamar County, Texas Gas Facility: Compressor station Exposure: Air fumes and noise Symptoms: Because of the fumes, they cannot do anything outside on their property www.supreme.courts.state.tx.us/ebriefs/10/10045106.pdf Joseph Justiss Location: Lamar County, Texas Gas Facility: Compressor station Exposure: Air - fumes and noise Symptoms: Cattle will not graze near pump station because of the vibration or smell on the grass www.supreme.courts. state.tx.us/ebriefs/10/10045106.pdf Leonard and Marie Popham Location: Live Oak County, TX Gas Facility: Pioneer Natural Resources gas wells Exposure: Land Symptoms: Stripped of ability to make a living on his own property, property rendered useless to him http://www. texassharon.com/2012/11/11/vietnam-veteran-victim-ofpioneer-natural-resources-strong- arm-tactics-in-eagle-ford -shale/ Toby Frederick Location: DeWitt County, TX Gas Facility: Range Resources, compressor station and wells Exposure:

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Fracking 2nd Edition Water – contaminated with benzene compounds Symptoms: Water discolored with a noxious odor, smell caused dizziness; forced to drill a new, shallower water well http:// www.texassharon.com/2011/06/13/eagle-ford-shale-watercontamination-show-and-tell/ http://sacurrent.com/texasfracking-critics-tour-the-eagle-ford-as-complaints-of-contamination-surface- 1.1165133?pgno=2 Tim and Shannon Pennington Location: Everman Texas emailed Kim Feil on 12/16/2012 “...we have lost our ground water, our roads are destroyed and there are now earthquakes. ....my husband and i have noticed a severe change in our health. all the symptoms that have been reported by other victims of the natural gas drilling process. ...we are dying literally...” Jake and Mike Wilfong, Paleo Pinto, Texas 17 cattle dead after rainstorm flooded drinking areas with mining effluents. http://mineralwellsindex.com/topstory/x439048960/ Dead-cattle-spur-lawsuit, http://barnettshalehell.wordpress. com/2012/01/18/emails-on-another-cattle-kill-story-nearmineral-wells-tx-june-2010/ Jan from Arlington, TX says she smells the gas wells and has health issues, is being tested for BTEX, formaldehyde & carbon disulfide poisoning- lives on Perkins near Lake Arlington’s gas wells and compressor station. http://www. youtube.com/watch?v=8_XIe8Bo72k Ethan Tempra, Arlington, TX needed bone marrow transplant - Kim Feil investigated and found he lives on Tiffany Lane near the drill sites and compressor station near Lake Arlington, and goes to school at Grace Prep which is also near a drill site at I20 & Park Springs Blvd. http://www.myfoxdfw.com/story/19044568/boys-lifedepends-on-bone-marrow-donor Aunt of Grogan family in Arlington, TX living near Martin High (where other suspect cancer clusters have been claimed -see Jan #644 case video) thinks the water maybe the cause of 3 of 4 family members having cancer including the dog. Her brother is a geologist with oil and gas industry with a kidney tumor, her sister-in-law has breast cancer, their child has Ewings Sarcoma. Kim Feil suspects the father is bringing home contaminates on his clothing.

Notes from the Field 149 Exxon (XTO) methanol additive handler for biocide treatments, Arlington, TX. His wife mentioned methanol poisoning, she wife complained of foul odor on his work clothes, their 16-year-old daughter has a benign brain tumor and terrible headaches. Arlington, TX video of testimony from Tammie Carson regarding nose bleeds of grandbaby, respiratory issues of daughter and her daughter’s husband. The anonymous lady complained her 16-year-old son who lives near drilling in Arlington was having seizures from brain lesions. Tammie complained to me “....(left the window open yesterday, Dec 7 2012) inside my house smelled like paint thinner or lacquer, ....had not been here all day ....my back door faces the line of drilling sites on hwy 287 between Little rd and Sublett. “  The date of the complaint matched her being downwind from the gaswells with southwest winds that day. http://www.youtube.com/watch?v=qBrbVusbvIM Ft Worth  Mary Kelleher, farm animals drowned during rainstorm when drillers changed grading near her property when pipeline was installed.  http://www.fwweekly. com/2012/07/25/dammed/ Dani Hood, Godley, TX - claims well water, earthquakes and poor health affected by drilling in email to Kim Feil on Facebook. Dr Hensley, determatologist – Arlington, TX told Kim Feil and witnessed by son Graham that he saw a lot of rashes from industry men working with silica dust. Natalie Genco, Colleyville, TX - Nov 2011 water well went bad just after drilling nearby.  http://www.youtube.com/ watch?v=cfl-0yL4oCA Graham Feil age 13, Elm St, Arlington, TX: eyes dilated, lethargic for ten days just after playing outside on a snow “white out” event in Feb 2010. Mom, Kim Feil, suspects cooling inversion pushed pollution down to ground had  headaches, nausea, dizzy, rapid breathing, brain felt scrambled, exhausted yet anxious/hyper. His doctor said he exhibited symptoms of exposure yet no diagnosis was made. Lives downwind to 22 gas wells and two lift compressors at UT Arlington Carrizo gaspad site. http://www.youtube. com/watch?v=7p-G36wAONc&feature=player_embedded,

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Fracking 2nd Edition http://barnettshalehell.wordpress.com/2011/07/24/barnettshale-arlington-tx-health-effects-diary-natural-gas-urbandrilling-emissions-and-the-canary-effect/ Bonnie, Arlington, TX UTA Community Gardens blames two extreme nosebleeds in Jan & Feb 2012 on nearby drilling http://www.youtube.com/watch?v=ztBRDsojySE&featu re=player_embedded Pantego, TX, five wells fracked near Bailey Junior High, Kim Feil reports during that time Graham Feil, Bailey student, diagnosed with asthma,  Mrs. Stuteville, a Bailey teacher, deceased from aneurysm just after the fracking and that by the summer, Bailey music teacher, Mrs Lynn Wilson, continues to battle 4th stage bone cancer (Wilson also lives downwind to the Arlington Compressor Station on Denham Dr). http://www.youtube.com/watch?v=Ht1RU_7r4KI&feature=p layer_embedded Mary Owen, East St, Arlington, TX near Chesapeake, Truman drill site hospitalized for worsened fibromyalgia summer 2012 during fracking of 3 wells. Walker age 14, Arlington, TX April 2011 following the Fulson gas emission event (who also lives about 1,200 feet downwind from the Ragland Site), was hospitalized hours after the gas leak with a 105 fever and swollen neck/ enlarged lymph nodes. No diagnosis was made. Regina & granddaughter, Spitfire Dr, Arlington, TX downwind from Arlington Compressor Station told me she & her granddaughter have respiratory issues ever since drilling came in. Three ER visits in November, 2010 and grandbaby’s nosebleeds are now 3 times a day. She told me sometimes she smelled fumes in the girl’s bedroom. There also is a drill site to the north of them too.

15.1 Going Forward In one respect, the concerns raised could be easily debated and put to rest. It has been suggested that if the well production companies stay within the letter of the law and EPA requirements, then many, if not all, problems can be solved, and future incidents of illness and discomfort shall diminish. As in so many instances, the public perception, the media’s spin, and the industries’ explanation rarely converge. One would

Notes from the Field 151 never have imagined that a fourth-grade math diagram would come in handy, but it is very apparent that this scenario plays out like a highly defined Venn Diagram with each faction holding on dearly to their circle of ‘truth.’ The temptation to take every single concern and debate to resolution is strong, yet it would be a fool’s errand. Concerns mentioned are very real, if in no other eyes than the conveyor. What has to be done is to make a strong and convincing argument to continue the pressure on increased safe exposure and reduced environmental impact. One hundred fifty years ago when crude oil was first being extracted, the damage done to the environment was nothing short of a nightmare. In some areas, little has changed, but in many instances, companies take extraordinary precautions. Many years ago, the ramifications of pollution were not understood. Today, much work is underway to address what is being understood as environmental concerns. The work that goes into preparing a fracking well site today in assuring that the chemicals used are innocuous while maintaining the physical integrity of the surrounding land is taken into consideration primarily for legal reasons as well as business concerns. While many opponents believe that exploration, drilling, and product producing companies will stop at nothing to turn a profit, this is simply not the case. If profit was the only motivation, more American companies would be in business as well as in court. Companies for the most part want to do the right thing. If environmental laws are in place, then work shall be structured accordingly. The challenge is to enact laws that make sense according to empirical evidence. It is also vital that those using the process and chemicals as well as the public understand the technology. As with all moral and ethical debates, evidence, albeit empirical, is all that is available. One cannot make decisions based on hunch or conjecture. One can only apply prudential certitude and act accordingly. Where industry in general fails is rushing forward and only applying the letter of the law and not working to push for higher requirements. Legislation is often left to the most verbal and most passionate. It is fair to say that when emotion runs high, logic wanes. If we are to utilize the gifts that the earth has bestowed upon us, then it is more than fair to assume a protective role going forward and to explore proper protocols to ensure that the environment and comfort of life remain as balanced as it was found. All can learn from the Boy Scout ethic of Leave No Trace. The authors would strongly suggest that if the reader has any concerns, ideas, or questions to direct them to local government agencies. The government is made up of people that may live in one’s town or city. They have the same concerns as those in opposition yet they may not be aware of

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certain incidents. Please bring concerns to them so that the government officials will be made aware. One last request, anyone who engages in an argument that ends with the statement “But what about the children…” shall be forever be thought of as weak and manipulative. Let us base our arguments on facts that can be substantiated. Our concerns will be better received, and just maybe the point will be proven and acted upon.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

16 Migration of Hydrocarbon Gases *Originally published in Environmental Aspects of Oil and Gas Production, by John O. Robertson and George V. Chilingar, copyright 2018, Scrivener Publishing

16.1 Introduction Seepage of methane and other hydrocarbons along faults, fissures, fractures, and outcrops from hydrocarbon-bearing formations is prevalent throughout the globe. The major composition of hydrocarbons in a natural gas migrating from a hydrocarbon reservoir (see Tables 16.1 and 16.2) is methane (typical range of 80% to 90%). Figure 16.1 shows that methane can be derived from several sources: (1) biogenic (shallow bacterial decomposition of organic matter) and (2) thermogenic (hydrocarbon deposits formed by deep burial). Methane is found in great abundance in association with oil and gas fields. Nikonov (1971) demonstrated the abundance of methane in many types of hydrocarbon gas sources (Figure 16.2). Methane is the simplest hydrocarbon and occurs in significant quantities in many areas migrating through the Earth in a gaseous form. As a gas it is light (about half the density of air), flammable, colorless and odorless. If the concentration of methane in the air ranges from 5% to 15%, in the presence of a spark, this mixture is explosive. The consequences of undetected methane gas migrating through the soil under structures can be 153

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Table 16.1 Typical composition of natural gases expressed in mole % (or volume %). (In: Chilingar et al., 1969, table 1, p.89.) Type of gas field Separation pressures4

Component

Sour gas2 (mole %) 3.3

Gas condensate3 (mole %)

400 psi (mole %)

50 psi (mole %)

Vapor (mole %)

0

0

0

0

0.68

0.81

89.57

81.81

69.08 5.07

Hydrogen sulfide

0

Carbon dioxide

0

6.7

0.68

0.3

Nitrogen and air

0.8

0

0

0

98.8

84.0

Methane

74.55

2.16

Ethane

2.9

3.6

8.28

4.56

5.84

Propane

0.4

1.0

4.74

3.60

6.46

8.76

Isobutane

0.1

0.3

0.89

0.52

6.46

2.14

n-Butane

Trace

0.4

1.93

0.90

2.26

5.02

0.75

0.19

0.50

1.42

0.63

0.12

0.48

1.41

0.15

1.05

4.13

Isopentane

0

n-Pentane

0

Hexane

0

Heptane

0

Octane

0

Nonane Total percent 1

Dry gas1 (mole %)

0.7

1.25 6.3

0 100.0

100.0

100.0

100.0

100.0

100.0

Gas from Los Medanos, CA; 2Gas from Jumping Pound, Canada; 3Gas from Poloma, CA; 4Gas from Ventura, CA (oil and gas separators).

disastrous due to the explosive and flammable capabilities of the gas itself. It is encountered dissolved in fluids (oil/water) or as a gas. The principal hydrocarbons present (generally greater than 90% by volume) in natural gas are methane (CH4), followed by ethane (C2H6), propane (C3H8), butanes (C4H10), and heavier components. The heavier hydrocarbons are present in a natural gas in decreasing proportions because of their high molecular weights. Upon migration, heavier hydrocarbons are preferentially adsorbed on rock minerals, mainly clays. The composition of hydrocarbons in natural gases produced from an oil reservoir will vary with various operating oil/gas separator pressures. The example in Table 16.1 illustrates this variation of different components at various oil/gas separation pressures for the same produced gas.

16.2 Geochemical Exploration for Petroleum The presence of methane in soil gas has long been used to identify the potential presence of petroleum. Based upon the potential migration of this hydrocarbon gas from a petroleum source, geochemical exploration

Migration of Hydrocarbon Gases 155 Table 16.2 Physical constants of light hydrocarbons and other components associated with natural gas. (Data abstracted from Natural Gas Processors Suppliers Association, 1981.) Physical constants of selected light hydrocarbons

Compound

Formula

Boiling point @ Molecular 1 atm. weight (°F)

Vapor pressure @ 100 °F (psia)

Critical Critical temperature pressure (°F) (psia)

Liquid specific gravity1

Gas specific gravity2

Hydrocarbons: Methane

CH4

6.04

258.68

116.5

673.1

Ethane

C2H6

30.07

127.53

90.09

708.3

0.375

1.046

Propane

C3H8

44.09

43.73

190

206.26

617.4

0.5077

1.547

n-Butane

C4H10

58.12

10.89

51.6

305.62

550.7

0.5841

2.071

Isobutane

C4H10

58.12

31.10

72.2

274.96

529.1

0.5631

2.067

Isopentane

C5H12

72.15

82.1

20.44

370.0

483

0.62476

2.4906

n-Pentane

C5H12

72.15

96.933

15.57

385.92

489.5

0.63116

2.4906

n-Hexane

C6H14

86.17

155.736

4.956

454.5

439.7

0.66405

2.9749

n-Heptane

C7H16

100.20

209.169

1.6199

512.62

396.9

0.68819

3.4591

n-Octane

C8H18

114.22

258.197

0.537

565.2

362.1

0.7077

3.*4432

n-Nonane

C9H20

128.25

303.436

0.179

(613)

(345)

0.72171

4.4275

n-Decane

C10H22

142.28

345.2

0.073

(655)

(320)

0.73413

4.9118

0.5555

Nonhydrocabons: Nitrogen

N2

28.02

320.4

232.8

92

0.9672

Oxygen

O2

32.00

297.4

181.8

730

1.1047

Hydrogen

H2

2.016

422.9

199.8

188

0.0696

Air

N2 & O2

28.97

317.7

221.3

547

Carbon Dioxide

CO2

44.01

109.3

88.0

1073

0.8159

1.5194

Hydrogen Sulfide

H2S

34.08

76.5

554.6

212.7

1306

0.790

1.1764

Water

H2O

18.02

212.0

0.9492

705.4

3206

1.000

0.6220

1.0000

1

all measurements made with respect to water Specific Gravity = 1.0 2 all measurements made with respect to air Specific Gravity = 1.0

for oil/gas is often conducted by sampling the air in surface samples of soil for the presence of hydrocarbons and then subjecting this gas to chromatographic analysis to detect the presence of methane and other hydrocarbons. This near-surface soil gas exploration for petroleum is based on the detection and interpretation of a great variety of natural phenomena occurring at or near the land surface or seafloor and attributed, directly or indirectly, to hydrocarbons migrating upward from “leaky” reservoirs (Sundberg, 1992). Development of surface geochemical exploration was conducted in the early 1930s, with the chemical analysis of gaseous hydrocarbons found in the air above the surface and/or air within the pores of soil itself. Geochemical exploration presumes that all oil or gas reservoirs

156

Fracking 2nd Edition CH4 Depth mi. 0

CH4 CH4 Gas

Temp. F 50

Water Base of b Biogenic methane acterial zone

Gas Oil Water

200 400

Gas

5

Fault

Gas Organic shale

10

ic gen mo ne r e a Th eth Organic shale m

600

Gas

Gas

800 1000

Deep crustal gas C + 2H2O CH4 + O2 (graphite + water)

Mantle gas (CO2 + CH4?)

1200 1300

15

Figure 16.1 Three processes can generate methane (CH4), the main component in natural gas. Biogenic methane is produced by microorganisms during metabolism. Thermogenic methane forms when heat and pressure decompose deeply-buried organic matter. Chemical reactions deep inside the Earth can also generate methane. (Modified after Howell et al., 1993; in: Khilyuk et al., 2000, p. 46, figure 3.2.)

30

Type of gas source NG - Gas in dry gas provinces G - Gas pools in gas-oil provinces GP - Gas pools related to oil deposits GGP - Gases of gas oil deposits P - Gases of oil deposits

G

Frequency

GP

GGP

20 NG 10

0

P

2.5

5

7.5

10

12.5

15

17.5

20

22.5

25

27.5

30

Sum of methane homologs, percent (%)

Figure 16.2 Frequency distribution of sum of methane gas homologs in different types of deposits. Figure based upon analysis and classification of 3500 worldwide reservoir gases. (Modified after Nikonov, 1971; in: Khilyuk et al., 2000, p. 47, figure 3.3.)

Migration of Hydrocarbon Gases 157 leak some hydrocarbons to the surface, and that these migrating hydrocarbons, if the volume of hydrocarbons is sufficient to be detected, can be related to possible subsurface oil/gas reservoirs. As an exploration technique, surface geochemistry assumes that (1) most reservoirs leak sufficient hydrocarbons to the surface to be recognized geochemically and (2) geochemical anomalies could be associated with commercial reservoirs. It also assumes that detected surface seepage of hydrocarbons is useful in determination of the presence of hydrocarbons of potential subsurface traps (reservoirs). This type of analysis of migrating hydrocarbon gas in the soil can be used to evaluate potential oil/gas reservoirs (Sundberg, 1994). Sundberg (1994) pointed out that in hydrocarbon exploration the use of seeps for identifying the presence of a petroleum source is widely accepted and practiced throughout the petroleum industry. All companies use a variety of techniques aimed at seep detection and hydrocarbon characterization. Particular methods may vary, but the general objectives of the various surveyors are about the same (Sundberg, 1994): 1. 2. 3. 4. 5.

locate hydrocarbon seeps, map the seeps to relate them to subsurface prospects, characterize the petroleum type hydrocarbons in a seep, refine economic evaluations before drilling deeper wells, and aid exploration departments in making lease relinquishments.

16.3 Primary and Secondary Migration of Hydrocarbons Organic material is transformed first into kerogen and then into hydrocarbons as it decomposes and is subjected to pressure and temperature. Due to their lighter density (buoyancy) compared to that of water at the same depth, these hydrocarbons migrate from their source rock, where they were formed, to the reservoir rock, where they are currently found, and then to the surface.

16.3.1 Primary Gas Migration Primary migration refers to the initial movement of hydrocarbons from the source rock to the reservoir. According to Chilingar et al. (2014), under the influence of increasing overburden pressure and geothermal temperature, kerogen in argillaceous sediments will generate petroleum

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hydrocarbons by thermal decomposition. The chemical process of generation of oil has become well established (Welte, 1972). The mechanism of petroleum migration out of source rocks, however, is still poorly understood. Many geologists believe that carrier water is necessary for the primary migration of oil (Hedberg, 1964). They consider that carrier water and oil migrate in the form of solution and/or emulsion. Interlayer water of montmorillonite released by transformation to illite during the late stage of diagenesis was considered to be essential for petroleum migration (Powers, 1964; Burst, 1969; Perry and Hower, 1972). On the other hand, Aoyagi and Asakawa (1980) concluded that both the interlayer and interstitial water expelled during the middle stage of diagenesis were responsible for oil migration. Based on extensive observations, shales composed of non-expandable clays such as kaolinite and illite did not act as source rocks, because of the absence of water necessary to push out the oil (Chilingar, 1960; Aoyagi et al., 1985). Also, many undercompacted (overpressed) shales did not act as source rocks, because compaction mechanisms were not operative to squeeze a sufficient amount of oil into the reservoir rocks. On the other hand, McAuliffe (1966) has objected to these opinions on the basis that oil is only very slightly soluble in water. Also, some geologists have favored the migration theories based on the movement of oil and gas due to the capillary phenomena, buoyancy effect and gas expansion, which are generally independent of the movement of water (Dickey, 1975). Some migration of oil could also occur in a gaseous form (Chilingar and Adamson, 1964). It is necessary to establish what conditions existed during the primary migration of oil (from source rocks to reservoir rocks) compared to those during the secondary migration of oil (during production) to make the former so much more efficient. Several possible explanations were presented by Chilingar et al. (2015): intense electrokinetics, Earth-tides, compaction, migration in a gaseous form, and seismic activity (earthquakes). Schowalter (1999) pointed out that the mechanisms of primary hydrocarbon migration and the timing of hydrocarbon expulsion have been debated by petroleum geologists since the beginning of the science. His discussion of several proposed primary hydrocarbon migrations includes: solution in water, diffusion through water, dispersed droplets, soap micelles, and continuous-phase migration through the water-saturated pores. Some early workers generally favored early expulsion of hydrocarbons with the water phase of compacting sediments. Schowalter (1999) further noted that Cordell (1972) has suggested that oil is formed at depths where the petroleum source rocks have lost most of their pore fluids by compaction.

Migration of Hydrocarbon Gases 159 On the basis of these conclusions, Dickey (1975) suggested a case for primary migration of oil as a continuous-phase globule through the pores of the source rock. Roof and Rutherford (1958) suggested that continuousphase oil migration from source rock to reservoir is required to explain the chemistry of known oil accumulations. Gas accumulations, however, can be explained by either continuousphase primary migration or by discontinuous molecular-scale movement of gas dissolved in water. Price (1976) offered still another expulsion concept. He postulated molecular solution at high temperature, upward movement with compaction fluids, and exsolution at shallower depths in low-temperature saline waters. In order to investigate some problems involved in primary migration of oil (Aoyagi et al., 1985) compacted Na-montmorillonite clay mixed with seawater and crude oil for 25 days under a pressure of 1000 kg /cm2 and a temperature of 60 °C. The proportion of oil in the expelled liquid increased with time. The porosity of the compacted sample decreased from 81% to 26%. These authors concluded that the primary migration of oil from source rocks to reservoir rocks occurred chiefly during the late compaction stage ( = 10–30%). Considering the fact that tectonic activity during the primary migration of oil was intense, the oil was simply squeezed out (expelled) from the source rock.

16.3.2 Secondary Gas Migration Secondary migration refers to the subsequent movement of hydrocarbons from the original reservoir toward the surface. This migration occurs while the hydrocarbons are clearly identifiable as crude oil and or gas, although the migrating gas can be found in either a (1) free form or (2) dissolved in fluids, e.g., oil and/or water. The density of most hydrocarbons is less than that of water; therefore, buoyancy of the hydrocarbons becomes a primary driving force moving the hydrocarbons due to differences in densities between water and hydrocarbons and also in response to differential pressures within the reservoir itself.

16.3.3 Gas Entrapment Hydrocarbons (oil, gas and gas-dissolved-in-water) migrate along various pathways, moving from areas of higher pressure to lower pressure, pushed by buoyancy forces as they work their way toward the surface of the Earth. The reason for accumulation of hydrocarbons in a trapping area (reservoir) is that the hydrocarbons escape from this trapping area (reservoir) at a rate

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slower or equal to those entering the area. All hydrocarbon reservoirs leak over geologic time and, eventually, all hydrocarbons will escape from one trapping area to another, as they migrate toward the Earth’s surface. The primary hydrocarbon trapping area is the primary reservoir, and the subsequent traps as the hydrocarbons migrate to the surface are secondary reservoirs. The hydrocarbon reservoir could be viewed as a temporary holding tank, which leaks at a very slow rate as the petroleum migrates from one reservoir (trap) to another. The time period that any reservoir holds hydrocarbons can be on the order of thousands to millions of years, depending upon the type of migrating hydrocarbon, volume, chemical composition, and the reservoir properties (permeability, porosity, pressure, temperature, etc.) at that time. During this migration period, the hydrocarbon molecules under pressure and temperature are slowly breaking into smaller and lighter hydrocarbon molecules, evolving toward simpler molecules of hydrocarbon (e.g., methane) and, finally, carbon-dioxide. While the migration of larger hydrocarbon molecules can be impeded by smaller migratory pathways of pore and fracture spaces, over time the breakdown of larger into smaller hydrocarbons results in the smaller hydrocarbon molecules having an easier task of passing through the finer pores and fractures (Khilyuk et al., 2000). Migration of hydrocarbons, gas and oil (sometimes tar or heavy oil) has been long observed in petroleum seeps that breach the surface, e.g., La Brea Tar Pits, CA. In this case, oil and gas have naturally migrated along faults to the surface as shown in Figure 16.3. Khilyuk et al. (2000) noted that the primary migration of hydrocarbons occurred along the 3rd and 6th Street faults to the surface forming the La Brea Tar Pits. Additional SE.

NW.

Pleistocene

Tertiary

Figure 16.3 1907 U. S. Geological Survey drawing shows how oil from underground rock layers migrates upward to fill the La Brea pits. (Drawing from “Rancho La Brea, A Record of Pleistocene Life in California”.)

Migration of Hydrocarbon Gases 161 secondary migration of gas occurred along paths that were man-made (abandoned wellbores), which resulted in migration of gas below several structures, giving rise to explosion and fire.

16.4 Origin of Migrating Hydrocarbon Gases Stray natural gas migration refers to movement of natural gas (primarily methane) through rock formations and soil. This gas can originate from leakage of a variety of natural sources, including petroleum reservoirs, coal seams, landfill, or any source of decomposing organic material. It can also originate from man-made installations, e.g., from leaking pipelines and any wellbore (gas, oil, and/or water) leaking hydrocarbons to the water sands above, surface, etc. Freshly drilled and completed or abandoned oilwells (some many years ago) can leak hydrocarbons, liquids, and gas to the surrounding formations if the cement has not totally isolated the well fluids in the reservoir from the wellbore. When a well is drilled, a new man-made pathway for the potential migration of gas is created. This is partly due to the induced fracturing of the formation during the drilling percussion process as the drillbit cuts the formation. Particular care must be taken in completing the well to be sure that potential paths of migrating fluids are properly plugged to block the potential migration of fluids (gas and liquids). The migration of stray gas is common, particularly, in areas that are underlain by deposits of petroleum, coal or decomposing organic materials.

16.4.1 Biogenic vs. Thermogenic Gas Knowing whether a natural gas show is biogenic gas or thermogenic gas is critical to understanding the source of migrating hydrocarbons and if they are related to a petroleum deposit. Geochemical analyses can be utilized to reveal the origin of gas in a gas show or seep, and indicate the presence of petroleum deposit versus a natural (bacterial) source of gas (methane).

16.4.1.1

Sources of Migrating Gases

Natural gases, a mixture of light-hydrocarbon and non-hydrocarbon gases migrating from petroleum reservoirs, vary in chemical and isotopic composition depending on their origin and migration history. Here, natural gas refers to a gas present in petroleum reservoirs. Crustal degassing and

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thermogenic or biogenic decomposition of organic matter can generate methane, the major constituent of gases. Common sources of natural gases include low-temperature bacterial fermentation (Rice and Claypool, 1981), thermogenic breakdown of deeply buried sedimentary organic matter (Schoell, 1983), and the mantle (Gold and Soter, 1980, 1982). The thermogenic decomposition of organic material is a large source of methane. Methane gas is the major component of natural gases associated with petroleum deposits. The non-hydrocarbon gases often present in migrating gases are the “acid” and “inert gases.” Carbon dioxide and hydrogen sulfide are referred to as “acid gases” as they can form acids on contact with water. Nitrogen and helium are referred to as “inert gases.” Normally, gases are partially or completely saturated with water vapor. The source of sulfur found in hydrogen sulfide and mercaptans is from the organic material from which they were derived. Unless sulfur is present, gases are colorless and odorless.

16.4.1.2 Biogenic Methane Methane is the primary component of gases resulting from the biogenic decomposition of organic material under low temperature and pressure. For biogenic and thermogenic decomposition of organic materials, almost all of the hydrocarbon gases are composed of methane with very few heavier hydrocarbons (i.e., ethane, propane, etc.) (Figure 16.4). Figure 16.5 is a schematic diagram for the conversion of organic matter to methane and carbon dioxide. Biogenic decomposition only occurs in shallow sediments where organic matter is exposed to low pressure and temperature without oxygen. Kaplan (1994) noted that the landfill environment was ideal for the biogenic generation of methane and hydrogen sulfide. Methanogenic bacteria (Archaeobacteria) are responsible for producing methane (Woese and Wolfe, 1985). Ward et al. (1978) stated that biogenic methane involves a consortium of microorganisms. The first step in the process involves the enzymatic hydrolysis of complex biochemicals discharged into the environment. When some oxygen is present in the decompositional environment (i.e., in water) aerobic respiration may rapidly convert the organic material into carbon dioxide. If oxygen is excluded during rapid burial, metabolic degradation proceeds by fermentation. The methanogenic bacteria can disproportionate the acids into methane (see Table 16.3). In biogenic systems, the type of environment influences the method of methane formation. Mah and Sussman (1967) noted that primarily

Migration of Hydrocarbon Gases 163 Shallow decomposition of organic material

–90

Biogenic

CO2 reduction

Organic acid decomposition –50 Early

Late

–30

Thermogenic

13

C(‰) of methane

–70

Deeper decomposition of organic material –10 100

70 90 80 60 Methane content in gas, %

50

Figure 16.4 Relationship between the carbon isotope ratio and methane content [C1/(C1-C2)] in gas. (Modified after Kaplan, 1994, p. 305, figure 13.)

Organic matter

Carbon dioxide

H2 O HCO3–

2

+O

2

CO2

+H

Acetic acid CH3COOH

CH4 Methane

Figure 16.5 Schematic diagram for the conversion of organic matter to methane and carbon dioxide. (Modified after Kaplan, 1994, p. 298, figure 2.)

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164

Table 16.3 Types of chemical reaction leading to methane formation. (Modified after Kaplan, 1004, figure 1, p. 298.) Acetic acid fermentation:

CH3COOH

CO2 reduction:

CO2 + 4H2

Mixed reactions: (a) CH3(CH2)(n–1)COOH + nH2O (b) nCO2 + 4nH2 nCH4 + 2nH2O

CH4 + CO2 CH4 + H2O

CH3(n–1)COOH + CO2 + (n +1)H2

–300

–250

Dmethane (‰) –200 –150

–100

–70

Swamp/delta

1

1

Ocean

Maturat ion

2

Mixed gases

Migration

3 S ou

Thermogenic gas, associated with oil

4 Thermogenic gas, dry

(a)

–60

Anoxin basin

Mig rat ion

Cmethane (%)

e enc

sid Sub

2 –50

3

13

1 Bacterial gas

–40

rc e ro c k

O ve rmature S o ur ce rocks

Zone of origin

4 –30

–20

(b) Range of values for each zone of origin

Figure 16.6 The isotopic composition of gas as related to its origin. The left panel depicts the geologic context of the gas origin (e.g., shallow bacterial, thermogenic, etc.) The right panel shows the range of anticipated values for carbon (y-axis) and hydrogen (x-axis) isotopic composition of methane in different genetic types of gases. Inasmuch as the PDB and SNOW are enriched in the13C and D in comparison to natural gases, the latter have negative δ13C and δD values. (Modified after Schoell et al., 1963, p. 338, figure 1.)

methane forms through fermentation of sewage sludge. Claypool and Kaplan (1974) suggested that in marine environments (Figure 16.6), methane forms by reduction of CO2. In fresh-water environments (i.e., swamps, lakes, or rice paddy fields) the process is that of fermentation. In saline environments and ruminating of herbivores, methane is produced by respiratory oxidation of hydrogen with CO2. Mah et al. (1977) have suggested that methane forms by a combination of two metabolic processes (Figure 16.5).

Migration of Hydrocarbon Gases 165 Kaplan (1994) described the microbiological successions in an aqueous environment, such as a lake, swamp, or estuary (Figure 16.7), and suggested that the same microbiological succession can also apply to the rice paddy field or landfill site in an environment with high rainfall. In this case, the methane will form at a depth where the respiratory organisms, which can derive the maximum energy, are no longer able to compete. Methanogenesis by reduction of CO2, is more efficient than methanogenesis by fermentation.

16.4.1.3

Thermogenic Methane Gas

Air

Biogeochemical zones

Water

Photic zone Photosynthesis

Mat forming bacteria Aerobic zone

NO3– SO42– HS–

Micro aerobic zone Anaerobic nitrate reducing zone Anaerobic sulfate reducing zone

HCO–3 CO32– CH4 H2

Aerobic respiration

Anaerobic biocarbonate reducing zone

Anaerobic respiration Anaerobic

O2

Sediment

Me t pro aboli ces c ses

Dis so spe lved cie s

Thermogenic decomposition of organic material may give rise to oil and gas under high temperature and pressure. As shown in Figure 16.4, this

Figure 16.7 Biogeochemical process in a marsh. An idealized cross-setion of a deltaic organic-rich (reducing) sedimentary environment. The biogeochemical zones are a consequence of ecological succession. (After Claypool and Kaplan, 1994, p. 299, figure 4.)

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type of decomposition creates not only methane, but also other light hydrocarbons. The methane content in the hydrocarbon portion of the gas is directly related to the temperature and pressure histories to which the organic material has been subjected. In order to differentiate the biogenic gases from thermogenic, it is necessary to know the ranges of isotopes of thermogenic and biogenic methane (Table 16.4). In fact, the isotopic values indicate the highest thermogenic pressure and temperature that the gas was exposed to. Examples of ranges for isotope ratios of carbon and hydrogen for various living and biologically derived materials, biological and nonbiological minerals, and gases are presented in Figures 16.8 and 16.9. Table 16.4 Ranges of carbon and deuterium isotope ratios for methane derived from different origins. (After Kaplan, 1994, table 2, p. 301.) 13

2

C

Biogenic:

Thermogenic:

D

CO2 reduction

100 to 60

250 to 150

Organic acid decomposition

60 to 45

350 to 250

Immature (low temperature)

50 to 40

250 to 220

Optimum maturity

40 to 30

220 to 160

Highly mature (high temperature)

30 to 15

160 to 90

13

C(‰) (PDB)

–80

–60

–40

–20

0

Atmospheric carbon dioxide Marine limestone Diamonds Carbonatites Marine plankton C3 C4 Terrestrial plants Petroleum Coal Microbial methane Thermogenic methane

Figure 16.8 δ13C values of selected materials. (Modified after Kaplan, 1994, p. 301, Figure 5.)

Migration of Hydrocarbon Gases 167 D‰ (SMOW) –400

–300

–200

–100

0

Sea water Meteoric water Juvenile water? Whole Marine organisms Lipid Whole

Terrestrial plants Lipid Petroleum Coal

Microbial methane Thermogenic methane

Figure 16.9 The δD values of selected materials. (Modified after Kaplan, 1994, p. 301, figure 5.)

16.4.2 Isotopic Values of Gases The origins of biogenic and thermogenic gases can be determined by isotopic gas analysis (the isotopic ratios of carbon and hydrogen). As shown in Figure 16.10, the isotope ratio of carbon (13C/12C) can be plotted versus the isotope ratio of hydrogen (2H/1H or D/H). Clustering of data indicates the type of process in which the methane was formed. The heavy isotopes of 13C and D (deuterium) are the rare species and constitute 1% of all carbon and 150 ppm of all hydrogen, respectively. Small variations in 13C/12C and D/1H ratios can be measured very accurately with modern mass spectrometers. For convenience, ratios are expressed in -notation as part-perthousand (‰) variations relative to the PDB (Peedee Belemnite; carbon) and SMOW (hydrogen) isotope standards as follows: 13

C(‰)

[13 C/12C]sample [13 C/12C]PDB

1

1000

(16.1)

1

1000

(16.2)

and 13

13

D(‰)

[D/1H]sample [D/1H]SMOW

C and D values for a gas may vary widely depending on the origin of the gas (Figure 16.6). Biogenic gases are grouped by the isotope ratios in

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one portion of the graph, whereas the thermogenic gases are grouped in another area. These ratios do not change significantly with repressurization, solution, dissolution, or other physical processes that take place during the gas migration to the surface. Those ratios, which reflect the origin of gases, are stable and independent of reservoir and sampling conditions. Consequently, the ratios are useful as tracers of origin and detection of gas movement from one part of a petroleum reservoir to another. As shown in Figure 16.4, the product of biogenic decomposition is almost all methane. Only small amounts of ethane and heavier hydrocarbons are generated. Although thermogenic decomposition does produce heavier hydrocarbons such as ethane in the earlier stages, in the later stages (higher pressures and temperatures) it also primarily produces methane. According to Price and Schoell (1995), as natural gas migrates from its site of origin to the reservoir traps above, it may fractionate, becoming much richer in methane. Table 16.4 lists typical ranges of isotopes for the biogenic and thermogenic decomposition of organic material. Isotopic ratio yields information on the past history. The composition and the isotope ratios of a gas may help determine the source of the gas. Isotope compositions of light hydrocarbon gases can help identify the origin of surface gas seeps. Gases formed by bacterial alteration of shallow-buried sediments, peats, and organic-rich shales are composed almost entirely of methane. These gases (methane 13C < 60‰) are isotopically light (Table 16.4). Carbon and hydrogen compositions of methane from various sources is presented in Figure 16.10. Jenden and Kaplan (1989) and Jenden et al. (1993) presented a valuable distribution graph of 13C of methane versus number of commercial natural gases (Figure 16.11).

16.4.3 Nonhydrocarbon Gases Poreda et al. (1988) stated that at least two mechanisms are responsible for the origin of CO2 in the subduction gases. Decarbonation or oxidation reactions produce a high-CO2, low-3He/4He gases, whereas high-3He/4He, CO2-rich gas may originate from the mantle. He isotope ratios provide information on the input of magmatic gases into crustal systems. The magmatic He component has a 3He/4He ratio (R) ranging from 0.5 to 3.8 times the atmospheric value (RA); also it has high 3He/ 4He (RA = 0.6 3.9) and low CH4/3He (90%), methane is the major component which determines the value of the compressibility factor for a natural gas mixture. Other hydrocarbon components, e.g., ethane, propane, etc., and diluents found in natural gases also contribute to the overall compressibility factor value for real gas mixtures.

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Fracking 2nd Edition Methane – low-to-moderate pressure range

Compressibility factor, Z

1.0500 1.0000 0.9500 200 F

0.9000 100 F

0.8500 0.8000

0 F

0.7500 –100 F

0.7000 0.6500 0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Pressure, psia

Compressibility factor, Z

Figure 16.16 Methane compressibility behavior example factors, Z, on constant temperature lines vs. low to moderate pressures. (Modified after Savidge, 2000, figure 3.)

2.2000 1.8000 1.6000

–200 F

Hydrogen gas Z values on constant temperature lines vs. pressure

2.0000 Z=

–100 F 0 F 100 F 200 F

Vreal gas Videal gas

1.4000 1.2000 1.0000 1,000

2,000 3,000

4,000 5,000 6,000 7,000 Pressure, psia

8,000 9,000 10,000

Figure 16.17 Hydrogen gas compressibility factor, Z; low to high pressure range. (Modified after Savidge, 2000, figure 2.)

Figure 16.17 shows the compressibility factors for hydrogen gas often found in natural gas. The contributions to compressibility by other gases in the stray gas are generally proportional to their mass concentrations. As the components in a mixture change, there is a corresponding change in their contribution to the compressibility factor. For example, for a given mixture consisting of methane and hydrogen at constant temperature and pressure, the compressibility factor value of the mixture will be a mass average weighted value. A compressibility value for methane gas at various low pressures and temperatures can be estimated using Figure 16.14 (NGSMA, 1957). The compressibility for mixtures of hydrocarbon gases can also be estimated graphically for natural gas knowing only the specific gravity of the gas and using the pseudo-critical temperature and pressure relationships.

Migration of Hydrocarbon Gases 181 The NGSMA (1957) presented Figures 16.18 and 16.19 showing specific gravity of the gas vs. critical temperature and pressure of the mixture. Figure 16.14 can then be used to estimate the compressibility factors for a natural hydrocarbon gas knowing the pseudo-critical values of pressure and temperature of the natural gas.

16.5.4 Density of Water

Pseudo-critical pressure, lb. per sq. in. absolute

Subsurface water generally is not a fresh water, but has dissolved salts within it. The density difference between the water surrounding the gas

700

600

0.5

0.6

0.8 0.7 Gravity of gas (air = 1.0)

0.9

1.0

Figure 16.18 Approximate pseudo-critical pressure as a function of natural gas gravity. Specific gravity of air equals 1.0. Pressure is absolute (pa = pg + 14.7). (After NGSMA, 1957, figure 4, p. 103.)

Pseudo-critical pressure, absolute ( F+460)

450

400

350

0.5

0.6

0.8 0.7 Gravity of gas (air = 1.0)

0.9

1.0

Figure 16.19 Approximate pseudo-critical temperature for natural gases vs. gravity with respect to air. (After NGSMA, 1957, p 103, figure 5.)

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Fracking 2nd Edition 20

16

Na Cl

14 12

MgC

l2

10 8 Vo l

NaCl

Concentration of various salts, precent

18

Mg

SO

um

4

e

6 4 SO 4 Ca

2

MgCl 2

MgSO 4 KCI

I KC

CaSO4

0 2

6

10

14 18 22 26 Density in Be @ 15.5 C

30

34

Figure 16.20 Density of water with various concentrations of dissolved salts, °Be = Baume scale. (Modified after Baert et al., 1996.)

and oil globule at any point reflects the buoyancy forces on the globule propelling it toward the surface. As a liquid, water is almost incompressible and so the density changes little for low changes in pressure. However, changes in salinity and temperature do affect the water density. One can quickly estimate the density of saline water at any depth and temperature by use of density calculators available on the internet. Temperature and salinity are the major factors in determination of the variation of water density as pressure plays a minor role for an almost incompressible fluid. If there is gas within the fluid under pressure, the gas itself is very compressible while the fluid is not. Figure 16.20 illustrates how the density of water varies with the type and concentration of ions in the water. Knowing the concentration of each type of salt, a weighted average density can be approximated for any mixture. The density of pure water is 1000 kg/m3, whereas the density of ocean water at the sea surface is about 1027 kg/m3. A graph (Figure 16.21) to

Migration of Hydrocarbon Gases 183 30

1

D=

1.02

2

D=

1.02

D=

25

D=

3

1.02

24

1.0

D=

25

1.0

Temperature ( C)

20

D=

27

1.0

15 6

.02

1 D=

10

28

D

1.0

D

=1

.02

8

5

=

0 33

34

35

36

37

38

Salinity (‰)

Figure 16.21 Interrelationship among density, temperature (°C) and salinity of water. D = Density of water at a particulatr temperature and salinity, (Modified after Classzone, www.classzone.com/books/earth_science/terc/content/.)

determine the density of water prepared by Class Zone is available on the internet (www.classzone.com/books/earth_science/terc/content/). Figure 16.21 illustrates the interrelationship among temperature, salinity and density. Increasing the salinity of the water (the quantity of dissolved salts) increases the mass of the water per unit volume (density). Temperature also affects the density of seawater by changing the volume of the water. Water expands with higher temperatures and so warmer water has a lower density. Pressure increase has a minor effect on the expansion and contraction of water. To estimate the density of water (Figure 16.21), find the point where the temperature and salinity values for the water intersect. The line on the graph nearest the point of intersection indicates the density of the water.

16.5.5 Petrophysical Parameters Affecting Gas Migration There are several factors that determine the magnitude of the force resisting the upward force of buoyancy, e.g. (1) the radius of the pore

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throats of the rock, (2) the hydrocarbon-water interfacial tension, and (3) wettability. The reliable geological interpretation of the migration of gas through porous media requires knowledge of the petrophysical and reservoir parameters of the formation through which it flows. Petrophysical relationships are based on the laboratory analyses of core samples saturated with formation fluids. Core analyses are conducted under surface (ambient) and subsurface (reservoir) conditions.

16.5.6 Porosity, Void Ratio, and Density Virtually all detrital rocks are porous (i.e., contain void space) to some extent. The relative volumes of voids and solids can be expressed in terms of (1) porosity and (2) void ratio. With few exceptions, geologists and petroleum engineers prefer the term porosity, whereas soils and civil engineers use the term void ratio. It should be pointed out here that the various disciplines in geology and engineering all have distinct sets of nomenclature and symbols for rock parameters. Both porosity and void ratio are related to bulk volume of a rock. Bulk volume, Vb, is defined as the sum of the volumes of the voids or pores, Vp, and the solids, Vs:

Vb

Vp Vs

(16.11)

Porosity, is the ratio of the void space to the bulk volume and is usually expressed in percent:

Vp

100

Vb

(16.12)

When used in an equation, however, the decimal equivalent is usually used, e.g., 0.5 instead of 50%. Comparison charts to aid in visual estimation of porosity are presented in Figure 16.22. Void ratio, e, is defined as the ratio of the voids volume to the solids volume:

e also:

Vp Vs

(16.13)

Migration of Hydrocarbon Gases 185 1%

5%

10%

20%

25%

30%

50%

Figure 16.22 Comparison charts to aid visual estimation of porosity. (Circles after Terry and Chilingar, 1955; squares after Folk. 1951.)

e

(1

)

(16.14)

or:

e (1 e)

.

(16.15)

Obviously, porosity can never exceed a value of 100% or 1.0 (fractional porosity), whereas void ratio often exceeds unity in fine-grained sediments and clays. Figure 16.23 shows the relationship between the void ratio and porosity in the commonly occurring range. Specific weight, , is often used in conjunction with porosity and void ratio. It is defined as the weight per unit volume, whereas density, , is the mass per unit volume and is equal to /g where g is the gravitational acceleration. The term “density”, however, is often used to designate specific weight, which often results in erroneous calculations. Mass, , is attracted

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Fracking 2nd Edition 1.4

1.2

Void ratio, e

1.0

0.8

0.6

0.4

0.2

0

0

10

20

30

40

50

60

Porosity, , %

Figure 16.23 Relationship between void ratio and porosity.

by the Earth with a force = ( g). For example, if the specific weight of water is equal to 62.4 lb /ft3, then the density expressed in terms of slugs /ft3 is equal to 1.94 [= 62.4 (lb/ft3)/ 32.17(ft/sec/sec)]. Bulk specific weight can be either “dry” or “wet” depending upon the nature of the fluid in the pore spaces. The unit weight of dry sand (only air is present in the pore spaces) is equal to:

(1

db

)

(16.16)

s

where db = weight per unit of dry bulk volume, and of solids (grains). The unit weight of wet sand is expressed as: wb

(1

)

s

wb

s

(

s

s

= specific weight

f

(16.17)

)

(16.18)

or: f

Migration of Hydrocarbon Gases 187 where wb = weight per unit of wet bulk volume, s = specific weight of solids (grains), and f = specific weight of fluid in the pores. Quartz sands have an average specific gravity of 2.65 with reference to water [specific gravity = specific weight of a material at 60  °F: (specific weight of water at 60 °F)]. If the weight of one cubic foot of fresh water is assumed to be equal to 62.4 lb, then one cubic foot of solid silica having a specific gravity of 2.65 would weigh 165.4 lb. If one cubic foot of dry sand weighs 137.3 lb, then its dry, bulk specific gravity would be equal to 2.2 (=137.3/62.4). The porosity of this dry sand can be calculated using ( s db ) (2.65 2.2) Eq. 16.16; db = (1 ) s, or 0.17 or 17% If the 2.65 s sand was saturated with water, its bulk specific weight would be equal to the weight of the solids (137.3 lb) plus the weight of the water (0.17   62.4 lb) or 148.06 lb /ft3. It can be easily illustrated on using idealized spheres that porosity is dependent upon the method of packing. If packed cubically, then spheres of equal size would have a maximum possible void space of about 47.6% (Slichter, 1897–1898). If packed rhombohedrally, the porosity is reduced to a minimum of about 26% (Figure 16.24). It is obvious that sphere size Case 1

Case 2

Case 4

Case 5

60 Case 4

90 Case 3

116 .34 60

90 60 60

90

60

90 Case 2

90 Case 1

90

Case 6

90

90 60

90

Case 3

Case 5

90 60

Case 6

Figure 16.24 Several different ways of packing speres. (After Graton and Frazer, 1933.)

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does not change porosity when unit volumes with sides at least 2 radii in length are examined. In nature, owing to variation in size of grains and their angularity, usually the porosity of a sand or sandstone will be less than the values specified for spherical grains. It has also been demonstrated that in a mixture of spherical particles having different diameters, stacking arrangement does affect porosity. The introduction of a second set of spheres, small enough to fit in the pore space between the larger set, can reduce porosity to about 13%. Usually, finer-grained sediments exhibit greater porosity when deposited than coarse-grained ones. A well-sorted, well-rounded, loosely compacted medium to coarse-grained sand may have a porosity of about 37%, whereas poorly sorted fine-grained sand with irregularly shaped grains may have porosity in excess of 50%. An admixture of irregular-shaped, tabular and bladed particles usually gives rise to a higher porosity values because of particle bridging. The wide variability of porosity owing to depositional environment is best illustrated by the greywackes, which may have either a high or a very low porosity value, depending on the amount of fine-grained material filling the pores. Clays and silts may have porosities as high as 50–80% when freshly deposited. The terms “effective porosity” and “total porosity” are often used in petroleum geology and reservoir engineering studies. These terms differentiate between the interconnected pores through which fluids can move and the total pore space, regardless of its ability to transmit fluid. The effective porosity as used in the United States is not really effective. It should be called intercommunicating or open. Real effective porosity is the “effective” porosity (as used in the Western world) minus the irreducible fluid saturation depending on wettability (water or oil), which does not participate in the flow of fluids, and is “hiding” in the dead-end pores and fractures. Thus, we recommend using the term “effective” properly.

16.5.7 Permeability Permeability is the measure of the ability of a porous rock to transmit a fluid under the pressure gradient (differential pressure). The absolute permeability, k, is the ability of a rock to conduct a single fluid (gas, oil, or water) at 100% saturation in the rock pore space with that fluid. Effective/phase permeability is the ability of a rock to conduct one fluid phase (gas, oil, or water) in the presence of other fluid phases. Relative permeability to a fluid is the ratio of effective/phase permeability at a given saturation value  to the permeability at 100% saturation (the absolute permeability). The terms kro(ko/k), krg(kg/k), and krw(kw/k) denote the relative permeabilities to oil,

Migration of Hydrocarbon Gases 189 gas, and water, respectively. The relative permeability is expressed in percent or as a fraction. Permeability is measured by an arbitrary unit called the Darcy, D, which is named after Henry d’Arcy, a French engineer, who in 1856 devised a method of measuring the permeability of porous rocks. One Darcy is 1 cm3 per second of a fluid having viscosity of 1 cP flowing through a 1 cm2 crosssection of rock under a pressure gradient of 1 atm/cm. Because most reservoir rocks have an average permeability considerably 140 °C) which are encountered in deeper wells. With regard to shrinkage, they stated that the current standards for cement are either not well founded or the criteria are based on a flawed view of the mechanism. There is also a need for better quality oilwell cement formulations for higher pressure and/or temperature applications (Dusseault et al., 2000). The significance of shrinkage is that older (>50 years) producing wells, along with the many abandoned wells and coreholes worldwide have an increasing potential for gas leakage as their cement gets older and shrinks. Commonly the way the oilwells are handled, is to plug them, cover them up and then forget about them. These plugs, however, do not last forever because of aging of cement along with corrosion of the metal casing. Thus, there is a likelihood that every oil and gas well will eventually leak.

16.8.3 Improper Placement of Cement It is imperative that the isolation of the oil and gas productive zones by cement (from the upper regions of the wellbore) is properly done. Improper well completion methods can result in a number of pathways for the migration of gas along the wellbore. These include missing cement, channeling of the cement, cracks or fractures in the cement sheath, debonding of the cement to the casing and/or wellbore, and plastic deformation of the cement sheath (Figure 16.41). Some causes for these problems may be the result of poor mud cake removal, shrinkage of the mud cake and/or cement, and cement permeability (Ravi et al., 2002). Bonett and Pafitis (1996) have noted that if during the period of placement and setting of the cement paste within the wellbore, the pressure within the annulus drops below that of the formation, gas will migrate from the formation into the cement paste. This invasion of gas into the cement paste may occur in a number of ways other than simple bubbles. As shown in Figure 16.42, gas may flow through the cement as elongated slugs, etc., which can result in channels within the cement as the cement hydrates and hardens. Bonett and Pafitis (1996) describe this gas infiltration as follows: Stage 1 – The cement slurry is a dense granular fluid and if the hydrostatic pressure is greater than the formation pressure, gas will not enter the cement paste. However, the hydrostatic pressure begins to drop almost immediately because of a combination of gelation, fluid loss and shrinkage of the cement paste. As the cement sets, static gel strength constantly increases, with the rate dependent upon the nature

Migration of Hydrocarbon Gases 221

Microannulus

Channel within cement sheath

Cement sheath about casing Casing Cement Cracks in cement sheath

(a)

Plastic deformation in cement sheath

(b) Area of debonding

Gas or mud cut (c) channels Channel along bedrock Along bedrock/cement Missing cement within cement sheath interface

(d) Along bedrock/casing interface

Figure 16.41 Schematics illustrating the effect of various mechanical problems resulting from improper placement of cement in wellbores. (Modified after Ravi et al., 2002 and Newhall, 2006.)

Rising plume

Direction of gas migration

Interface type

Direction of gas migration

Slug type

Direction of gas migration

Direction of gas migration

Direction of flow of gas migration

Bubble type

Figure 16.42 Schematic illustrating the different ways gas bubbles (light gray) can migrate through cement prior to its setting (dark gray) that can lead to channeling. (Modified after Bonett and Pafitis, 1996, p. 39.)

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Fracking 2nd Edition of the slurry. Space for the gas to enter the slurry is provided by the shrinkage of the cement (dehydration). As the cement cures, opportunity for gas to enter the slurry decreases. Stage 2 – Cement as a two-phase material: During Stage 2, a cement column is fully self-supporting and is a matrix of solid particles with interconnected pores containing a fluid phase. The majority of the shrinkage occurs during this phase. This may initiate fractures and disrupt the bonding of the cement to the casing and/or formation. Internal shrinkage creates a secondary porosity in the cement. Stage 3 – An elastic solid. Once dehydration is almost complete, cement becomes an elastic and brittle material, which is isotropic, homogeneous and essentially impermeable to gas infiltration. At this stage, gas can only flow through the fractures and pathways present in the cement matrix.

Major contributing factors resulting from incorrect placement of cement, which create gas migration pathways during the cementing process, were reviewed by Bonett and Pafitis (1996) in Figure 16.43. Incorrect cement densities can result in the flow of natural gas from the formation into the cement. Poor and incomplete removal of mud cake can result in channels along the formation providing future pathways for gas migration up the annulus. Premature gelation leads to loss of hydrostatic pressure control. Excessive fluid loss from the cement gives rise to additional space in the cement paste for natural gas to enter the cement. Highly permeable slurries result in poor zonal isolation and offer little resistance to gas flow. High cement shrinkage results in increased porosity in the cement sheath that may lead to microannulus. Cement failure under stress results in fracturing of the cement sheath, whereas poor cement bonding to the casing and/or wellbore wall gives rise to channels for gas migration along the wellbore.

16.9 Environmental Hazards of Gas Migration 16.9.1 Explosive Nature of Gas Many petroliferous basins have experienced fires due to migrating hydrocarbon gases. The lower explosive limit (LEL) of hydrocarbon (oilfield) gases (composed primarily of methane) occurs when approximately 5% by volume of gas is mixed with 95% by volume of air. This translates into a serious explosion and fire hazard, especially where the gas is capable of

Migration of Hydrocarbon Gases 223 Wrong density

(a)

Poor mud/filter cake removal

(b) Highly permeable slury

(c)

High shrinkage

(d) Cement

Formation

Premature gelation

(e)

(f)

Cement failure under stress

(g)

Casing Excessive fluid loss

Poor interfacial bonding

(h)

Figure 16.43 Schematics illustrating the effect of various mechanical problems resulting from improper placement of cement in well bores. Arrows indicate direction of fluid flow (gas/liquid). (Modified after Bonett and Pafitis, 1996, figure 1, p. 37.)

migrating into a confined space such as a room or an electrical vault. These hydrocarbon gases are often the result of leakage from gas pipelines and/ or seepage of gas from oilfields. If the explosion (LEL) limit is met, a spark can quickly initiate a fire/explosion. In many areas, homes and commercial structures have been constructed directly over old oilwells that have not been properly sealed, and where mitigation measures have not been taken to seal out the seeping gases.

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16.9.2 Toxicity of Hydrocarbon Gas The U.S. Environmental Protection Agency (EPA) has determined that the primary hazardous air pollutants (HAP) emitted from the oil and natural gas transmission and storage facilities are (Federal Register, Volume 63, No. 25 / Feb. 6, 1998): (a) benzene, (b) toluene, (c) ethyl benzene, and (d) xylenes. These compounds are often collectively referred to as the BTEX chemicals. The BTEX chemicals are common aromatic components of crude oil and gas. A detailed discussion of these hazardous components of crude oil can be found in McMillen et al. (2001). Although crude oil has variable contents of aromatic hydrocarbons, depending upon its origin, the API rating of the crude oil can be a good predictor of the content of aromatics, especially benzene (see Figure 16.44). A general rule is that, the higher the API gravity of the crude oil, the higher the percentage of aromatics in the crude oil. The formula for calculating API gravity is:

API gravity

141.5 131.5. SG

(16.56)

Generally speaking, 40 to 45 API gravity degree oils have the greatest commercial value because they are rich in gasoline. Condensates are worth slightly less because the natural gasoline has a lower octane value. Heavier crudes are worth less because they require more refinery processing. An overall classification of crudes is presented in Figure 16.45. West

Concentration of benzine in oil, mg/kg

105 104 103 102 101 100 0

10

20

30

40

50

60

70

API gravity

Figure 16.44 Benzene concentrations versus API gravity for 61 crude oils and 14 condensates. (Note: API gravity data were unavailable for eight crude oils). Modified after Rixey, 2001.)

Migration of Hydrocarbon Gases 225 Aro% 90

10

80

Aromatic asphaltic

20

70

Aromatic intermediate oils

30 Aromatic naphthenic

40

60 50

50 Paraffinic nepthenic oils

Maturity 40

60

30

70

20

80 Paraffinic oils

10

90

80

70

60

Naphthenic oils

50

40

30

20

Sat%

90

10 Polar%

Figure 16.45 Ternary diagram showing the class of composition of the World’s crude oils. (Modified after Kamali et al., 2012.)

1.050 Extra heavy (Bitumen) – < 10 API

1.000 Density, kg/m3

Heavy crude – < 22.3 API

0.950 API = (141.5/S.G.) - 131.5

0.900

Medium crude – 22.3 to 31.5 API

0.850

Light crude – > 31.1 to 45 API

0.800 0.750 0.700

Condensate – > 45 API

10

50 20 30 40 API specific gravity @ 60 F

60

70

Figure 16.46 API gravity of oil vs density and classification of oil based on API gravity.

Texas Intermediate (WTI) is the benchmark crude oil used by the United States to set prices and compare with other oils. Figure 16.46 shows the composition of various API gravity oils. Tissot and Welte (1978) found that 95% of the crude oils produced around the world fall into the hydrocarbon distribution pattern shown in Figure 16.47.

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Fracking 2nd Edition Aromatics - 100%

95% frequency distribution envelope for world oils

Saturates - 100%

50 % 50 %

50 %

Resins & asphaltenes 100%

Figure 16.47 Ternary diagram showing the class composition of crude oils. (Modified after Tissot and Welte, 1978.)

The majority of the world’s crude oils have been reported to contain 15% to 40% aromatics. These aromatics are characterized by a double carbon bond, which has been directly linked to the health hazards posed by these chemicals. Benzene and toluene, known human carcinogens, have been linked to leukemia, aplastic anemia, lymphomas and a variety of other cancer-related ailments. Oil and gas production facilities handling these potentially dangerous chemicals are required by California law, for example, to provide warnings to the public under the California Health and Safety Code Section 25249.6 (otherwise known as Proposition 65). All facilities must be required to identify the amount or the specific types of chemicals being released to the atmosphere from their operations. The EPA has identified dehydration equipment as a major source of benzene and toluene air toxics emissions, and has proposed legislation to curtail such emissions, especially in residential areas. Venting of oilfield gases to the atmosphere must be viewed as a hazardous activity, not only due to potential fire and explosion danger, but because oilfield gases may contain appreciable levels of benzene and toluene. Oilfield gases and condensates are known to contain aromatics (benzene, etc.). A typical content of benzene in the oilfield gases can vary between 30 parts per million (ppm) to over 800 ppm. For this reason, the natural gas should always be carefully tested for its benzene content before venting to the atmosphere. Also, vent stack emissions should be carefully monitored.

Migration of Hydrocarbon Gases 227 Additional concerns and precautions must always be taken in and around sour (hydrogen sulfide, H2S) oilfield operations. Hydrogen sulfide, even in small quantities, can be toxic (hazardous) to human health. Research conducted at the University of Southern California Medical Facility (Kilburn, 1998, 1999) has established central nervous system damage from the neurotoxin effects of hydrogen sulfide even at concentration in air as low as 1 ppm. This is much lower than the workplace standards that have been considered safe in the past. This also highlights the importance of not relying upon workplace standards regarding air toxics emissions in the case of residential areas and school sites. Safety, health, and environmental considerations need to be made a top priority in the land use planning where urban development coexists with the oilfield and gasfield operations. Many oilfields have a long history of gas migration problems, i.e., explosion, fires, noxious odors, and potential emissions of carcinogenic chemicals such as BTEX. These risks must be seriously examined for all oil and/ or gas operations in urban or developed areas. Although the migration of hydrocarbons has been long recognized, the dangers of fire and explosion were not considered as the primary problem.

16.10 Migration of Gas from Petroleum Wellbores Many petroliferous basins have been plagued with numerous gas seeps from oilfields (migration of gas from hydrocarbon pools to the surface) that present serious explosion and health risks to the overlying population. Oilfield gases have a propensity to migrate upward to the surface along faults and poorly cemented and/or abandoned wellbores. Furthermore, the upward migrating gases can accumulate in the near-surface collector zones, which are often concealed within the shales in the permeable gravel and sand lenses. There is a need to carefully evaluate the integrity of casings in many older oilwells because holes in the casing due to corrosion can serve as a primary source for gas migration to the surface. Also, it should be remembered that the bonds between the casing and formation will break down in time. Early oilwells were not always completed with cement. In some cases  the wellbore was filled and abandoned with a drilling fluid. Furthermore, the early cement utilized in the oilwells drilled prior to the 1950s was not as competent as that which is available today. Recent studies have shown that even under current standards with today’s cements, over 15% of all modern oilwells leak. Many oilwell leaks can be traced to poor

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well completion and/or abandonment procedures, e.g., poor cementing practices. The writers estimate that the life of cement before deterioration is about 50 years. Gas migration from the subsurface hydrocarbon pools into inadequately cemented wellbores, with the resultant leakage to the surface, has been a persistent problem in the oil and gas industry for many years. In the case of gas storage reservoirs, pressure and temperature cycling on the cement bonding of wells is an acute problem and can give rise to shoe leaks and loss of bonding between the formation and well casing. To help quantify the annular leakage problem in gas storage wells, a survey was prepared and sent to the American Gas Association’s Pipeline Research and Storage Reservoir Supervisory Committee. The survey attempted to determine the magnitude of the annular leakage problem (Marlow, 1989). Tests showed that even when the most up-to-date cement types and techniques are used, leakage can and will occur in a significant number of cases (Marlow, 1989, pp. 1147, 1148). For example, in a study of 250 well casing jobs over a 15-month period with current cement, 15% of the wells leaked (Waiters and Sabinas, 1980). Many wells are capable of giving rise to very serious environmental problems associated with gas migration to the surface. Even low concentrations of hydrogen sulfide in the gas can further destroy the integrity of both steel and cement. The corrosive action of hydrogen sulfide has defied engineering solutions (Craig, 1993). The topic of corrosion is further discussed in Chapter 6.

16.10.1 Effect of Seismic Activity Seismic activity is another factor in contributing to the well integrity problem, e.g., in the Los Angeles Basin, CA, the 1971 Sylmar earthquake was responsible for damaging well casing and cement bonding in several oilfields resulting in well blowouts in the Fairfax area (Salt Lake Oilfield) (Khilyuk et al., 2000). It is important to do a systematic examination of the condition of all wells in a field after seismic events to determine the extent of damage to the well casings. If each well leak is only evaluated individually and as an isolated example, without examining the field history and other wells, the true dangers to the public may not be recognized.

16.11 Case Histories of Gas Migration Problems This section is a review of many case studies illustrating the potential environmental problems inherent with oilfields in developed urban areas. In the

Migration of Hydrocarbon Gases 229 case of the Salt Lake Field, for example, gas migrated along the faults and/or wellbores resulting in the Ross Dress for Less department store explosion, Los Angeles, CA. Toth (1996), in his study of the hydrology of this area, noted that the underlying permeable aquifers for this basin can conceal the true magnitude and hazard of lateral gas migration away from the reservoir itself. In the case of Hutchinson, KS, gas migrated horizontally about 7 miles through aquifers from where the explosions and fire occurred within the city. A review of well abandonment records for the Los Angeles Basin for example reveals the potential problem of very serious leakage of gas from wells that were abandoned prior to the use of cement and/or to current standards of completion. Many of the wells within the Los Angeles Basin, CA, were drilled prior to the 1970s, when current cementing standard practices were not used to insure proper placement of the cement and segregation of the productive zone from the wellbore to prevent gas migration. For example, in the Montebello Oilfield (utilized as a repressured gas storage reservoir), several older wells that had been abandoned to make way for a new housing development, were found to be leaking gas to the surface and under the new homes. In order to reabandon the leaking wells under these homes, the homes were torn down, the wells reabandoned and the land where the home had stood was converted to a mini-park. Building a house over an abandoned well is like building a house over a potential “volcano.” Most construction over old wells fail to provide gas detection or other mitigation measures (e.g., as required by the Los Angeles City Methane Ordinance, 1985) in order to deal with potential gas migration hazards. For example, the underground gas storage operations at Playa del Rey involved injection of storage gas under high pressure ( 120 kg/cm2). Gas inventory studies (Tek, 1987) have shown that leakage is directly proportional to the reservoir pressure maintained for gas storage (Figure 16.48). According to Tek (1987), a gas reservoir after repeated pressure cycling begins to break down and leak gas after 50 years. It is paramount to realize that repressured wells often leak gas. Proper procedures for continuous monitoring for leaking gas must be developed for gas storage reservoirs in urban areas. The gas storage pressures are typically selected by the operator to maximize the storage volume, and to enhance retrievability of the stored gas when market demands (usually during cold spells when demand for gas increases). According to Khilyuk et al. (2000), what often is not considered when repressuring the reservoir is: (1) the potential creation of new fractures within the reservoir if the pressure exceeds the current strength of the reservoir rock, (2) fluid leakage along the faults when they open up as the formation is repressured, (3) the mechanical condition of the aging active wells that

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120 Leak rate from data

Leak rate, mmcf/yr

100 Case III Leak rate conservatively estimated from computer history match (coats)

80 Case II

From field data 60

40 1740

Case I

Runs from computer simulation cases, I, II, III

1800 Maximum pressure, psia

Figure 16.48 Gas leak rate for various maximum reservoir pressures for the Leroy Gas Storage Project. (Modified after Tek, 1987, figure 11.16.)

may not have been designed to isolate the formation from the wellbore under the new pressures, and (4) the existence of a cement barrier isolating the cyclic repressurizing zone for those wells that penetrate or pass through the repressurized interval and all coreholes and abandoned wells that penetrate the repressurized interval. In addition, the operator must continuously monitor the surface soil for leaking gases.

16.11.1 Inglewood Oilfield, CA The Inglewood Oilfield consists of nine major groupings of layers or pools of intermixed oil and water aquifers located about 9 miles west of the center of Los Angeles, CA. The field, as shown in Figure 16.49, is a faulted anticline. A major fault, the Newport-Inglewood, bisects the field. The reservoir thickness for the total field is over 8,000 ft of alluvial Pliocene and Miocene sediments with the average depth of pools ranging from 950 to 8,400 ft. The discovery well was drilled in 1924. Over 693 wells have been drilled in this field. Many of these well were drilled prior to the 1950s when cementing practices were not recorded or regulated by today’s standards. As the property values were increasing there was interest in developing the property above the Inglewood Oilfield. This field has a history of

Migration of Hydrocarbon Gases 231

Newport fault A

B

A Upper investment Investment

p To

of

tto pe re

B

U.I.

Newport fault

U.I.

ers o Vickachad m zone ge Rind zone

V. M

.

Rubel ne zo

P Milioce oc ne en e

Moynier zone

Figure 16.49 Inglewood Oilfield, CA; contours on Vickers-Machado zone. (After California Division of Oil and Gas, 1961, p. 576.)

inadequately abandoned wells leaking fluid (gas and liquids) to the surface during the waterflooding of the Vickers zone. There is also a record of water passing through fault planes within the Vickers waterflood at differential water pressures greater than 150 psi. A large housing development was proposed for the Baldwin Hills area with high retaining walls contemplated to enhance views of the buildings. This project was halted and the property later sold to the State of California for use as a public park (Chilingar and Endres, 2005).

16.11.2 Los Angeles City Oilfield, CA The Los Angeles City Oilfield consists of three shallow major groupings of layers of oil and water aquifers located about 1 mile north of the center of

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Los Angeles, CA. The field, as shown in Figure 16.50, is a shallow faulted homocline. The total thickness of sediments is about 1,500 ft of alluvial Miocene deposits with the average depth of reservoir pools ranging from 375 to 1,700 ft. The discovery well was drilled prior to 1892. About 1,250 wells have been drilled in this field. Almost all the wells were drilled prior

Figure 16.50 Los Angeles Oilfield; contours on top of the 1st Oil Sand. Productive area is shaded. (After California Division of Oil and Gas, 1961, p. 598.)

Migration of Hydrocarbon Gases 233 to the 1950s and not abandoned by today’s standards with many abandoned without the use of cement. Intense residential and commercial development has occurred over this old field and abandoned wells. There is evidence of natural gas leaking to the surface from the reservoir throughout the area.

16.11.2.1

Belmont High School Construction

The Belmont Learning Center, previously proposed to be a high school in downtown Los Angeles, CA, was constructed over the Los Angeles City Oilfield. The site chosen was on a 0.14 km2 parcel of land. This location is over the shallow oilfield that has a surface outcrop just north of the building site. The area is also over part of the Elysian Park blind thrust fault system that has a generally east-west trend, which helps explain the uplifting and tilting of petroliferous formation depicted in Figure 16.50. There are oilwells in the area producing from shallow oil deposits at a depth of no greater than 213 m. Most of the wells producing oil today were drilled in the early 1900s, and lack a proper cement completion to isolate the producing formation from the wellbore. Although the gas production is minimal, all of the produced oilfield production gases are released to the atmosphere in the residential area above the wells. This includes four operational wells at the northwest corner of the school property. Environmental studies were undertaken only after construction began. These studies revealed oilfield gas seepage to the surface over most of the 0.14 km2 parcel and the surrounding area, including the area directly under the proposed school buildings. The project was abruptly halted when gas seepage was detected in the main electrical vault room of the project, just before the power was to be energized. Soil gas studies revealed that methane (explosive levels) and other gases are migrating to the surface, including toxic gases such as hydrogen sulfide. Measurements at the surface revealed releases to the air of over 300 parts per million (ppm) of hydrogen sulfide (Endres, 1999, 2002). Investigation in the area revealed that the gas migration to the surface is common throughout this area. After a lengthy discussion, the project was completed and used as an administrative center rather than a school site. This case history clearly identifies the caution required in evaluating the environmental suitability of developed sites located over oilfields where there are migrating hydrocarbon gases, especially in the case of school construction. The State of California has passed recent legislation that requires direct participation by the Department of Toxic Substances Control (DTSC) in the future school site selection process in order to avoid a repeat of the Belmont failure.

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16.11.3 Montebello Oilfield, CA The Montebello Oilfield consists of 13 major groupings of layers or pools of oil and water aquifers located about 5 miles east of the center of Los Angeles, CA. As shown in Figure 16.51, this field consists of a Main and West area anticline and East area faulted anticline area. The overall thickness of the deposits is about 6,000 ft of alluvial Pliocene and Miocene sediments with the average depth of pools ranging from 2,200 to 7,000 ft. The discovery well was drilled in 1917. Over 629 wells have been drilled in this field, many prior to the 1950s when cementing practices were neither regulated nor recorded. Overlying this oil field is a dense, highly developed, residential area.

16.11.3.1 Montebello Underground Gas Storage The partially depleted 8th zone of the Montebello Oilfield (at a depth of 2,236 m) was converted into an underground gas storage operation. Natural gas was transported to the field through interstate pipelines and injected under

Depth, ft 2000’ 4000’ 6000’

Figure 16.51 Montebello Oilfield; contours on top of the 8th zone. (After California Division of Oil and Gas, 1961, p. 606.)

Migration of Hydrocarbon Gases 235 high pressure (exceeding 105.6 kg/cm2) into the 8th Zone pool. Methane gas was discovered at the surface coming out around several well wellheads and under existing dwellings. Investigation revealed that this gas had migrated from the gas storage reservoir to the surface though wellbores that had been drilled in the 1930s and, possibly, along faults. In several instances, homes which had been built over abandoned wells had to be torn down in order to provide access for drilling rigs to reabandon wells that were a pathway for gas migration to the surface. Further investigation revealed that the cement used in some of the older abandoned wells was not adequate to seal off the repressured storage gas in the reservoir. After several years of problems with the migration of gas and reabandoning leaking wells, this facility was abandoned.

16.11.4 Playa Del Rey Oilfield, CA The Playa Del Rey Oilfield, CA, consists of two major groupings of layers or pools of oil and water aquifers located about 13 miles southwest of the center of Los Angeles. This field, as shown in Figure 16.52, consists of an Upper and Lower zone and is an anticline over a basement high. There are about 2,000 ft of alluvial Pliocene and Miocene sediments, with the average depth of pools ranging from 4,000 to 6,400 ft. The discovery well was drilled in 1929. Over 320 wells have been drilled in this field and many when cement was not used or when cementing practices were neither regulated nor recorded. Overlying this oilfield is a dense, highly developed, residential area. Oil production in the Venice area of the Playa Del Rey Field began in 1929. This area has produced 82% of the oil production of this field. A large reduction in reservoir pressure occurred from 1929 to 1944, when the initial pressures of 1900 psi decreased to about 100 psi. Nearly all of the oil wells in the Venice area have been abandoned and there is currently little subsidence due to hydrocarbon withdrawal; however, environmental problems exist because of water extraction from the aquifer in the area causing subsidence and potential problems of gas migration through the improperly abandoned wells.

16.11.4.1 Playa Del Rey underground Gas Storage The older wells in this field were drilled, completed, and abandoned prior to the 1950s, which today are vulnerable to the problems of gas migration as a result of: (1) a breakdown of aging of the cement about the wellbore along with additional the chemical breakdown weakening the cement seal between the formation and the wellbore. (2) Many of the earlier wells had no cement as a protective barrier. (3) Breakdown of earlier cements as a

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Depth, ft 4000’

6000’

Figure 16.52 Playa Del Rey Oilfield with contours on top of schist conglomerate. (After California Division of Oil and Gas, 1963, p. 634.)

direct result of seismic activity (earthquakes). (4) Movement along the faults bending or shearing the casing. (5) Holes in the casing due to corrosion. The condition of these older wells in the Del Rey Hills area (see Figure  16.53) is especially critical, because the reservoir underlying this area is now being used to store high-pressure gas (Lower Zone). There is a potential for repressured gas to migrate up from the Lower Zone along many potential vertical pathways and contaminate the upper fresh-water sands in the area as it moves toward the surface. A portion of the Lower Zone of the Playa Del Rey Oilfield was converted to an underground gas storage operation about 1942. As shown in Figure 16.53, the Venice Oilfield adjoins Playa Del Rey Oilfield to the immediate north. This gas storage reservoir located in the Del Rey Hills area has been laterally

Migration of Hydrocarbon Gases 237 0

2000

4000 feet

Marina del rey

Playa del rey oil field

Playa del rey gas storage unit Venice oil producing area

Figure 16.53 Playa del Rey Oilfield showing location of oil-producing areas and gas storage reservoir. (In: Chilingar and Endres, 2006, figure 4.)

leaking (stored gas) into the adjoining Venice Oilfield since the early years of the gas storage operation (Riegle, 1953). There are over 200 abandoned wells throughout this area, including those wells that had to be abandoned in order to accommodate the construction of the Marina Del Rey Boat Harbor. Many of these wells, which were drilled prior to the 1950s, were not cemented and are located directly below the main surface channel that connects to the Pacific Ocean. Numerous gas seeps at the surface have been observed by the authors of this book within the boat harbor, around the homes in the marina, and in the Ballona Flood Control Channel. Historically, the Los Angeles River was responsible for depositing a massive gravel layer that extends eastward, providing a highly permeable collector zone. This Gravel Zone begins below the surface sediments at a depth of approximately 15 m (sometimes also referred to as the “15-meter Gravel”) and extends to a depth of several hundred feet. The Gravel Zone interconnects many of these wells in the area providing a pathway for gas migration and serves to conceal the identity of those wells that are experiencing the worst leakage. Gas fingerprinting has established that the leaking well gases match the stored reservoir gases seeping to the surface along the flood control channel and into the surrounding residential areas. This Gravel Zone is

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saturated with hydrocarbon gases, which are additionally pressurized during the heavy rains. At this time, surface gas seeps can be observed bubbling through the surface brackish water. Probes placed into the 15-meter Gravel Zone have measured gas flow rates as high as 20 to 30 L/min (Chilingar and Endres, 2005). Also, drilling rigs have experienced blowouts as a result of encountering the high-pressure gas zone when drilling to a depth of 15 m.

16.11.5 Salt Lake Oilfield, CA The Salt Lake Oilfield, CA, is located in Los Angeles, east of the town of Beverly Hills. This field consists of four major groupings of layers or pools of oil and water aquifers and is a stratigraphic trap along two plunging anticlinal noses (Figure 16.54). There are about 1,000 ft of alluvial Pliocene and Miocene sediments with the average depth of pools ranging from 1,000 to 2,850 ft. The discovery well was drilled in 1902. Over 500 wells have been drilled in this field, many when cement was not used or when cementing practices were neither regulated nor recorded. Overlying this oilfield is a dense, highly developed residential area and the La Brea Tar Pits are a portion of this area. The tar pits are an excellent example of fluids (oil and gas) migrating up along a fault to the surface. After a rainfall in this area, one can observe small bubbles of gas and oil breaking out in surface cracks in the sidewalks and paved areas. The urban area above the Salt Lake Field has had a history of migrating gas, fires and explosions.

16.11.5.1 Ross Dress for Less Department Store Explosion/Fire, Los Angeles, CA A very serious urban problem due to oilfield gases migrating to the surface, igniting and causing an explosion in the La Brea Tar Pits area occurred on March 24, 1985, at the Ross Dress for Less department store, in the Fairfax area of Los Angeles, CA. This incident resulted in an explosion and fire for several days, that could not be extinguished, injuring over 23 people (Cobarrubias, 1985). The fire was fed by escaping migrating natural gas through cracks in the paved areas. This area was across the street from the La Brea Tar Pits. Investigation revealed that in another nearby area there was a large quantity of subsurface gas migrating to the surface under the Hancock Park Elementary School, located on Fairfax Street near 3rd Street. The complex pathway for gas migration to the surface included the (1) 3rd Street Fault, (2) an abandoned well and (3) a shallow collector zone (large pocket) of trapped oilfield gas at a depth of approximately 10 m with

Migration of Hydrocarbon Gases 239

Figure 16.54 The cross-section and structure of the Salt Lake Oilfield. (After California Division of Oil and Gas, 1961, p. 652.)

pressures of approximately 1.8 kg/cm2. This collector zone had sufficient porosity and permeability to serve as a secondary trap for a large quantity of upward migrating gases. A clay layer over the secondary trap served as a seal until its threshold pressure was exceeded. After the Ross store explosion, permanent soil gas probes were installed to a depth of approximately 4.6 m penetrating this clay layer in order to perform degassing of the collector zone and as an ongoing monitoring of the migrating gases. Near-surface soil gas studies revealed that the highest concentrations of gases were aligned in an elliptical pattern with the semi-major axis having an exact alignment with a nearby well (the Metropolitan #5 well). Well production records of this well revealed that it was the largest gas producer from the underlying Salt Lake Oilfield. Well records revealed that the well

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casing had developed leaks as a result of corrosion, located at depths beginning approximately at 1,100 ft (366 m) (Endres et al., 1991; Khilyuk et al., 2000). The major migration gas pathways were the wellbore of Metropolitan Well #5, and the 3rd Street Fault. Another migration path to the surface for the migrating gas was traced to an abandoned Well #99. To remedy the problem, a vent well was drilled into the collector zone in the parking lot of the Ross store to vent gas to the atmosphere. Detailed gas fingerprinting, primarily utilizing isotopic gas characterization, showed that the Fairfax explosion and fire were caused by migrating gases escaping from the underlying Salt Lake Oilfield (Figure 16.55, Schoell et al., 1993). Identification of migrating gases in the surrounding area revealed that the gas seeps at the adjacent La Brea Tar Pits had resulted from the upward migration of gases from the Salt Lake Field along the 6th Street Fault (Jenden, 1985). The 6th Street Fault slopes downward toward the north and intercepts the oilfield reservoir at the location of the Metropolitan Well #5. Jenden (1985) showed (fingerprinting) that the gas seeps at the La Brea Tar Pits match the leaking gases that caused the Ross department store explosion.

16.11.5.2

Gilmore Bank

On February 7, 1989, a pedestrian walking by the Gilmore Bank building, located across the street from the 1985 explosion site, observed gas bubbling out of the ground in an outside flower planter box. The fire department was immediately called, which led to the discovery of areawide gas seeps emerging from the cracks in the sidewalks. Investigation showed that the Anthony ventwell (the well-used to alleviate pressure in the collector zone for the 1985 fire) had become plugged and no longer bled the migrating gas from the collector zone. The area

Methane Ethane

Surface seeps

Propane

Relief well Salt lake field production –45

–40 –30 13

–25

–20

C (‰)

Figure 16.55 Carbon isotope fingerprinting of migrating gas leaking from a shallow Salt Lake Oilfield. (After Schoell et al., 1993, p. 7, figure 8.)

Migration of Hydrocarbon Gases 241 was immediately cordoned off to prevent ignition/explosion of the gas. The ventwell was cleaned out and the migrating gas again vented to the surface.

16.11.5.3

South Salt Lake Oilfield Gas Seeps from Gas Injection Project

In January 2003, serious gas leakage was discovered in the residential area near the Fairfax area (viz., in the vicinity of Allendale St. and Olympic Boulevard, Los Angeles, CA). The oilfield operator had been injecting natural gas into the South Salt Lake Oilfield for approximately 2 years, under elevated pressures to enhance recovery. Gas began leaking to the surface along abandoned and poorly completed wellbores. In fact, the Division of Oil and Gas records reveal that numerous wells had been drilled and completed in this area before the official well records were maintained. Consequently, the existence and abandonment status of some of these wells is unknown. High-density urban development, largely of apartment buildings, has occurred directly over many of these improperly abandoned older wells.

16.11.5.4

Wilshire and Curson Gas Seep, Los Angeles, CA, 1999

A very serious gas seep at the intersection of Wilshire and Curson streets (south of the La Brea Tar Pits) was discovered in 1999. This required the City of Los Angeles to install a vent pipe on the southwest corner of this intersection in order to direct the oilfield gases into the air above the adjoining threestory commercial building. The odors from the gas emitted from the vent pipe were noticeable throughout the area. The commercial office building to the immediate east of this seep location experienced gas odors. A ventilation system is now operating 24 hr/day within the subterranean parking structure of that building in order to mitigate against the risk of an explosion. Historical records of the area, reviewed by the writers, revealed that an old abandoned well had been drilled near the location of this seep. However, the high-density commercial development in the area has prevented finding the exact location of the well.

16.11.6 Santa Fe Springs Oilfield, CA The Santa Fe Springs Oilfield consists of 10 major groupings of layers or pools of oil and water aquifers located about 12 miles southeast of the center of Los Angeles. The structure of this field is a dome (Figure 16.56). The overall thickness of the deposits is about 7,000 ft (alluvial Pliocene and

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Miocene sediments) with the average depth of pools ranging from 3,580 to 9,100 ft. The discovery well was drilled in 1919. Over 1,283 wells have been drilled in this field and many when cement was not used or when cementing practices were neither regulated nor recorded. Overlying this oilfield is a dense residential area. Earth Engineering, Inc., Fallbrook, CA, conducted a study for the City of Santa Fe Springs, CA, to determine the migration of gas and integrity of the oilwells in the Santa Fe Springs oilfield in the 1990s. To facilitate this study, a time period was selected after heavy rains in which the well cellars were partially filled with water. This allowed the observation of migrating gas bubbles in the producing well cellars which were seeping to the surface along wellbores and casings. The results were systematically recorded for more than 50 wells in this field, some of which were used for waterflooding operations at pressures approaching 84.4 kg/cm2. Approximately 75% of the wells surveyed were found to be leaking small amounts of gas.

Figure 16.56 Structure and cross-section of the Santa Fe Springs Oilfield. Contours on the top of the Bell Zone. After California Dvision of Oil and Gas. 1961, p. 662.)

Migration of Hydrocarbon Gases 243 Waterflooding for enhanced oilfield recovery can be a dangerous practice if one does not monitor the maximum injection pressures at which the hydraulic fracturing of the formation and sheaths of cement in the wellbore can occur. These fractures could create new pathways for the migration of gas toward the surface. Repressurization of an oilfield by way of

Figure 16.57 Contours on top of Cascade zone and structure for the Castaic Hills Oilfield, CA. (After California Division of Oil and Gas, 1974.)

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water or gas injection requires careful examination of the age and integrity of the cement for the producing, injecting and abandoned wells throughout the oilfield. A soil gas monitoring program must be implemented in the vicinity of each well and surface fault to define the overall leakage of gas to the surface.

16.11.7 El Segundo Oilfield, CA The El Segundo Oilfield has a depth of about 3,000 ft. Gas that was stored in the early 1970s, migrated into the adjoining geologic formations. Gases were detected in a nearby Manhattan Village, CA, housing development that was under construction. As a result, the construction was stopped. To protect the housing development, a $750,000 passive venting system was installed to prevent the buildup of gases, which may cause an explosion, and the injection project was shut down.

16.11.8 Honor Rancho and Tapia Oilfields, CA Castaic gas storage is located in the depleted Castaic Hills Oilfield (Figure 16.57) near the producing Honor Rancho (Figure 16.58) and Tapia (Figure 16.59) oilfields. Figure  16.60 shows the relationship of the three oilfields. The arrows show the direction of gas migration. The Tapia oilfield producing zone has an average depth of 1,050 feet. The Honor Rancho has several producing levels ranging from an average depth of 3,800 to 6,400 feet. Gas from the gas storage project broke into producing wells of the Honor Rancho and Tapia oilfields. Indications of gas migration along faults at the surface included killing of oak trees along the surface trace of faults in the area. Gas bubbles were also noted in a nearby water reservoir. The helium content identified the migrating gas as originating from the gas storage project at the Castaic Field because the native natural gas has very low helium content, whereas the imported gas from Texas does contain helium.

16.11.9 Sylmar, CA — Tunnel Explosion In 1971, a tunnel (approximately 5 miles long) in the Sylmar area of Southern California was being excavated for a future water project. The excavation had proceeded uneventfully until the tunneling machine encountered a fault plane. The fault was filled with natural gas that had migrated from a nearby oilfield. Natural gas from that oilfield had migrated along the fault

Migration of Hydrocarbon Gases 245

Figure 16.58 Contours on top of Wayside A Sand and Gabriel Sand along with structure for the Honor Rancho Oilfield. (After California Division of Oil and Gas, 1974.)

plane and had filled the fault zone. The tunneling machine, upon contacting the gas-saturated fault zone, set off an explosion. Consideration of gas-saturated fault zones had not been a part of the design of this project. Seventeen workers were killed in the explosion.

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Figure 16.59 Contours on top of the Yule Sand and structure of the Tapia Oilfield, CA. (After California Division of Oil and Gas, 1974.)

Migration of Hydrocarbon Gases 247 Castaic hills

Charlie canyon (Abd) Tapia Wayside canyon Honor rancho

Figure 16.60 Physical relationship of the Castaic Hills, Honor Rancho and Tapia Oilfields, CA. Arrows show the prevailing direction of gas migration. (After California Division of Oil and Gas, 1974.)

16.11.10 Hutchinson, KS — Explosion and Fires A natural gas explosion destroyed part of the downtown area of Hutchinson, KS, on January 17, 2001. The next day, a second natural gas explosion under a mobile home park, outside of the city, occurred killing two people. The migrating gas and the associated gas created additional gas-water geysers reaching heights of 30 feet. The source of the gas leaks was traced to an underground repressurized natural gas storage reservoir located in a prior oilfield. This prior oilfield was located nearly 7 miles from the site of the explosions. The gas had migrated from the reservoir, through faults into a permeable water aquifer. The water, in turn, carried this gas to the explosion site. Investigation has revealed that virtually no monitoring was in place in order to prevent this disaster. The emergency response teams initially had no clue as to the cause of disaster. For example, the fire department was unable to extinguish the flames, illustrating the lack of preparedness for such an event. In the case of the 1985 Fairfax explosion, the fire department had been called and had responded to gas odors in the area 30 minutes before the explosion.

16.11.11 Huntsman Gas Storage, NE Located in southwestern Nebraska, the Huntsman Gas Storage Field was a depleted 4,800-ft deep gas field prior to its conversion to gas storage. Gas leakage occurred from this field into the adjoining oil- and gasproducing field several miles away. A different company handled production. In this case, a large lateral gas migration occurred through the barrier (fault), which several experts had thought to be impermeable. The gas company purchased gas from the oil company. In fact, they purchased the migrating gas several times over, as the gas was recycled between the  two fields. Isotopic analysis proved that the gas company was purchasing its own gas.

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16.11.12 Mont Belvieu Gas Storage Field, TX In October 1980, a serious gas leak developed in a salt dome gas storage field beneath Mont Belvieu, TX, located 33 miles east of Houston. The gas seepage was detected when an explosion ripped through the kitchen in a house. This explosion occurred when the homeowner turned on the dishwasher and the spark of electricity ignited the gas mixture. More than 50 families were evacuated from their homes as a result of the explosion caused by the gas leak. A flash fire caused by the gas that had seeped into the home burned the housewife. The gas consisted of a mixture of ethane and propane with traces of butane. The concentration of these gases ranged from 2% to 14% by volume. The gas storage company had noted an “unexplained” drop in the reservoir pressures in September 1980. The event caused severe financial difficulties for the city, which paid for housing and lodging of the displaced families. Isotopic gas identification results showed that the source of gas was the gas storage facility.

16.11.13 Leroy Gas Storage Facility, WY The Leroy Gas Storage project lies about 100 miles northeast of Salt Lake City. Shell Oil Co. drilled the first well in the summer of 1951. After testing, it was decided that the Thaynes would be a good storage formation (Figures 16.61 and 16.62). Additional wells were drilled and completed in 1970 through 1972. The Federal Power Commission approved this storage project on November 17, 1972. Gas migration to the surface was first confirmed during the latter part of November 1978 through bubbling of gas in a nearby creek and pond. The gas migrated from the reservoir and was trapped in a secondary collector formation (Figure 16.63). The gas leaked from this storage to the surface and was, overall, a result of corrosion problems in wellbores and migration of gas along the fault plane. The gas leakage was confirmed by identification of the formation of bubbles in the adjacent creek and pond. The rate of gas loss to the project was estimated to be (Tek, 1987, p. 323):

q1

3.74 10 7 ( p2g

2 n

)

(16.57)

where q1 is the daily leak rate in MMCF/D and pg is the maximum gas bubble pressure in psia. The exponent n was assumed to be equal to 1.0. The variation of leak-rate versus formation pressure is shown in Figure 16.48.

Migration of Hydrocarbon Gases 249 R117W Well no. 14

Well no. 10

28

Well no. 15 Well no. 4A Well no. 4 Well no. 5 d Well no. 11 a Well no. 3 lro ai r c cifi pa Well no. 9 n io Un Leroy camp 33 Ler oy roa d

T16N

Well no. 6

Muddy creek

Well no. 7

Well no. 12

Well no. 8

Well no. 2

Figure 16.61 Surface map illustrating road (solid lines) and well locations for the Leroy Gas Storage Project, WY. (After Tek, 1987, figure 11.7, p. 316.)

16.12 Conclusions The history of environmental problems throughout the world has demonstrated the need to exercise a high degree of vigilance. Subsidence and gas migration are common to all oilfields, Land use planning and governmental decisions regarding allowing massive real estate development over and adjacent to the oilfields has often ignored the health and safety risks to the public posed by these operations. The most important lesson to be learned from these problems is the need to carefully evaluate and continue to monitor all wells which can serve as the primary pathways for the migration of oilfield gases to the surface; and be aware that the faults can provide pathways for the migrating gases. In order to exercise a high degree of vigilance regarding the environmental hazards posed by oilfield operations, it is necessary to take the following steps:

Nugget

6000 Knight Twin creek

Ankareh

Nugget sandstone

Thaynes

Jurasic

Knight Twin cree k

Tertiary

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4000

Woodside

Ankareh

Dinwoody Phosphor ia

2000

Amsd en Madison

Woodside Dinwoody Phosphoria

Weber

Triassic

Thaynes

Weber

Permian

250

Figure 16.62 Lithologic cross-section and stratigraphic sequence of the Leroy Gas Storage Project, WY. (After Tek, 1987, figure 11.8, p. 317.)

B(t) Surface Seepage Imperfect collector zone A(t), leakage

Storage area Aquifer

Thaynes aquifer

A(t) = cp (pg2 – p2o)n

Figure 16.63 Schematic representation of gas leakage from the Leroy Gas Storage Project. cp = performance coefficient for leak, MMCF/D/psi2, Po = maximum storage pressure, psia. After Tek, 1987, figure 11.12, p. 323.

Migration of Hydrocarbon Gases 251 1. Gas migration monitoring: Close attention must be given to the need of ongoing monitoring for gas migration into the near-surface soils and under developed areas that are impacted by historical oil production. This is particularly true where there are many old and abandoned wells drilled prior to the 1950s. Cement was often not used in many of these older wells and even when used in wells drilled prior to the 1950’s, was of a poorer quality and breaks down with time. It is also very important to monitor gas migration near the fault zones. 2. Soil and groundwater monitoring: Soil and groundwater should be carefully evaluated at construction sites for toxic contamination before development is allowed to proceed. This requires an evaluation of the underlying aquifers, which become a ready target for the oil and gas contamination. It is also necessary to determine what mitigation measures may be necessary to protect against migration of explosive and sometimes toxic oilfield gases into residential and commercial structures. This will be an ongoing problem in many areas that must employ gas detectors, vent pipes, membrane barriers and ventilation systems in order to protect against the gas migration hazards. 3. Air toxics monitoring: The release of toxic material from hydrocarbons from all surface operations, wellheads and pipelines must be carefully monitored and recorded in order to protect the public health, especially from the release of such chemicals as benzene, toluene, ethyl benzene, xylene (viz., the BTEX aromatic hydrocarbons) and hydrogen sulfide. Monitoring of toxic emissions is also required in the operation of vapor recovery equipment (release of gases to the atmosphere). Analysis of all produced gases should be made and recorded in order to be aware of any toxic hazards and to take corrective action. 4. Prohibition of building over and near abandoned wells: No construction should be allowed over any abandoned wellbore or corehole. Prior to permitting any construction, all oil and gas wells near a proposed construction site must be carefully evaluated. 5. Land planning: Issuance of new building permits should require adequate room to provide access for a drilling rig to reenter old wells, if and when they begin leaking gas.

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Santos, R. G., Loh, W., Bannwart, A. C., and Trevisan, O. V., 2014. An overview of heavy oil properties and its recovery and transportation methods. Braz. J. Chem. Eng. vol. 31 no. 3, São Paulo July/Sept.  Savidge, J. L., 2000. Compressibility of Natural Gas, internet: help.intellisitesuite. com/Hydrocarbon/papers/1040.pdf, 26 pp. Schoell, M., 1983. Genetic characterization of natural gases. AAPG Bull., 67:2225–2238. Schoell, M., 1988. Multiple origins of methane in the earth. Chemical Geology, 71:1–10. Schoell, M., Jenden, P. D., Beeunas, M. A. and Coleman, D. D., 1993. Isotope analysis of gases in gas field and gas storage operations. SPE No. 26171, SPE Gas Technol. Symp., Calgary, Alberta, Canada, June 28–30, pp. 337–344. Schowalter, T. T., 1999. Mechanics of Secondary Hydrocarbon Migration and Entrapment, AAPG data pages, http://www.searchanddiscovery.com/documents/97018/mechan.htm Schumacher, D. and Abrams, M. A. (eds), 1994. Hydrocarbon Migration and Its Near-Surface Expression. AAPG Mem. 66:360 pp. Serruya, C., Picard, L. and Chilingarian, G. V., 1967. Possible role of electric currents and potentials during diagenesis (Electrodiagenesis). Sediment. Petrol., 37:695–698. Smith, J. E., Erdmn, J. G. and Marris, D. A., 1971. Migration, accumulation and retention of petroleum in the earth. In: Proc. 8th World Petroleum Congress, Moscow. Applied Science Publishers, London, pp. 13–26. Sundberg, K. R., 1994. Surface geochemistry applications in oil and gas exploration. Oil and Gas J., 6:47–58. Tek, M. R., 1987. Underground Storage of Natural Gas. Contributions in petroleum geology and engineering, No. 3, G. V. Chilingar (ed.), Gulf Publishing Co., Houston, TX, 389 pp. Terry, D. and Chilingar, G. V., 1955. Summary of concerning some additional aids in studying sedimentary formation by M.S. Shvetsov. J. Sediment. Petrology, 25(3):229–234. Tingay, M., Reinecker, J. and Muller, B., 2008. Borehole breakout and drillinginduced fracture analysis from image logs. World Stress Map Project, 8 pp. Tissot, B. P. and Welte, D. H., 1978. Petroleum Formation and Occurrence. Springer, Berlin, Heidelberg, New York. Titus, C. H. Wittle, J. K. and Bell, C. W., 1985. Apparatus for passing electric currents through an underground formation. U.S. Patent 4495990, 29 Jan. Toth, J., 1996. Thoughts of a hydrogeologist on vertical migration and near-surface geochemical exploration for petroleum. AAPG Mem., 66:279–283. Waiters, L. T. and Sabinas, F. L., 1980. Field evaluation of method to control gas flow following cementing. SPE Paper 9287 presented at the 1980 SPE Annual Technical Conference, Dallas, TX, Sept. 21–24. Ward, D. M., Mah, R. A. and Kaplan, I. R., 1978. Methanogenesis from acetate. App. Env. Microbiol., 35:1185–1192.

Migration of Hydrocarbon Gases 259 Weatherford laboratories, 2011. Determining the Origin of Hydrocarbon Gas Shows and Gas Seeps (Bacterial Gas vs. Thermogenic Gas) Using Gas Geochemistry. http://www.gaschem.com/determ.html Welte, D. H., 1972. Petroleum exploration and organic geochemistry. J. Geochem. Explor., 1:117–136. Wentworth. C. M., Ziony, J. I., and Buchanan, J. M., 1969. Preliminary Geologic Environmental Map of the Greater Los Angeles Area, California. Whittaker, M. J., 1994. Correlation of natural gases with their sources. In: L. B. Magoon and W. G. Dow (eds.), The Petroleum System, From Source to Trap, AAPG:261–283. Wittle, J. K., Hill, D. G. and Chilingar, G. V., 2008. Direct Current Stimulation for Heavy Oil Production. Paper 2008-374. Second World Heavy Oil Congress. Edmonton, March 10–12. Wittle, J. K., Hill, D. G. and Chilingarian, G. V., 2011. Direct Electric Current Oil Recovery (EEOR). A new approach to enhancing oil production. Energy Source Part A, 33:805–822. Woese, C. R. and Wolfe, R.S. (eds.), 1985. Archaeobacteria, Vol III. In: A Treatise on Structure and Function. Academic Press, New York, NY. Zaks, S. L., 1952. Effect of rock and bound water on value of pressures at which oil/gas system is transformed into one-phase gas condition. Dokl. Akad. Nauk USSR, 86:1017–1020. Zaks, S. L., 1955. Toward question of migration and accumulation of petroleum. Dokl. Akad. Nauk USSR, 105:332–334. Zhuze, T. P. and Yushkevich, G. N., 1959. Solubility of oil and its heavy fractions in compressed gases. Trudy Inst. Nefti Akad. Nauk, 13:626–274.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

17 Subsidence as a Result of Gas/Oil/Water Production *Originally published in Environmental Aspects of Oil and Gas Production, by John O. Robertson and George V. Chilingar, copyright 2018, Scrivener Publishing

17.1 Introduction Much of the Earth’s surface consists of layers of alluvial material. Some of these porous layers contain fluids and are identified as aquifers. There are two types of aquifers, confined and unconfined. An unconfined aquifer has no caprock (similar to an unsealed tank without a top) and fluids can easily migrate either in or out of this type of aquifer without affecting the support of the overburden as the fluid does not help support the weight of the formation above it. When surface pressure is applied to the unconfined aquifer, the pressure of the overburden is carried totally by the rock-matrix skeletal structure of the rock. Confined aquifers have a caprock or impervious interval that prevents fluids from either percolating into the aquifer from above or migrating out of the aquifer (similar to a sealed tank). The difference between a layer of confined and unconfined aquifer is that in a confined aquifer, fluids within the aquifer help support the overlying weight. Withdrawal of fluid from a confined aquifer results in reduction of the pressure of the pore fluid as

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the fluid (produced) is withdrawn from the aquifer, resulting in the rockmatrix skeletal structure of the rock then carrying a greater share of the overburden pressure. Hydrocarbon reservoirs are confined aquifers. (See Poland and Davis, 1960.) The withdrawal of fluids (oil, water, and/or gas) from subsurface confined aquifers/reservoirs can result in the subsidence of the Earth’s surface. Fluids that exist in the pore space or fractures of confined aquifers are under pressure. The pressure of the fluid within that pore space along with the strength of the rock-matrix skeletal structure of the rock help support the overlying formation (load). If fluids (oil, water, and/or gas) are withdrawn from the pores of a subsurface aquifer, a decrease in fluid pressure may occur giving less support of the overlying formation. This reduction of pore pressure can result in the partial compaction of the subsurface aquifer, to the level where the pore structure and remaining fluid pore pressure can now support the overlying load. The two fluids that occur in subsurface aquifers beneath the surface of the Earth are water (groundwater) and hydrocarbons (crude oil and/or natural gas). Upon reduction of pore pressure as a result of the production of fluid, there is often a collapse of the rock-matrix skeletal structure of the rock to compensate for the reduction of pore pressure supporting the overburden. This collapse in a subsurface aquifer is not elastic and the deformation of the pore structure is permanent. Table 17.1 lists a few cities throughout the world that have experienced these subsidence problems due to removal of water and/or hydrocarbons from underlying aquifers. Chilingarian and Donaldson (1995) have pointed out that subsidence events are rarely considered as immediate major disasters, certainly nowhere near the scale of an earthquake, tsunami, volcanic eruption or landslide. However, the slow subsidence of an urban area over a long period of time can cause as much economic damage as earthquakes in which damage occurs over a short period of time. Subsidence problems manifest themselves in various ways. The following selected global examples portray problems associated with subsidence: (1) The extraction of natural gas caused land subsidence in the Po Delta of Italy and also in the large Groningen Gasfield of the Netherlands. (2) Widespread harbor subsidence resulted from oil production in the Wilmington Oilfield, Los Angeles/Long Beach, CA. (3) Seabed subsidence occurring around the North Sea Ekofisk production platforms resulting in a threat to the safety of personnel and equipment. (4) The rapid draw-down of the groundwater table by over-pumping in arid and semi-arid agricultural regions can result in abrupt ground failure. (5) Excessive withdrawal of groundwater creating large earth fissures in the farming area of Wadi al Yatimah and

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Table 17.1 Subsidence found in various cities as a result of fluid withdrawal. (Modified after Nelson, 2015.)

City, Country

Maximum recorded subsidence

Approximate area of subsidence (km3) Cause of subsidence

Long Beach/Los Angeles, CA, U.S.A.

9.00 m ( 29.25 ft)

50 km3

Hydrocarbon production

San Joaquin Valley, CA, U.S.A.

8.80 m ( 28.6 ft)

13,500 km3

Groundwater production

Mexico City, Mexico

8.50 m ( 27.6 ft)

225 km3

Filled in lake with sediments

Tokyo, Japan

4.50 m ( 14.5 ft)

3,000 km3

Coastal sediments

San Jose, CA, U.S.A. Osaka, Japan Houston, TX, U.S.A. Shanghai, China Niigata, Japan

3

3.90 m ( 12.7 ft)

800 km

3.00 m ( 10 ft)

500 km3

Coastal sediments Coastal sediments 3

2.70 m ( 8.8 ft)

12,100 km

Coastal sediments

2.63 m ( 8.5 ft)

121 km3

Coastal sediments

2.50 m ( 8.1 ft)

3

Coastal sediments

3

8,300 km

Nagoya, Japan

2.37 m ( 7.7 ft)

1,300 km

Coastal sediments

New Orleans, LA, U.S.A.

2.00 m ( 6.5 ft)

175 km3

Deltaic sediments

Taipei, China

1.90 m ( 6.1 ft)

130 km3

Costal sediments

Bangkok, Thailand

1.00 m ( 3.2 ft)

800 km3

River sediments

Venice, Italy

0.22 m ( 0.7 ft)

3

150 km

Costal sediments

London, England

0.30 m (»1.0 ft)

295 km3

River sediments

destruction of new tourist facilities at Al Afiaj lakes of western and central Saudi Arabia. 6) Widespread ground subsidence in the large metropolitan areas, e.g., Osaka, Japan, and London, England, resulted from excessive pumping of water from aquifers. If all subsidence of the Earth’s surface was uniform due to fluid production, the elevation of all supported structures, within the area of subsidence would uniformly decrease in elevation and there would be few environmental problems; however, the layers of Earth’s sediments are not homogeneous, they are heterogeneous and so the amount of collapse of the rock structure can vary from one area to another within the area of subsidence. This variation in subsidence is often referred to as differential subsidence. Differential subsidence may result in: (1) cracking of concrete highways, curbs and sidewalks, (2) weakening foundations and structures of buildings, (3) breaking of pipelines and leaking sewers, (4) breaking in earthen

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dams, and (5) generation of fractures in the Earth’s surface through which gas and/or fluids can then migrate to the surface. Some of the earliest recorded examples of subsidence due to ground water withdrawal are Osaka, Japan (noted in 1885); London, England (noted in 1865), and Mexico City, Mexico (noted in 1929). One of the earliest recognized examples of subsidence caused by withdrawal of hydrocarbons is Goose Creek Oil Field, Texas (noted in 1918), described by Pratt and Johnson (1926). The phenomenon of subsidence has been investigated by many and today it is recognized that withdrawal of fluids from a confined reservoir likely will result in the compaction of the reservoir rocks, reflected as subsidence at the surface. A detailed analysis of subsidence has been presented by Chilingarian et al. (1995) and Donaldson and Chilingarian (1997). In summary, subsidence as a result of fluid withdrawal occurs when the reservoir fluid pore pressures are reduced and the grain-to-grain pore structure along with the existing pore pressure of the fluid in the reservoir rocks lack the strength to resist deformation upon the transfer of load from the fluid phase to the grain-to-grain contacts needed to support the overburden pressure. The principal lithological and structural characteristics of the subsiding areas in oilfields commonly include the following characteristics: 1. Sediments are unconsolidated and lack appreciable cementation. 2. Porosity of the sands is high (>30%). 3. The sediments are of Miocene age or younger. 4. Producing formations are located at depths 30 m. 6. Overburden is composed of structurally weak rocks. 7. Tension-type faulting, often with a graben, is present. 8. Sands are interbedded with clays, silts and/or siltstones, and shales. 9. Pore pressure is greatly reduced by production

17.2 Theoretical Compaction Models Subsidence over fluid producing (oil, water, and gas) formations is caused by the reduction of pore (fluid) pressure within the producing formation through the removal of fluids within the pores and increasing effective stress. Thus, (effective, grain-to-grain, stress, pe) = (total overburden stress, pt) n (pore or fluid pressure, pp):

Subsidence as a Result of Gas/Oil/Water Production

pe

pt np p

265 (17.1)

Rieke and Chilingarian (1974, p, 6), however, proved experimentally that exponent n is about one. Thus, (effective stress {grain-to-grain} stress, pe) = (total overburden pressure, pt) (pore or fluid pressure, pp) (17.2) The overburden pressure, pt is equal to the specific weight of the overlying water-saturated rock ( b) multiplied by the depth (D): pt =

b

D

(17.3)

During sedimentation, the stresses (pe, pt, pp) can attain temporary equilibrium with different degrees of support assumed by the rockmatrix skeletal structure and the fluids occupying the pores (pt = pp + pe). Gravitational stress (mass of the overburden) is transmitted vertically through the grain-to-grain contacts. Hydrostatic stress from the mass of the interstitial water above the compacting rocks is transmitted through the water column. Another stress that aids grain redistribution is the viscous drag caused by movement of water downward and toward producing wells. Chilingarian et al. (1995) found that clay and sand layers compact to almost the same extent. The principal difference is the plastic behavior of the clay bodies, because of the extremely low effective permeability to water, which must be expelled in order for compaction to take place. Over a period of years, however, the slow contribution of shales and clays to compaction (and subsequent subsidence) can be of major importance (Van der Knap and Van der Vis, 1967). The concept of the compaction process can be explained by use of a mechanical model that is composed of a perforated round metal plate and enclosing cylinder which contains a metal spring and water (Figure 17.1). In this analogy, the spring represents the compactable sediment grains, water represents the fluid in the pore space, and the size of perforations in the metal plate is a measure of permeability. A useful expression in studying compaction is the ratio of the fluid stress, w, to the total stress, (see Hoffman and Johnson, 1965): w

pp p1

(17.3)

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S S S p

=1 Stage A

0.465 Stage B

= 0.465 Stage C

Perforated plates Water

Figure 17.1 Simplified schematic representation of clay compaction (concept after Terzaghi and Peck, 1948, p. 84; In: Holtman and Johnson, 1965, p. 718.). σ = grain-tograin bearing strength; S = axial component of total stress (overburden pressure); p = fluid pressure; and λ = ratio of the pore stress to total stress: σ = S – p. Stage A: overpressured system; water is not allowed to escape. Stage B: water is allowed to escape: springs carry part of the applied load. Stage C: compaction equilibrium; load is supported by the springs and the water (water pressure is simply hydrostatic). (Modified after Rieke and Chilingarian, p. 93, 1974.)

When stress is initially applied to the closed system, has a value of 1 and the system is overpressured. At the final compaction stage, when the load is carried entirely by the skeletal structure (spring), is equal to 0. At the final stages of compaction, the applied load is supported jointly by the skeletal structure and intergranular water (hydrostatic) and the value of is approximately equal to the normal pressure gradient, i.e., 0.465psi/ft. This value is typical of the normal pressure gradient in the U.S. Gulf Coast. The lithostatic (geostatic or overburden) pressure gradient is considered to be about 1.0 psi/ft (0.3231 kg cm 2m 1) of depth. The hydrostatic pressure can vary from locality to locality dependent upon the specific weight of the water (due to the varying degree of salinity). The spring analogy often fails to agree with the actual compaction values of clay in the field as the pressure conditions in the field are often not uniform throughout the thickness of the clay mass as they are in the test cylinder. According to Allen et al. (1971), subsidence due to withdrawal of fluids occurs when (a) reservoir fluid pressures are lowered, (b) reservoir rocks are compactable (usually uncemented) and/or are unable to effectively

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267

resist deformation upon the transfer of load from the fluid phase to the grain-to-grain contacts, and (c) overburden lacks internal self-support and can easily deform downward. When the hydrostatic head is lowered, the overburden support is decreased and grain-to-grain load increases. As a result, sands and silts compact by grain rearrangement and crushing, whereas plastic flow occurs in argillaceous sediments. Water from clays and shales moves into associated sands and, consequently, there is a decrease in volume of fine-grained sediments. The relative contribution of sands and of clays to compaction varies with depth and with the geologic history. According to Allen et al. (1971), at very shallow depths clays and silts are usually the major compacting materials, whereas at greater depths (300–1,000 m) sands constitute the major compacting material. Susceptibility of the formation to subsidence is dependent upon many factors, such as the degree of compaction due to (1) previous depth of burial during geologic time, (2) types of clays, (3) shape and size of sand grains, and (4) relative proportions of interbedded clays and sands. As pointed out by Allen et al. (1971), the concept of overburden load and load transfer is extremely important, because upon fluid removal subsidence would not occur unless there is a load transfer. The maximum amount of load transfer possible at a particular depth is equal to the fluid pressure (hydrostatic pressure) at that point. The manner in which the load change could occur upon production of fluids is illustrated in Figure 17.2. Initially, the geostatic pressure gradient (0.91 psi/ft.) is equal to the sum of the intergranular pressure gradient (0.48 psi/ft.) and hydrostatic pressure gradient (0.43 psi/ft.). Assuming no residual fluid in the pores, the buoyant effect of the water is lost and the intergranular load is increased as the fluid level is lowered from A to B, for example. Geostatic load decreases (curve 3 shifts to curve 3b, Figure 17.2) as water is removed. The intergranular and geostatic loads are equal if the pores are dry (curve 2b, Figure 17.2). Compaction can occur if the intergranular load is increased. In the case of a confined aquifer, which has a relatively impermeable cover (caprock), as the fluid level is lowered from A to C, the intergranular load gradually increases until it becomes equal to the geostatic load (curve 2 shifts to curve 2c, Figure 17.2). If pore spaces still contain some residual water, the intergranular load and geostatic load are not equal below the level C. Upon the reduction in pore-water pressure and consequent load transfer in the aquifers, pressure gradients are set up across the interfaces of interbedded siltstones, shales, and clays. As a result, water movement occurs from these fine-grained beds into coarse-grained aquifers. The

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A

0

0

Pressure, p.s.i. 800

400

1200

1600 0

.77 psi/ft. (.18 kg/cm2/m) Unconsolidated unconfined aquifer 100

) 2 /m m /c kg .21 t( i/f ps .01 nt ie ) ad 2 /m gr re /cm g k su 1 1 es ) t. (. 2 /m pr si/f p cm tic .48 kg/ ta nt (.1 os die /ft. Ge gra psi .43 ure ess ent i B d r pr l at gra ula re eve ran er l ssu erg pre wat c Int c if tati tati ros ros Hyd Hyd

3a

400

2a

B

1a

3

Depth, ft.

3b

300

Depth, m

800

200

2

1

2b

1200

Impermeable caprock

C Hydrostatic head in aquifer reduced to auifer top

1600

Unconsolidated confined aquifer

500 2c

1b

2000

400

600 0

20

40

60 Pressure, kg/cm2

80

100

Figure 17.2 Illustration of load transfer owing to water-level drop or reduction in porewater pressure in unconfined and confined aquifers. Geostatic, hydrostatic and intergranular pressure gradients are plotted assuming that solids and water have specific gravities of 2.7 and 1.0, respectively, and that porosity is equal to 35%. (Modified after Allen et al., 1971, figure 4, p. 285. Courtesy of Enciclopedia della Scienza e dell Tecnica, Mondadori.).

volumetric rate of flow depends on the permeability of clays and silts, porewater pressure drop, length of the drainage paths, viscosity of water, and cross-sectional area of flow. According to Allen et al. (1971), in shallow, unconsolidated sediments consisting of interbedded clays, silts, and sands, which have void ratios of about 0.6 or greater, clays and silts are the major compactible materials upon dewatering. On the other hand, at depths of

Subsidence as a Result of Gas/Oil/Water Production 0.1 160

Applied pressure, p.s.i. 10 100

1

1,000

269

10,000

1

140

120

Void ratio, e

100

2

80

3 4 8

5

60

7

6 9

40

10 12

20

0

11 13 14

0.01

0.1

1 10 Applied pressure, kg/cm2

100

Figure 17.3 Relationship between void ratio and applied pressure for sand, silt and clay cores obtained at different depths from various areas. 1 = Corcoran Clay (depth of 425 ft); 2 = very loose sand; 3 = Corcoran Clay (depth of 735 ft); 4 = silt (depth of 1,345 ft); 5 = average Wilmington, California sands (depth of 2,000–4,000 ft); 6 = average Wilmington, California siltstones (depth of 2000–2,900 ft); 7 = sand from Maracaibo, Venezuela (depth of 3,000 ft); 8 = intermediate compacted sand; 9 = average Wilmington, California siltstone (depth of 3,000 ft); 10 = very compacted sand; 11 = average Wilmington, California siltstone (depth of 3,100–3,500 ft); 12 = clay from Maracaibo, Venezuela (depth of 3,104 ft); 13 & 14 = average Wilmington, California, siltstones (depth of 3,600–6,000 ft). (After Allen and Mayuga. 1969. In: Chilingarian et al., 1995, p. 187, figure 3.11.)

300 m or greater and/or where the void ratios are below 0.6, the sands constitute the major compacting material. In Figure 17.3, void ratio is plotted versus applied pressure for sand, silt, and clay cores. At void ratios of 0.6 or greater and pressures of about

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30 kg/cm2, sands are as compactible as clays, or even more compactible. Clays having high void ratios are very compactible at high pressures. Void ratio-versus-pressure data obtained by Roberts (1969) shows that in the 1,000–20,000 psi pressure range, certain sands may be at least as compressible as the typical clays, if not more compressible. At a depth of 3,000 ft, Boston Blue Clay could undergo about 6% compression (Figure 17.4), i.e., for an initial stratum thickness of 100 ft, a total settlement of approximately 6 ft may occur. Compression of the oil sand, which was disturbed and repacked into an initially loose condition, could result in a settlement only 15% lower than that of the Blue Clay (Roberts, 1969, p. 375). At a depth of 5,000 ft, the Blue Clay could undergo 5.5–6% compression. At this depth various sands could undergo 1–7.5% compression (Roberts, 1969, p. 375). At a depth of 8,000 ft, the Blue Clay could undergo about 5% compression, whereas various sands could undergo compressions varying from about 2 to 10%. At this depth a 20–40 mesh Ottawa Sand is about twice as compressible as the Blue Clay (Roberts, 1969, p. 375). Figure 17.5 illustrates the relationship between void ratio and applied pressure for oil sands. Figure 17.6 shows the relationship between porosity and depth of burial for shales and argillaceous sediments.

17.3 Theoretical Modeling of Compaction The porosity or pore volume of elastic sediments and rocks decreases with increasing depth. This decrease in porosity is a measure of the amount of compaction undergone in the argillaceous sediment since deposition. There is a problem in evaluating the effects of depositional rates and geologic age in developing a simple sediment compaction model. Nevertheless, empirical data suggest that the effect of age and depositional rates are predictable. Although the effect of temperature on formations is difficult to evaluate, experiments by Warner (1964, pp. 50–79) suggested that at temperatures less than 200 °F, temperature may not have a significant effect (other than in accelerating compaction-rates). Most compaction models utilize clay minerals of an idealized size and shape, which are influenced by mechanical rearrangement during burial. The following theories, presented below, are intended to enable the reader to better visualize the interrelationship among pressure, porosity reduction, and interstitial fluid release in argillaceous sediments.

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271

Clay and shale 3

1

Void ratio, e

0.7

4

5

0.5

2

6 7

0.3

8

0.1 10

100

10,000 1000 Applied pressure, p.s.i.

100,000

Figure 17.4 Relationship between void ratio and applied pressure for clay and shale. Curve 1 = undisturbed Boston Blue Clay; Curves 2,7 & 8 = clay cores from Venezuela (depths of 2,486 to 4769 ft); Curves 3 & 4 = compressed curves for plastic clays with liquid limits of 80 and 30% with a P. I. of 50 & 12, respectively (Skempton, 1953); Curve 5 = undisturbed shale (C11); and Curve 6 = undisturbed shale (C5). (After Roberts, 1969, figure 1, p. 369. In: Chilingarian et al., 1995, p. 188, figure 3.12.)

Oilfield sands

0.8

1 2 3

Void ratio, e

4 0.6

5 6

0.4

0.2 10

100

1000 10,000 Applied pressure, p.s.i.

100,000

Figure 17.5 Relationship between void ratio and applied pressure for oilfield sands. Curve 1 = remolded(25.10); Curves 2 & 6 = remolded (M.I.T. Geol. Dept.); Curve 3 = undisturbed (1.1); Curve 4 = undisturbed (25.1); Curve 5 = remolded (25.13). (After Roberts, 1969, figure 4, p. 372. In: Chilingarian et al., 1995, figure 3.12, p. 183.)

272

Fracking 2nd Edition Shales and argillaceous sediments 0 2 1 3

5 8

9 10

5000

Depth, ft.

6 7

4

10,000

15,000

20,000 0

20

40 Porosity, %

60

Figure 17.6 Relationship between the porosity and depth of burial for shales and argillaceous sediments. Source: Curve I = Proshlyakov (1960); Curve 2 = Meade (1966); Curve 3 = Athy (1930); Curve 4 = Hosoi (1963); Curve 5 = Hedberg (1936) Curve 6 = Dickinson (1953); Curve 7 = Magara (1968); Curve 8 = Weller (1959); Curve 9 = Ham (1966); and Curve 10 = Foster and Whalen (1966). (After Rieke and Chilingarian, 1974, p. 42, figure 17.)

17.3.1 Terzaghi’s Compaction Model Terzaghi (1943) introduced the effective stress concept. The effective stress concept was first empirically formulated on the basis of laboratory experiments. This approach assumes that the load, L (overburden pressure), applied to a unit of fluid-filled soil or rock, is supported by the solid frame (grain-tograin stress, e, or pe) and the pore pressure increase, p. The support provided by the solid frame, within this scheme, was also called effective stress ( e or pe). Effective stress does not correspond to any actual stress in a rock, but is the stress in the model medium and is an average stress (computed value) on a horizontal plane (see Gurevich and Chilingarian, 1993):

Subsidence as a Result of Gas/Oil/Water Production e

=L

p

273 (17.5)

In the Terzaghi model, physical meanings of measured values are quite definite: L represents a new, additional load applied to a physical body in mechanical equilibrium and p is the elastic response of the pore fluid to the total (elastic, reversible, and plastic, irreversible) deformation of the specimen. Terzaghi assumed that effective stress, , is the stress in the solid frame under these conditions (Gurevich, e 1980). In a dynamic situation, hydrostatic uplift and elastic response act together. Thus, the physical meaning of the effective stress concept being applied to deformations of rocks in situ is rather obscure physically and often leads to confusion. This is especially true because the effective-stress concept completely ignores both the nature of deformations and mechanical properties of rocks that are deformed. This concept does not take into account the fact that not just a small piece, but rather a large mass of rocks is being deformed as a single unit. Thus, when deformation cannot be reduced to a one-dimensional model, some additional problems arise. For example, the generation of a vertical tension and strain of rocks in the course of subsidence of formations above a compacting reservoir is not compatible with the effective-stress concept: the overburden weight is not fully transmitted to the reservoir but, nevertheless, compaction continues (Gurevich and Chilingarian, 1993). Additional problems with the effective-stress concept arise because of heterogeneity of the rock and its mechanical properties, and the presence of fractures. Owing to heterogeneity, some scale effects arise and should be taken into account (Bell and Dusseault, 1991; Enever et al., 1990; Ito et al., 1990; Ratigan, 1990). Another source of confusion is the disagreement on whether or not compressibility of sediments and rocks obtained from compaction tests in the laboratory and those in situ differ. There is a dependence of compressibility on loading history and according to some investigators, the measured degree of compaction in situ is lower than those predicted from laboratory tests. Radioactive bullet surveys in the Groningen gas field showed that the actual compaction values were three times lower than the amount predicted (Mess, 1979). It is important to know, however, whether uniaxial or hydrostatic compaction equipment was used in the laboratory. For example, when using hydrostatic compaction apparatus, the compressibility of unconsolidated sands are often about twice as high as those obtained when using uniaxial compaction apparatus.

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17.3.2 Athy’s Compaction Model According to Athy (1930) compaction represents a simple process of squeezing out the interstitial fluids and thereby reducing the porosity. In relatively pure shales a definite relationship exists between porosity and depth of burial as shown in Figures 17.6 and 3.7. After sediment has been deposited and buried, the pore volume may be further modified by: (1) deformation and granulation of the mineral grains; (2) cementation; (3) solution; (4) recrystallization; and (5) squeezing together of the grains. Upon continued application of overburden stress, the porosity is reduced and bulk density is increased. Athy (1930) pointed out that the amount of compaction is not directly proportional either

Garber oklahoma shales 26

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3000 1000 Present depth at garber, ft.

(a)

5000

Porosity, %

Oklahoma shales 50 40 30 20 10 0 (b)

0

2000

4000

6000

Depth, ft.

Figure 17.7 (a) Relationship between bulk density and depth for Oklahoma shales. (b) Relationship between porosity and depth for Oklahoma shales. (After Athy, 1930, Figures 2 and 3, pp 12 & 13. In: Rieke and Chilingarian, 1974, p. 37, figure 14. Courtesy of the American Association of Petroleum Geologists.)

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to reduction in pore volume or increase in bulk density because of the abovementioned processes.

17.3.3 Hedberg’s Compaction Model Hedberg (1936) stated that because of the numerous processes involved in compaction, it is not possible to express satisfactorily pressure-porosity relationships for clays and shales throughout the entire depth range by any one simple equation. Hedberg (1936) determined the porosities of shale core samples taken from Venezuelan wells from depths of 291 ft to 6,175 ft. An analysis of this data, led Hedberg (1936) to propose a compaction process consisting of three distinct stages: The first stage consists mainly of the mechanical rearrangement and dewatering of the clayey mass in the pressure interval from zero to 800 psi. During this period of dewatering, there is a rapid decrease in porosity for small increments of additional overburden pressure. Expulsion of free water and mechanical particle rearrangement are dominant in the porosity range from 90% to 75%. Some adsorbed water is also lost during this stage. Between a porosity of 75% and 35%, adsorbed water is expelled from the sediment. In the second stage mechanical deformation of the clay structure occurs below a porosity of 35% where the clay particles come in closer contact with each other. As a result, there is a greater resistance to further reduction in porosity. The third and final stage is recrystallization with porosities less than 10%. The main compaction mechanism during this stage is recrystallization under high pressures. Reduction of the pore volume occurs slowly and only with large pressure increments. The larger crystals may grow at the expense of the smaller ones, and a gradual transition may occur from a shale to a slate and then to phyllite.

17.3.4 Weller’s Compaction Model Weller (1959) described a compaction process very similar to the one proposed by Hedlberg (1936). Weller’s composite porosity depth curve shown in Figure 17.8 represents an equilibrium condition in a continuous column of ordinary mud and shale. This curve is based on Terzaghi’s, Athy’s, and

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1.8 5.4

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1.0

r

lle We 2.0

Va

sso

ev

ich

3.0 4.0 5.0

98 196

392

588 784 Pressure, N/m2

980

1176

Figure 17.8 Relationship between porosity, depth of burial and overburden pressure. N = unit of force (Newton) = 102 g-force = 105 dynes. (After Weller and Vassoevich, in: Kartsev et al., 1969, in: Rieke and Chilingarian, 1974, p. 43, figure 18.)

Hedberg’s data. The porosity-depth relationships can be distorted by the occurrence of carbonates and sands in shales and by abnormally overpressured zones. In addition, application of laboratory soil-compression tests to buried sediments presents some problems. Weller (1959) proposed a compaction process starting with a mud at the surface having a porosity between 85% and 45%. As the overburden pressure increases owing to sedimentation, the interstitial fluids are expelled from the pore space (porosity ranges from 45% to 10%). As a result, there is rearrangement of the mineral grains and development of closer packing. Compaction at this stage is related to the yielding of clay minerals between the more resistant grains. Weller theorized that at about 10% porosity, the non-clay mineral grains are in contact with each other, and the clays are being squeezed into the void space. Further compaction (porosity < 10%) requires deformation and crushing of the grains.

17.3.5 Teodorovich and Chernov’s Compaction Model Teodorovich and Chernov (1968) suggested the following stages in the compaction of productive Apsheron horizons in Azerbaijan: The first stage occurs at burial depths of 0 to 8–10 m where there is a rapid compaction. Porosity in clays decreases from

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66% to 40%, whereas that of sandstones-siltstones decreases from 56% to 40%. Large amounts of water are squeezed out during this stage. During the second stage there was a rapid decrease in the compaction rate in the intervals from 8–10 m to 1,200–1,400 m. During this stage, porosities of the shales and sandstones-siltstones decrease to about 20%. The third stage (burial to a depth of 1,400 to 6,000 m) is characterized by slow compaction. The absolute porosity of sandstonessiltstones at a depth of 6,000 m decreases to approximately 15% to 16%, whereas that of shales to 7% to 8%.

17.3.6

Beall’s Compaction Model

Beall (personal communication, 1970), proposed a simple model for consolidation of elastic muds, based on the data from offshore well core samples, Louisiana, the JOIDES Deep Sea Drilling Project, and from high-pressure experiments on marine muds. The initial stage of compaction (down to a depth of approximately 3,300 ft) primarily involves expulsion of fluids by mechanical processes as in the other proposed theories. Approximately 50% of the total consolidation is reached at a very shallow depth. The average calculated pore throat diameters during the first stage are around 6Å. During the second stage (approximately at depths of 3,300 to 8,000 ft) about 75% of total compaction is complete, and pore throat widths in the clays approach 1Å. The fluid pressures remain hydrostatic. During the third-stage of compaction there is an extremely slow decrease of porosity with depth, and pore throat diameters are generally less than 1Å. According to Beall, NaCl filtration could probably take place during the third stage resulting in the expulsion of progressively less saline fluids to associated permeable sands, if the latter are present. In Beall’s model, overburden pressure between 8,000 to 12,500 psi would be required to initiate NaCl filtration in marine muds. In the absence of permeable sands, the excess fluid pressure may be generated during the third stage.

17.3.7 Katz and Ibrahim Compaction Model Katz and Ibrahim (1971) presented a mechanical model for explaining compaction and fluid expulsion from shales. Their model is based on Terzaghi and Peck’s simple piston and spring analogy (see Figure 17.9). The Katz and Ibrahim model is based on the compaction of an argillaceous layer

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K

W

h=

W W

P

t2 S stress

W

t1

t

W

Datum

K

Section

+ K,

P

G G

Section

G G

Perforated disc. (low permeability) Shales

Springs (analog clay aggregates) Sands

Figure 17.9 Schematic representation of clay compaction, porosity and permeability relationships and creation of abnormally high formation fluid pressures. Where k = permeability; = porosity; t = time; p = pore pressure; W = specific weight of water; h = height to which fluid will rise in the tubes; this represents the pressure head (P/ w); W = water and G = gas. (Modified after Katz and Ibrahim, 1971, figure 12, courtesy of Soc. Pet. Eng., in: Rieke and Chilingarian, 1974, p. 319, figure 170.)

between two permeable sand layers. As proposed by Terzaghi and Peck, the argillaceous sediment is represented by a series of springs and perforated disks. The perforated disks represent low-permeability clays, which restrict the escape of fluids, whereas the springs represent the deformable clay matrix. Sudden loading on the model corresponds to a rapid sedimentation rate. Water contained in the spaces between the perforated disks represents the interstitial fluid. If a stress is applied suddenly to the system, the water between the disks initially will support the entire load. After a brief period of time, the water will be forced through the perforations in the disks either in an upward or a downward direction, depending on the relative magnitudes of pressure in the compacting systems, without lateral flow. As the top and bottom disks move closer to the internal disks, the springs will begin to carry part of the applied load (Figure 17.9). Consequently, the fluid pressure between the external disks will decrease. When the disks approach each other, it will become difficult for the pore fluid to escape

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from inside the system. Katz and Ibrahim (1971) mentioned that the gradual decrease of permeability from the center toward the top and bottom of the model could be represented either by a decrease in the number of openings in the disks per unit length in the model or by an increase of the number of disks per unit length in the model. Higher fluid potential is shown to exist in the central portion rather than in the upper or lower portions of the model. This means it takes more time for the fluid in the center of the model to escape than at the outer boundaries. The behavior of the Katz and Ibrahim mechanical model is in general agreement with the observed performance of overpressured formations in the U.S. Gulf Coast area. The model illustrates the reasons for the higher porosity for undercompacted shales, the extreme drop in permeability with increasing lithostatic pressure, and entrapment of high interstitial fluid pressure in the shales.

17.4 Subsidence Over Oilfields Formation pressure drops in petroleum reservoirs during fluid production (water/oil/gas) often result in subsidence if there is no influx of water. If there is an influx of water, the quantity of subsidence could be less than anticipated. This reduction in pore pressure within reservoir rocks may result in the influx of water from the adjoining formation in waterdrive reservoirs. If the influx of water is not sufficient to totally replace the produced fluids, a greater percentage of the overburden load will be then carried by the skeletal structure of the rock (the grain-to-grain stress is increased). This eventually will be reflected at the Earth’s surface as land subsidence. Compaction occurs in both the reservoir rocks and the overlying layers of rock as the pore skeletal structure adjusts itself to carry the additional stress. The area of subsidence as a result of subsurface fluid production is about twice as large as the area of the reservoir. Subsidence (differential) at the surface can cause engineering and ecological problems. These include structural damage, rupture of casings, and disruption of pipelines (Barends et al., 1995; In Chilingarian et al., 1995; Dobrynin and Serebryakov, 1989). Tapping the earth for ground water and/or hydrocarbons has resulted in many areas in sinking of the land surface due to loss of pore pressure. An excellent example is the subsidence in East Mesa geothermal field, CA, where there was withdrawal of large quantities of hot brine for geothermal power. Fluid pressures in petroleum and geothermal reservoirs are often reduced by as much as 2,000 to 4,000 psi from the initial pressure, whereas

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those in ground-water reservoirs are reduced by 200 to 600 psi (460 to 600 ft head of water). Dramatic and damaging effects of subsidence occurred above the Wilmington Oilfield in Long Beach, CA, in the 1940s and 1950s. This sinking (see Figure 17.10) occurred over an area of 22 sq mi and gave rise to a subsidence bowl up to 27 ft deep, causing damages in excess of $150 million to the above structures. The vertical subsidence was accompanied by a horizontal movement of as much as 9 ft, directed inward toward the center of the bowl of subsidence. The bowl is underlain by 6,000 ft of sediments of Recent to Miocene ages that uncomfortably overlie a basement schist of Pre-Tertiary age. Seven oil-producing zones extend from a depth of about 2,500 ft to 6,000 ft. The average porosity of productive zones, containing 23% to 70% sand, ranges from 24% to 34%. Similar areas of land subsidence related to exploitation of oil and gas fields include: (1) Goose Creek, Texas; (2) Lake Maracaibo, Venezuela; (3) Niigata, Japan; and (4) Po Delta, Italy. Marsden and Davis (1967, p. 95) and Poland and Davis (1969) described several techniques of measuring the compaction of underground strata:

Figure 17.10 Subsidence of Long Beach, CA, area between 1928 and 1962 of the Wilmington Oilfield, CA. The subsidence shown in the upper right is due to fluid withdrawal from the Long Beach (Signal Hill) oilfield, whereas that in the foreground is due to fluid withdrawal from the Wilmington oilfield. Lines of equal subsidence are in feet ( 2’, 4’, 6’, 10’, 14’, 22’, 27’ and 29’). (Courtesy of City of Long Beach Department of Oil Properties, CA.; http://www.lon beach. ov/lb a/about-us/oil/subsidence/)

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1. Bullets of radioactive material are shot into the rock at measured intervals in the wellbore from a firing mechanism (gun) lowered down the hole. A gamma ray detector is then periodically lowered into the well on a cable to determine the changes (lessening) in distances between the radioactive markers. 2. The vertical compression of casing (steel pipe) that lines the well is measured. Inasmuch as casing is usually cemented to the rock surrounding it, the vertical compression of the rock will shorten the pipe length. Casing comprises 30- or 40-ft pipe joints. Magnetic flux at the collar joining two pipe lengths is different from the flux along the length of the pipe. Thus, a magnetometer can be used to locate the successive collars and measure the shortening of individual pipe lengths. Shortening as low as 1/2 inch in a 40-ft joint can be detected. The shortening also can be measured by marking the pipe with radioactive pellets at definite intervals. 3. Compaction recorders are used, which consist of a heavy weight emplaced in the formation below the bottom of a well  casing. Cable, which is attached to the anchor weight (200–300 1b), extends to the land surface and is counterweighted (in 50-lb increments) to maintain constant tension. The cable is free to move at its upper end. The amount of cable rise above the land surface is continuously measured by a recorder, as subsidence occurs. When amplified, the record can reveal subsidence as small as 1/10 mm. 4. Floats, quartz rods and transducers are employed, which enable measurement of vertical and horizontal strains and tilts of the land (Marsden and Davis, 1967, p. 99). Additional information may be found in Colazas and Strehle (1995, pp. 324–327).

17.4.1 Rate of Subsidence In addition to the grain response to increased stress in the rock-matrix skeletal structure, the subsurface reservoir as a whole undergoes several types of changes adjusting to the imbalance of forces caused by fluid withdrawal. Loosely cemented rocks undergo permanent rearrangement of grains and pore spaces resulting in the loss of porosity and permeability. This type of compaction induced by the mobility of grains is only partially reversible if the fluid pressure is later increased by water injection or natural recharge.

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Thus, indiscriminate fluid production can lead to a permanent loss of the capacity of an aquifer or a reservoir to contain (and to conduct) fluids. Information published on total and annual rates of subsidence may be relatively abundant but it tends to be incomplete. This information often gives the impression that there is an approximate maximum amount of subsidence; however, to get at definite values of the subsidence rates one must know the pressure decline rates, reservoir thickness, depth, and lithology of reservoir and overlying rocks. In a few cases, subsidence reached 10 m. In the San Joaquin Valley, CA, by 1970, the largest subsidence due to groundwater withdrawal was 8.5 m (28 ft). In the Wilmington Oilfield, CA, total subsidence due to hydrocarbon and water withdrawal was 9 m. Lesser values of subsidence for other oilfields are in the order of 0.9–1.5 m (3.5 ft) in the Los Angeles Basin, CA. The annual rate of subsidence is dependent on the rate of pore pressure decline, and may be as high as 0.6 m (2 ft) per year. In San Joaquin Valley, average annual rate of subsidence due to water withdrawal, was up to 2.4 m (8 ft) for 10 years (1959–1969), i.e., 24 cm (0.8 ft) per year. In the Wilmington Oilfield, annual subsidence rate in some areas was as high as 70 cm (2.3 ft), with the total subsidence for a three-year period (from 1951 to 1954) being 2.1 m (7 ft). Globally, high rates of about 0.3 m (1 ft) per year are often encountered [25 cm (0.84 ft) per year in Taipei Basin, Taiwan; and 32 cm (1.07 ft) per year (in 1960) in Tokyo, Japan] while lower rates in the order of several cm per year are also common.

17.4.2

Effect of Earthquakes on Subsidence

Green (1972) investigated the movement of benchmark elevations in California affected by earthquakes. The two principal types of earthquakes studied were those causing (1) surface faulting and (2) shaking, with the former being uncommon at the present time as the majority of earthquakes in California are relatively deep-seated. Earthquakes are normally reported in terms of magnitude (M), which is a measure of the energy released at the source (1 to 10 on the Richter scale) and epicenter, i.e., location on the surface directly above the quake. Intensity, which is a measure of the severity of ground motion at a particular point on the earth’s crust (I to XII on the modified Mercelli scale), is of prime importance in studying the effect of the magnitude of earthquakes on subsidence. According to Green (1972), the largest earthquake during the past 20 years in California (Kern County, 1952, M = 7.7) resulted in a maximum vertical displacement of 4 ft and a maximum horizontal displacement of 2–3 ft. The 1971 earthquake in San Fernando Valley in California (M = 6.6) resulted in maximum vertical and horizontal movements of 3 and 5 ft, respectively. Green (1972) showed a

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direct relationship between the anomalous settling of benchmarks and increased shaking. The amount of energy released at a particular source does not appear to be as important as the secondary effect of ground shaking.

17.4.3 Stress and Strain Distribution in Subsiding Areas

Extension zone

Compression zone

Extension zone

Compression

Extension

Distribution of stress and strain within the rock mass above the compacting hydrocarbon reservoir is the most important feature of subsidence from a viewpoint of fracturing of rocks and increase in vertical permeability. Several points should be emphasized. Horizontal tension is the highest in the zone around the central core of the subsidence bowl where horizontal compression predominates (Figure 17.11). Horizontal displacement in the Wilmington Oilfield reached a maximum of about 3.66 m (Allen, 1973; Kosloff et al., 1980). This extension can be presented, for example, as four new 0.5 mm-wide fractures per each meter in the zone of tension. These deformations, which released tensile strain and caused earthquakes, gave rise to open fractures, both lateral and vertical. The latter can become avenues for gas migration from the oilfields. Vertical tension is the highest in approximately the same zone. Figure 17.12, modified after Poland and Davis (1969), shows measured elongations in five successive moments. This combination of horizontal

Subsidence

Reservoir

Extent of subsidence fron production

Figure 17.11 Schematic diagram of compressive and tensile stress distribution in subsiding formation due to fluid withdrawal. (Modified after Gurevich and Chilingarian. 1993, figure 1, p. 224.)

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4-11-57

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Figure 17.12 Schematic of casing count surveys of a typical well in the Wilmington Oilfield. (Modified after Poland ad Davis, 1969; in: Gurevich and Chilingarian, 1993, figure 2, p. 244.)

shear stress with vertical tension caused several small earthquakes (Lee, 1979; Kosloff et al., 1980). As Kosloff et al. emphasized; “The hypocenters were at shallow depths between 450 and 550 m in bedded shale formation. The fault planes were always close to horizontal (Richter, 1958; Mayuga, 1965; Kovach, 1974). Locations of epicenters for the Wilmington Oilfield are shown in Figure 17.13 modified after Kosloff et al. (1980). It is these deformations, that released tensile strain and caused earthquakes, also formed open fractures, both lateral and vertical. It is necessary to emphasize that the very fact of the existence of vertical tensile strains and elongations above the compacting reservoir is direct evidence that the weight of the overburden is not transmitted fully to the compacting rocks due to the bridge-effect of overlying formations. That means that the effective-stress concept and models based on it do not exactly fit this deformation. In a sense, the existence of vertical tensile strain means that a reservoir compacts faster than the overlying beds bend down. Thus, beds break apart vertically. It is worth noting that in the case of sand production, when extraction of sand forms a cavity around the borehole, this effect will be enhanced and deformation similar to those shown in Figure 17.14 (Whittaker and Reddish, 1989), may be possible. The role of the strength of formations above a compacting reservoir is also indicated by a time lag in subsidence. Meyer and Fowley (1988) noted that “surface subsidence commonly lags behind cumulative production.”

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August 15, 1951 January 25, 1955

Maj

or a

April 4, 1961

xis -

-- Su

bsid

enc

e bo

wl August 15, 1951

November 18, 1949 September 24, 1951 December 14, 1947

San Pedro Bay 0

1

2

Km

Figure 17.13 Locations of epicenters and slip planes of subsidence earthquakes, Wilmington Oilfield, Long Beach, CA. (After Kosloff et al., 1980 figure 3, p. 245. In: Gurevich and Chilingarian, 1993.)

Figure 17.14 Deformation pattern of strata above longwall extraction with strong overburden (physical model). (After Whittaker and Reddish, 1989; in: Gurevich and Chilingarian, 1993, figure 4, p. 254.)

This means that for some time compaction of the reservoir is compensated not by equal subsidence but by vertical extension of the formation above the reservoir, while the deformation zone slowly expands upwards. Thus, first fractures should form in the caprock of a depleting reservoir. This may impair the reliability of the caprock and provide some paths for the leakage of gas from the pool.

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Generally, gas/oil/water production lowers the formation pressure and results in surface subsidence. However, in the case of some hydrocarbon reservoirs which are water driven, the influx of water from the surrounding aquifer will reduce the pressure drop due to the production of fluids. Only if the influx of water is not sufficient to replace the produced fluids there will be subsidence as in other types of hydrocarbon reservoirs.

17.4.4 Calculation of Subsidence in Oilfields The area of subsidence, as shown in Figure 17.11, due to fluid withdrawal is about twice as large as the reservoir from which the fluids are withdrawn. The type of subsidence for hydrocarbon reservoirs is generally differential, resulting in structural damage, rupture of well casings, disruption of pipelines, etc. (Barends et al., 1995; Chilingarian et al., 1995a&b, Dolbrynin and Serebryakov, 1989). Geertsma (1973), along with a study by Yerkes and Castle (1976) identified oilfields with “extreme” subsidence. These fields primarily consisted of gas-depletion reservoirs with large vertical production zones in poorly consolidated alluvial sediments similar to those found in the L.A. Basin. Generally, the large vertical production interval consists of independent pools of oil and/or water aquifers. Their studies, suggested the following contributions to “extreme” subsidence: (1) There is a significant reduction in reservoir pressure as a result of high volumes of produced fluid (oil, gas and water) over the production life of the hydrocarbon field. (2) The major mechanism for production is dissolved gas drive (gas-depletion). (3) Production is obtained from a large vertical interval. (4) Fluids (oil and gas) are contained in loose or weakly cemented (poorly consolidated) sediments. (5) The producing reservoirs have a rather small depth of burial compared to their lateral dimensions. Extreme Subsidence has been an environmental problem in several instances caused by oilfield fluid production within the L.A. Basin (Wentworth et al., 1969). Subsidence is the result of the reduction of pore pressure within the reservoir resulting from fluid production where the pore pressure helps support the geologic overburden. The resulting increase in the effective stress on the pore structure partially collapses the structure, resulting in the compaction of sediments which is propagated to the surface, typically causing a bowl-shaped subsidence as shown in Figure 17.15 at the surface, centered over an oilfield. G. V. Chilingar has suggested that the area of actual surface subsidence can encompass and affect about four times the surface area of the reservoir itself or twice its lateral dimensions. The maximum vertical subsidence occurs at the center of the reservoir.

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Figure 17.15 Total subsidence in Wilmington Oilfield area in 1954. (In: Chilingarian et al., 1995, p. 296, figure 6.8.)

Wilmington Oilfield subsidence reached approximately 8.5 m before corrective action was taken by implementing a massive water injection program (see Figure 17.15). Experience has shown that subsidence can be minimized by a subsidence-monitoring program and repressurizing the formation by reinjecting produced water. Standard subsidence-monitoring that can be used throughout the world (Endres et al., 1991) is the Global Positioning Satellite System (GPS). Many subsidence problems of the past can be directly traced to the failure to perform adequate monitoring and reinjecting fluids to prevent subsidence. Conventional surveying and now satellite geodesy permit determination of both vertical and horizontal movements of the land surface above oilfields with great accuracy and at relatively minimal cost. Vertical reservoir subsidence due to compaction (a reduction in reservoir thickness) is the result of the partial collapse of sediments (pore space) in those reservoirs where the pore pressure partially supports the overburden pressure. The total overburden pressure (pt) is supported by the pore pressure (pp) and the grain-to-grain or effective pressure (pe), i.e., pt p p pe . As the pore pressure decreases due to fluid production, the effective stress in the rock matrix structure increases causing a compaction of the formation. When the reservoir lateral dimensions are large compared to the vertical height, Geertsma (1973) suggested that reservoirs deform predominately in the vertical plane. Vertical compaction can be

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dz , z cmdp. The vertical reservoir coefficient of compressibility may be

characterized for a reservoir by the vertical strain in the reservoir: Ez or Ez

1 dz . Due to the nature of the structure of reservoirs, cm z dp is usually not a constant, but rather a function of p ( pi pc ), the difference between current reservoir pressure, pc, and initial pressure, pi. The coefficient of vertical compressibility, cm is dependent upon a number of factors, such as rock type, degree of cementation, porosity, depth of burial, etc. Figure 17.16 presents a general relationship between porosity and the coefficient of vertical compressibility for unconsolidated sediments at defined as cm

Unconsolidated reservoirs

Semi-unconsolidated reservoirs 1000 m depth of burial = effective vertical stress 2

1000 m depth of burial = effective vertical stress

1

3000 m depth of burial = effective vertical stress

2

40 40

4 3000 m depth of burial = effective vertical stress

10

25 30 35 40 45 Porosity, %

20

10

0 25 30 35 40 Porosity, %

cm for semi-consolidated rock, 105 cm3/kg

20

cm for semi-consolidated rock, 105 cm3/kg

30

cm for unconsolidated rock, 105 cm3/kg

cm for unconsolidated rock, 105 cm3/kg

1

30

20

10

015

25 35 Porosity, %

3

2

1

15

35 25 Porosity, %

Figure 17.16 Uniaxial compaction coefficient cm (vertical axes) for unconsolidated and semi-consolidated sandstone reservoirs. The effective vertical stresses σ1. range from 100 to 200 kg/cm2, correspondin to a depth of burial of 1000 m and σ2 = 300 to 600 kg/cm2 for a depth of burial of 3000 m for normal pressure reservoirs. (Modified after Geertsma, 1973, figures 1 & 2. 736 & 738.)

Subsidence as a Result of Gas/Oil/Water Production

Production of fluids from a reservoir

Compaction of reservoir rocks

Formation of faults and fractures

Subsidence of ground surface

Increase in gas migration

Earthquakesmovement along preexisting faults

Formation of faults and fractures

Regional subsidence

289

Microseismic activity

Formation of additional fractures and movement along preexisting faults

Formation of additional faults and fractures

Figure 17.17 Schematic diagram of system relationships among production of fluids, compaction, subsidence, and seismic activity. (After Chilingarian et al., 1995, figure D-1, p. 461.)

depths of 1,000 m and 3,000 m. Geertsma (1973) suggested that the vertical compaction coefficient, cm, could range between 20 to 40 10 5 cm2/kg for sediments similar to those found within the L.A. basin. For detailed analysis, see Geertsma (1973) and Chiligarian et al. (1995). In regard to subsidence, the main factors that dominate reservoir compaction behavior are: (1) the reduction in reservoir pressure as a result of the production of fluids, (2) the vertical extent over which this pressure reduction takes place, and (3) the order of magnitude of the relevant physical deformation properties of the reservoir itself. The combination of large vertical production intervals and/or thick stacking of producing pools (layered reservoirs) of unconsolidated sediments can result in significant or extreme vertical surface subsidence. It should also be noted that a sizable degree of compaction can be expected even in a well-consolidated rock for the particular conditions of large pore-pressure reductions and a sufficiently large vertical producing interval. Figure 17.17 illustrates the interrelationship among earthquakes, gas migration, and subsidence resulting from oilfield production (Chilingarian et al., 1995).

17.4.5 Permeability Seals for Confined Aquifers A permeability seal (caprock) is required in order to have a closed or leakyproof compaction system in a confined aquifer for hydrocarbon systems. Bradley (1975) described seals in three dimensions, that is, top, bottom

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and lateral containment of the fluids within the sediment body. The bottom seal for hydrocarbon reservoirs can be simply the density difference between water and hydrocarbons (Bradley, 1975, p. 971). Lateral or horizontal permeability seals can be faults, lateral diagenetic and lithologic changes in facies, or existence of evaporite bodies. Vertical seals arise from lithologic changes, fault displacement or diagenetic changes. Myer (1968) stated that the thickness of a seal may be variable, but it is assumed to be thin with respect to both thickness and lateral extent of an abnormal pressure zone. Pressure changes can be abrupt laterally across faults or vertically across bedding. Bradley (1975) stated that the manner in which a seal is maintained is an enigma. High pore pressures generated by compaction and aqua-thermal pressuring at great depth could fracture the argillaceous sediments. If the sediments are relatively unconsolidated, such vertically directed fracturing would be self-sealing owing to the plastic nature of the argillaceous sediments. Another healing mechanism could be the precipitation of minerals resulting from the release of pressure (Bradley, 1975) and/or a decrease in temperature across this boundary, as described by Lewis and Rose (1970). Seals in the geologic column have existed over a long period of geologic time and many have survived destruction during tectonic activity. The fact that permeability seals remain intact suggests that the above-mentioned mechanisms may heal any damage to these barriers. (For further discussion, see Powley, 1990.)

17.4.6 Fissures Caused by Subsidence Tensile horizontal strain can cause fissures on the Earth’s surface (Guacci, 1979; Beckwith et al., 1991; Holzer, 1984; Lister and Secrest, 1985; Love et al., 1987; Pewe et al., 1987; Pampeyan et al., 1988; Contaldo and Mueller, 1991; Haneberg et al., 1991; Keaton and Shlemon, 1991). Mostly, large surface fissures are caused by withdrawal of water from shallow aquifers, as a rule, alluvial. Withdrawal of oil or water with dissolved gas, with substantial formation pressure decline, also causes surface deformation, which mostly consists of horizontal displacements and fractures (Pratt and Johnson, 1926; Strehle, 1989). Full depth of cracks and fissures should be investigated. Origin and occurrence of earth fissures with dewatering of phreatic aquifers in Arizona, California, and Nevada have been studied by Holzer (1984). A common mechanism of fissure generation is localized differential compaction of unconsolidated aquifer material over bedrock irregularities. Association of earth fissures with zones of variable aquifer thickness

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suggests the occurrence of differential compaction (Jachens and Holzer, 1979). Differential compaction is the dominant source of horizontal tension causing earth fissures in the Picacho Basin, Arizona. An analysis of tensile strains at fissures at the times of their formation ranged from 0.1% to 0.4% (see Figure 17.18). The deepest reported fissure [more than 16.8 m (55.1 ft)] was located near Pixley in the San Joaquin Valley, California (Guacci, 1979). It was 0.8 km (0.5 mile) long and 2.4 m (8 ft) wide. The fissure was open to a depth of 1.8 m (6 ft) (Figure 17.19). Reported cracks attributed to hydrocompaction extended up to 4.4 m (14.5 ft) deep and were no more than 1 cm (0.4 in) wide (Beckwith et al., 1991). Contaldo and Mueller (1991) studied 13 discrete locations in the Mimbres Basin in southwestern New Mexico. They found that measurable fissure depths range from less than 0.3 to 12.8 m, whereas the width of fissures ranged from an incipient hairline to 9.7 m (see Figure 17.19). Little is known about the full depth of these cracks and fissures, which is important from the potential gas migration viewpoint. Kreitler (1977), Gabrish and Holzer (1978), Holzer and Thatcher (1979), and Van Sickle and Groat (1981) have studied the effect of subsidence on faulting. Holzer and Thatcher (1979) investigated changes of  surface altitudes on both sides of the Picacho fault (Figure 17.18). They simulated the process of differential movements of fault sides and showed that the difference in altitude changes of sides depends on the angle of a fault. Physically, it is quite clear that existing faults will provide differential movements of their sides if a shear stress exists, relative to the fault plane. The widths of old and new fractures should be studied from the upward gas migration viewpoint. West Subsidence, m

0.0

East

1964 Datum 1968 Datum

0.5 500 m

1.0

1977

m

Datu

Figure 17.18 Subsidence profiles across the Picacho Fault, AZ. (Modified after Holzer and Thatcher, 1979; in: Gurevich and Chilingarian, 1993, figure 6, p. 247.)

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0 Cracks

3

Trench floor

6 0

3

6

9

12

15

18

21

24

Fissure Ground surface

Depth, m

0

3

6

Cracks Trench floor

Figure 17.19 Trench logs of the Pixly fissure, San Joaquin Valley, CA. I I 21 24 (Modified after Guacci, 1979; in: Gurevich and Chilingarian, 1993, figure 5, p. 246.)

The issue of the full depth range of fissures to the producing formation, which is very important from the gas migration/leakage viewpoint, remains unexplored. It is suggested by the authors that surface cracks likely extend much deeper than measured. This problem needs extensive examination.

17.5 Case Studies of Subsidence over Hydrocarbon Reservoirs 17.5.1 Los Angeles Basin, CA, Oilfields, Inglewood Oilfield, CA An instructive review of subsidence rates in the Los Angeles Basin, CA, can reveal serious environmental urban problems, as a result of subsidence, that have been caused by oilfield production. Chilingarian et al. (1995) found that subsidence exists over virtually every oilfield and producing horizon in the Los Angeles Basin. Figure 17.20 shows the location of oilfields located in the Los Angeles Basin. The Inglewood Oilfield, discovered on September 1924, lies under the western half of the Baldwin Hills area. It covers an area of about 4.9 km2. In 1963, there were more than 600 producing wells. The Inglewood Oilfield consists of nine major groupings of layers or pools of intermixed oil and water aquifers located about 9 miles west of the center of Los Angeles. The

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Figure 17.20 Distribution of oilfields in the Los Angeles Basin, CA. (After California Division of Oil and Gas, 1961.)

field, as shown in Figure 17.21, is a faulted anticline. The thickness of the deposits in the field is over 8,000 ft (alluvial Pliocene and Miocene sediments) with the average depth of pools ranging from 950 to 8,400 ft. The discovery well was drilled in 1924. Over 693 wells have been drilled in this field; many prior to the 1950s when cementing practices were not recorded or regulated by today’s standards (see California Division of Oil and Gas, 1961). Historically, there has been little urban development above the reservoir and so environmentally the development of the field has presented few problems; however, there is a record of abandoned and production wells leaking fluid to the surface during the development of the waterfloods in the Vickers zone. There is also a record of water passing through fault planes within the Vickers waterflood at differential water pressures greater than 150 psi. Due to the lack of urban development and monitoring for this field, subsidence is likely present but basically unrecorded with the exception of the area of the Baldwin Hills Dam failure.

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Newport fault A

A

B

B

Newport fault

Figure 17.21 Structure and contour map of the Inglewood Oilfield showing location of the Newport Fault. Contours on the Vickers-Machado zone. (After California Division of Oil and Gas, 1961, p. 561.)

17.5.1.1 Baldwin Hills Dam Failure On December 14, 1963, at about 11:15 a.m., an unprecedented flow of water was heard in the spillway pipe at Baldwin Hills Dam in the Inglewood Oilfield area of Los Angeles County. A short time later the earthen dam failed and water broke violently through the downstreamface of the dam (causing property damage to 60 homes located below the dam and six deaths) flooding a 4-square-mile area. The Inglewood Oilfield lies under the area of the site of the water reservoir on the south and west. The nearest reported production from the Inglewood Oilfield, at the time of the reservoir failure, was from three wells within 213 m of the south rim of the dam.

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The Baldwin Hills earthen dam formed a large water reservoir that held water in a highly developed residential portion of Los Angeles and was located over a large oilfield with two large-active faults. Although an ongoing surveillance for leaks within spillways had been carried out, no monitoring for oilfield subsidence had been undertaken. The owner of the dam, the Los Angeles Department of Water and Power, had operated the dam continuously from July 1951 until its failure on December 14, 1963. Analysis of this catastrophe revealed that the earthen dam failure was due to differential subsidence of the earth which correlated directly with the Inglewood Oilfield fluids production. The total area of subsidence resembled an elliptical bowl with its center about 805 m west of the reservoir and centered over the oilfield. Subsidence at the reservoir site was about 0.9 m, compared to nearly 3.4 m at the subsidence bowl (Figure 17.22). Noteworthy was the fact that the southwest corner (viz., N B’ 0.95 (25) 0.1 (2)

Reservoir faults

1.64 (25) 0.20 (2)

0.05

Dam fail Reservoir

0.10 0.15 0.20

2.21 (27) 0.28 (2)

1.85 (25) 0.22 (2)

B

PBM 68

Inglewood fault 0

5000 Scale-feet

5

Contours of equal rate of settlement as of 1961, feet per year Observed cracks Bench mark

1.64 (25) 0.20 (20)

Direction and magnitude of horizontal movement in feet for number of years in parentheses Approximate oil field limits

Figure 17.22 Horizontal movements and subsidence rates in the area of the Baldwin Hills Dam. (Modified after Lee, 1976, p. 301, figure 1.)

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direction of maximum subsidence) had dropped more than the northeast corner, resulting in differential settlement across the dam of approximately 0.15 m. Figure 17.23 shows the subsidence of several local benchmarks between 1918 and 1974. Furthermore, a review of survey data from 1934 to 1961 and 1963 showed lateral movement in the direction of subsidence depression. The Inglewood-Newport Beach Fault (an active major strike-slip fault) bisects this area with numerous tension relief faults branching off the main fault (see Figure 17.21). There was potential for differential movement along individual fault blocks. Indeed, a post-accident investigation revealed that differential fault block movement had caused rupturing of the asphaltic membrane used as a water seal over the floor of the dam. Although fluid extraction and resultant subsidence were the prime contributors to the rupture of the reservoir, there is substantial evidence to indicate that water injection to stimulate oil production was also a contributing factor as it caused differential uplift in portions of the reservoir and possibly led to fault movement (Hamilton and Meehan, 1971). The main lesson to be learned is that differential subsidence was responsible for this disaster and property loss, which could have been avoided if

Cumulative subsidence in feet since 1917

1

1918

1926

1934

Year 1942 1950

1958

1974

PBM 12

2 3

1966

1917

1910 0

PBM 31 (baldwin aux.)

Two possible paths of subsidence of PBM 122 prior to 1943

4 PBM 68 (BM “DD”)

5 6 7

(BM “saddle”)

8 9 10 11

Legend Dates when elevations were taken

PBM 122

Note: Dashed lines indicate possible paths of subsidence where no data are available

12 Subsidence of bench marks baldwin hills area

From T.M. leps, 1964

Figure 17.23 Subsidence of benchmarks, Baldwin Hills Dam area, Los Angeles, CA. (After California Department of Water Resources, Baldwin Hills Reservoir, Apr. 1964, figure 2.5, p. 8.)

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proper monitoring for subsidence had been undertaken. Virtually every oilfield in the Los Angeles Basin has experienced similar subsidence as a result of fluid production (Chilingar and Endres, 2004).

17.5.1.2 Proposed Housing Development Recently, a large housing development was proposed for the Baldwin Hills area, virtually over the mentioned subsidence area. Large retaining walls (exceptionally high) were contemplated to enhance views. If the project had been completed, these retaining walls would have been extremely vulnerable to a known geologically active and subsidence-prone area. The project was halted and the property later sold to the State for use as a public park (Chilingar and Endres, 2005). This case history of the dam failure highlights the importance of proper planning and monitoring of the land movement in an area that has been heavily impacted by major faulting, oilfield subsidence, and secondary recovery. The problem was not uniform subsidence, but rather differential subsidence resulting in vertical stress on the dam. Although not discussed, there is also a likely problem of migration of gas from this oilfield, which currently does not pose a hazard as there is a lack of urban development over the Inglewood Oilfield.

17.5.2 Los Angeles City Oilfield, CA The Los Angeles City Oilfield, CA, consists of three shallow major groups or layers of oil and water aquifers located about 1 mile north of the center of Los Angeles. The field, as shown in Figure 17.24, is a faulted homocline. The total thickness is about 1,500 ft of alluvial Miocene sediments with the average depth of pools ranging from 375 to 1,700  ft. The discovery well was drilled prior to 1892. About 1,250 wells have been drilled in this field. Many of these wells were drilled prior to record keeping. The wells drilled prior to the 1950s were not abandoned by today’s standards. Intense residential and commercial development has occurred over this old field (see California Division of Oil and Gas, 1961).

17.5.2.1

Belmont High School Construction

The Belmont Learning Center, a proposed high school in downtown Los Angeles, was constructed over the Los Angeles City Oilfield. The site chosen was on a 0.14 km2 parcel of land. This location is over the shallow oilfield that has a surface outcrop just north of the building site. The area is

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Figure 17.24 Los Angeles Oilfield, contours on top of 1st Oil Sand. Productive area is shaded. (After California Division of Oil and Gas, 1961, p. 598.)

also part of the Elysian Park blind thrust fault system that has a generally east-west trend, which helps explain the uplifting and tilting of the petroliferous formation. Oil wells in the area continue to produce from shallow oil deposits at a depth no greater than 213 m. Most of the wells producing oil today were drilled in the early 1900s, and lacked a proper cement completion. Although the gas production is minimal, all of the produced oilfield production gases are released to the atmosphere in the residential area above the wells. This includes four operational wells at the northwest corner of the school property.

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299

Environmental studies, undertaken only after construction began, revealed oilfield gas seepage to the surface over most of the 0.14 km2 parcel and the surrounding area, including the area directly under the school buildings. The project was abruptly halted when gas seepage was detected in the main electrical vault room of the project, just before the power was to be energized. Soil gas studies revealed that methane (explosive levels) and other gases are migrating to the surface, including toxic gases such as hydrogen sulfide. Measurements at the surface revealed releases to the air of over 300 parts per million (ppm) of hydrogen sulfide (Endres, 1999, 2002). Investigation in the area revealed that the migration to the surface was common in this area. After a lengthy discussion, the project was completed and used as an administrative center rather than a school site. This case history clearly identifies the caution required in evaluating the environmental suitability of developed sites located over oilfields, where there are migrating hydrocarbon gases, especially in the case of school construction. The State of California has passed recent legislation that requires direct participation by the Department of Toxic Substances Control (DTSC) in the future school site selection process in order to avoid a repeat of the Belmont failure.

17.5.3 Playa Del Rey Oilfield, CA The Playa Del Rey Oilfield consists of two major groups or layers/pools of oil and water aquifers located about 13 miles southwest of the center of Los Angeles. This field, as shown in Figure 17.25, consists of Upper and Lower zones and is an anticline over a basement high. The overall thickness of the sediments is about 2,000 ft (alluvial Pliocene and Miocene) with the average depth of pools ranging from 4,000 to 6,400 ft. The discovery well was drilled in 1929. Over 320 wells have been drilled in this field and many when cement was not used or when cementing practices were neither regulated nor recorded. Overlying this oilfield is a dense, highly developed, residential area (see California Division of Oil and Gas, 1961).

17.5.3.1 Playa Del Rey Marina Subsidence The oldest periodic leveling surveys of the land over the Playa Del Rey Oil Field were made by the U.S. Coast and Geodetic Survey in 1925 to 1927 and 1931 to 1932. During this period of 6 years as much as 5 in. of subsidence was observed. Studies of old topographic surveys indicate that the Venice area has had little subsidence prior to the 1920s. A later survey in

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Depth, ft 4000’

6000’

Figure 17.25 Playa Del Rey Oilfield with contours on top of the Franciscan Schist. (After California Division of Oil and Gas, 1963, p. 634.)

1936 indicated that rate of subsidence had increased to 1 in. per year. Based upon later surveys, the subsidence rate appeared to decrease over the years from 1936 to 1970 (see Figure 17.26). Since 1964, the average rate of subsidence along Balboa Creek appears to be related to the depletion of ground water in underlying aquifers. Subsidence in the area of the Venice Oilfield is likely caused by a combination of oilfield production and regional ground water extraction (DOGGER). Today, the subsidence in this area appears to be primarily due to water withdrawals from the groundwater aquifer and possibly the compaction of sands, silts and muds near the surface. Little subsidence monitoring has occurred since 1970 despite the fact that fluids continued to be produced. The Marina Del Rey breakwater overlying this portion of the oilfield is likely subsiding as is the coastal area. Oil production in the Venice area of the Playa Del Rey Field began in 1929. This area has produced 82% of the oil production of this field. A large

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301

Gas storage area

0

Scale in miles 1

2

Figure 17.26 Subsidence in the Playa Del Rey Oilfield. Vertical movement in feet occuring between 1937 to 1970. (After California Division of Oil and Gas, 1961.)

reduction in reservoir pressure occurred from 1929 to 1944, when the initial pressures of 1,900 psi decreased to about 100 psi. Nearly all of the oil wells in the Venice area have been abandoned and there is currently little subsidence from hydrocarbon withdrawal; however, environmental problems exist as there is water extraction from the aquifer in the area and potential problems of gas migration through improperly abandoned wells (see Chilingar and Endres, 2004).

17.5.4 Torrance Oilfield, CA The Torrance Oilfield consists of three major groups of layers/pools of oil and water aquifers located about 8 miles southwest of the Long Beach, CA. This field as shown in Figure 17.27 consists of a faulted anticline and is considered by many as an extension of the Wilmington Oilfield. The overall thickness of the sediments is about 1,500 ft (alluvial Miocene) with the average depth of pools ranging from 3,100 to 4,400 ft. The discovery well was drilled in 1922. Over 1,541 wells have been drilled in this field, many of which were not cemented. Overlying this oilfield is a dense, highly developed, residential area. (See California Division of Oil and Gas, 1961.)

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do

Re nd eld

fi ch

ea

ob

Figure 17.27 Torrance Oilfield showing the geologic structure on the top of Main Zone. The Redondo Beach Oilfield is an extened portion of the Torrance Oilfield as shown above. (After the California Division of Oil and Gas, 1961, p.674.)

According to the California Division of Oil and Gas (1961), the greatest amount of subsidence in the Torrance Oilfield amounted to 0.8 ft from 1953 to 1970 and occurred where the Torrance Oilfield abuts the Wilmington Oilfield. In a 12-year period prior to 1953, subsidence reached 0.2 ft. Although subsidence is not a great problem for the Torrance Field, it presented a serious problem for the Redondo Beach marina area which overlies a portion of the Torrance Oilfield.

17.5.5

Redondo Beach Marina Area, CA

The Redondo Beach Oilfield is the western extension of the Torrance Oilfield located under the harbor area of the City of Redondo Beach (Figure 17.27). This area is about 12 miles northwest of the city of Long Beach, CA. This edge area of the Torrance Oilfield consists of layers of hydrocarbon-bearing sands intermixed with layers of water-bearing sands. Initial production in this area was initiated in 1943, but the area remained

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relatively undeveloped until the City of Redondo Beach authorized drilling of directional wells under the marina and breakwater area. Thus, the fluid production (oil and water) from this area increased significantly. During a winter storm in January 1988, waves overtopped a breakwater constructed by the U.S. Army Corps of Engineers built to protect the Redondo Beach King Harbor Boat Marina and surrounding commercial structures. Subsidence had lowered the height of the breakwater (Figure 17.28), which resulted in the destruction of the Portofino Inn and many facilities in the area. The heights of benchmarks used by the U.S. Army Corps of Engineers to construct the breakwater were based on a U.S. Coast and Geodetic Survey of 1945. These benchmarks were assumed to be fixed, but were actually lower due to the subsidence as a result of the high fluid production from the Redondo Oilfield. The Corps of Engineers were not aware of subsidence in this area until 1985. The surveys in 1985 showed the breakwater crests to be as much as 1.5 m below the original design elevations. The breakwater no longer had the necessary height to protect the city. Nothing was done to protect the harbor or to warn the commercial establishments prior to the storm of January 1988. This disaster could have been averted if the subsidence had been recognized and the breakwater elevation increased to the proper levels (see Chilingar and Endres, 2004).

17.5.6 Salt Lake Oilfield, CA

Breakwater elevation loss, ft

The Salt Lake Oilfield is located in Los Angeles, CA, east of the town of Beverly Hills. This field consists of four major groups of layers/pools of oil and water

North breakwater original height

0 –1 –2 –3 –4 –5 55 60 65 70 75 80 85 Year

Figure 17.28 Changes in the North Redondo Beach breakwater elevation during the period of 1955 to 1980. (Data obtained from U.S. Army Corps of Engineers; in: Robertson et al., 2012.)

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aquifers and is a stratigraphic trap along two plunging anticlinal noses (Figure 17.29). The overall thickness of sediments is about 1,000 ft (alluvial Pliocene and Miocene) with the average depth of pools ranging from 1,000 to 2,850 ft. The discovery well was drilled in 1902. Over 500 wells have been drilled in this field, many when cement was not used or when cementing practices were neither regulated nor recorded (see California Division of Oil and Gas, 1961). Overlying this oilfield is a dense, highly developed, residential area and the La Brea Tar pits. The tar pits are an excellent example of fluids (oil and gas) migrating up along a fault to the surface. After a rainfall in this area, at cracks in the sidewalks, paved areas, and roads, one can observe small bubbles of gas. When captured, this gas burns when ignited. Further examination of the paved areas after the rainfall shows small quantities of oil that has been carried by the gas and water to the surface. The area over the Salt Lake Oilfield has had a history of fires and explosions. It is also subjected to surface subsidence, which is reflected in broken sidewalks, paved areas, etc.

Depth, ft 1000’ 1500’ 2000’ 2500’ 3000’

Figure 17.29 The cross-section and geologic structure of the Salt Lake Oilfield. (After California Division of Oil and Gas, 1961, p. 652.)

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17.5.7 Santa Fe Springs Oilfield, CA The Santa Fe Springs Oilfield consists of 10 major groups of layers/pools of oil and water aquifers located about 12 miles southeast of the center of Los Angeles. The structure of this field is a dome (Figure 17.30). The overall thickness of the sediments is about 7,000 ft (alluvial Pliocene and Miocene) with the average depth of pools ranging from 3,580 to 9,100 ft. The discovery well was drilled in 1919. Over 1,283 wells have been drilled in this field and many when cement was not used or when cementing practices were neither regulated nor recorded. Overlying this oilfield is a residential area. (See California Division of Oil and Gas, 1961.) Many of the concrete buildings, sidewalks, paved streets show evidence of cracking, which is probably due to differential subsidence. The authors determined the integrity of operational oilwells in the Santa Fe Springs Oilfield in the 1990s. To facilitate this review, a time period was

Figure 17.30 Structure and cross-section of the Santa Fe Springs Oilfield. Conturs on to of the Bell Zone. (After California Division of Oil and Gas, 1961, p. 662.)

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selected after heavy rains in which the well cellars were partially filled with water. This allowed observation of gas bubbles seeping to the surface along the side of the well casings. Results were systematically recorded for more than 50 wells, some of which were used for waterflooding operations at pressures approaching 84.4 kg/cm2. Approximately 75% of the wells were found to be leaking small amounts of gas. Waterflooding for enhanced oilfield recovery can be a dangerous practice if one does not monitor the maximum injection pressures that could result in hydraulic fracturing of the formation, as these fractures could form pathways for the migration of gas toward the surface. Repressurization of an oilfield by way of water injection or gas injection also requires careful examination of the integrity of both the producing and the abandoned wells throughout the oilfield. A soil gas monitoring program must be implemented in the vicinity of each well and surface fault, to detect the leakage of gas to the surface.

17.5.8 Wilmington Oilfield, Long Beach, CA The Wilmington Oilfield is located approximately 20 miles south of downtown Los Angeles, California in the Wilmington-Long Beach Harbor area (see Figure 17.31). The field is one of a chain of oil accumulations that overlie a basement high extending for approximately 21 miles in a southeasterly direction from the Torrance Oilfield to the Huntington Beach offshore pool. The Wilmington oilfield consists of five major groups of layers/pools of oil and water aquifers and is a gentle faulted anticline overlying the Franciscan Schist. The overall thickness of sediments is about 4,500 ft (alluvial Pliocene and Miocene) with the average depth of pools ranging from 2,200 to 11,000 ft. The discovery well was drilled in 1932 (Colazas and Strehle, 1995; in: Chilingarian et al., 1995). Over 6,150 wells have been drilled in this field, many when cement was not used or when cementing practices were neither regulated nor recorded. Overlying this oilfield is a dense, highly developed, industrial, residential, and major seaport area. The Wilmington Oilfield was officially discovered in 1931, but intensive development did not begin until 1936. By 1951, yearly production was more than 50  million barrels of oil, along with about 53,000 MMcf of gas. By 1965, approximately 3,500 wells had produced about one billion barrels of oil from 7,825 acres. Until 1965, production was confined to the western portion of the Wilmington Oilfield. With the successful solution to the subsidence problem in this portion, development was started in the eastern portion (Long Beach Unit) which extends east

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Figure 17.31 Structure and cross-section of the Wilmington Oilfield. Contours on top of the Ranger Zone. (After California Division of Oil and Gas, 1961, pp. 684 & 685.)

of the harbor area in the City of Long Beach. From the Wilmington Oilfield’s discovery in 1931 to the end of 1990, more than 2.34 billion barrels of oil and 1.1 billion Mcf of gas have been produced from the Wilmington Oilfield. Current daily production is about 71,000 barrels of oil and 1,081,000 barrels of water. Remaining reserves for the field are approximately 600 million barrels (Colazas and Strehle, 1995; in: Chilingarian et al., 1995). According to Colazas and Strehle (in: Chilingarian et al., 1995), more than 1,000  wells were drilled during the initial development of the field from 1932 to 1942. The rapid rate of fluid production led to a subsidence problem. First noticed in 1941, with a drop of more than a foot, it wasn’t initially clear what was causing the subsidence. In 1953, a $30-million program of waterflooding was initiated to slow down the rate of subsidence. Figures 3.32 and 3.33 demonstrate a 9-meter subsidence at the center of the depression in 1954. Reinjected water has helped slow down the rate of subsidence and in some areas the surface has rebounded due to water injection. The area affected by subsidence was about 50 km2. Since the early 1940s, the Wilmington Oilfield has been plagued by an unusually large amount of land subsidence. This was an especially critical

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Figure 17.32 Northwest-southwest cross-section of the Wilmington Oilfield showing profile of subsidence bowl on top of the Wilmington anticline. (After Colazas, 1971; in: Chilingarian et al., 1995, p. 297, figure 6.10.)

Figure 17.33 Wilmingtion Oilfield subsidence unit: 1973 to 1974 subsidence in feet. (After California Division of Oil and Gas, Sixth Annual Report.)

problem because the field is located under the Long Beach and Los Angeles Harbor areas. The City of Long Beach, U.S. Navy, and Southern California Edison Company engaged qualified engineers, geologists and soil experts to investigate the causes and assist in finding a solution to the potential destruction of the industrial, port and naval facilities within this area of

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subsidence. They concluded that restoration and maintenance of subsurface pressures by injection of water would reduce further subsidence. The result of this decision was one of the largest waterflooding programs in the world. (See Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 286.) Currently, field injection of water is in excess of 1.2 million barrels per day into 700 injection wells. With this program in effect, subsidence was stopped. In the areas of maximum repressuring the surface has rebounded over 1 foot. The sequence of rocks encountered in the Wilmington Oilfield, including the depth, net and gross thickness of the sediments, are presented in Tables 17.2 and 17.3 and in Figures 3.32, 3.34 and 3.35. Zone names, boundaries and markers within the zones are those designated by the City of Long Beach, its contractors and other operators in the Wilmington Oilfield. (See Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 287.) The oil-bearing formations in the Wilmington Oilfield range in thickness from 6,400 to 7,500 ft. The age of these formations ranges from Jurassic (?) for the Catalina Schist-Basement complex to the early Pliocene (Repetto) for the Tar Zone. There are seven recognized productive zones in the field. In increasing depth sequence these are the Tar, Ranger, Upper Terminal, Lower Terminal, Union Pacific, Ford and 237-Basement. Table 17.2 lists these zones, their approximate depths at the crest of the anticline, gross thickness and net oil sand thickness. (See Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 290.) The upper four zones are of great economic importance, not only because they have produced the greatest amount of oil, but also because they have made the greatest contribution to subsidence. In addition, they have been the subject of numerous compression tests conducted by investigators. Colazas and Strehle (1995; in: Chilingarian et al., 1995) have described the most productive zones in the Wilmington Oilfield as follows (See Figure 17.35): 1. The Tar Zone consists primarily of unconsolidated fine- to coarse-grained, fairly well sorted lenticular sands, with soft, light brown to olive green interbedded siltstones. The sands average approximately 40% of the bulk of the zone. 2. In the Ranger Zone, the top of the Miocene is found near the “G” electric log marker (see Figure 17.34). The Ranger Zone consists of alternating layers of fine- to coarse-grained, fairly well to poorly sorted unconsolidated sands. The Pliocene siltstones are firm, sandy and have a distinctive brown to olive green color, whereas the Miocene siltstones and shales

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Table 17.2 Geologic formation data, oil producing zones and summary of reservoir data for the various zones of the Wilmington Oilfield, CA. (After Colazas, 1971; in: Chilingarian et al., 1995, table 6.1, p. 288.) Age

Formation

Form. Thick., ft Prod. zone

Recent

Unnamed

± 1000

Pleistocene San Pedro Pliocene

Upper Pico

± 800

Elect. log mark.

Oil Average Aver. Sand interval gravity, porosity, perm., Zone o mD % thick., ft in zone API

Lithology and remarks

Gaspur

± 189

200/400 Silverado

± 220 ± 600

Upper Pico

± 800

Alternating sands and siltstones

0 to 200

Sands and siltstones

Middle Pico 0 to 200 Upper Pico

Fresh water sands, gravels and clays

Unconformity Pliocene

Repetto

700 to Tar 1400

Puente

± 5,300

300 to ± 40 400

Old area F to G New area Fo to G

400 to ± 40 500

12 to 15

35

± 1000

12 to 25

35

700 to 1500

12 to 25

35

700 to Hard brown 1500 shales and sands; sands are fine and unconsolidated at top, becoming firmer coarser grained at bottom

50 to 70 14 to 25 Upper Old area HX 400 to 850 60 to 80 14 to 25 Terminal to AA 400 to New area 900 HX to AA

35 35

450 450

Lower AA to AE Terminal

500 to 60 to 80 20 to 31 800

30

450

Union Pacific AE to AM

400 to 25 to 30 27 to 32 20 to 25 900

150

Ford

AM to BA

750 to 25 to 35 28 to 32 1200

25

100

“237”

BA to 200 to 20 to 40 28 to 32 basement 2650

25

275

Upper Ranger

Miocene

Old area, S to F New area, T to Fo

Lower Ranger

200 to 400

Grey and green shales, siltstones & sands at top grading too brown and fine grained at bottom

600 to 700

Old area G to 150 to ± 30 HX 250 New area G to HX1

Unconformity

Upper Mohnian

Unconformity Jurassic

Basement

± 100

Schist, fractured

Subsidence as a Result of Gas/Oil/Water Production Table 17.3 Depth and thickness of Wilmington Oilfield oil zones. (After Colazas, 1971; in: Chilingarian et al., 1995, table 6–11, p. 291.) Productive Zone

Depth, ft

Zone gross thickness, ft

Net oil zone thickness, ft

Tar

2,050 to 2,350

200 to 400

50 to 95

Ranger

2,350 to 2,850

400 to 750

220 to 420

Upper Terminal

2,850 to 3,350

600 to 750

400 to 500

Lower Terminal

3,350 to 3,850

700 to 800

450

Union Pacific

3,850 to 4,500

900 to 950

230 to 285

Ford

4,500 to 5,400

950 to 1,200

500 to 600

“237”

5,400 to 5,600

2,650

75

Basement (Schist)

±5,600

are dark brown to grey, becoming progressively darker with depth. The Miocene shales are well laminated, diatomaceous and are locally referred to as “poker chip” shales. They average approximately 40% of the bulk of the zone. (See Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 290.) 3. The Upper Terminal Zone consists primarily of soft to easily friable very fine-to medium-grained, fairly well sorted arkosic sands, interbedded with layers of claystone, siltstone and occasional hard sandstone calcareous members locally referred to as “shells”. The lower sand members are generally coarser than the upper members. The sands average approximately 70% of the bulk of the zone. 4. The Lower Terminal Zone consists primarily of sands that are similar to the Upper Terminal Zone, but somewhat coarser and more massive, becoming firmer with depth. The siltstones and shales are well indurated and have a dark grey color. The sand content is estimated at 60% to 80% of the bulk of the zone.

311

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Fracking 2nd Edition

AE Union pacific

Uncomformity L S TAR

Upper miocene Puente Delmontian

5000’

2000’

F1

Ranger G HX Upper terminal AA

2500’

Ford

5500’

BA

3000’

6000’

6500’ “237”

3500’

7000’

Lower terminal AE

4500’ AO

1500’

Upper miocene Puente Upper mohnian

Pliocene Repetto Pico

Recent and pleistocene

Uncomformity Jurassic (?) Schist

4000’

Figure 17.34 Composite electric log showing stratigraphic sections and markers of the Wilmington Oilfield. (After Colazas, 1971; in: Chilingarian et al., 1995, p. 287, figure 6.2.) Long beach

0’ Recent 1000’ Pleistocene 2000’ Pliocene 3000’

Sea level

0’ Old area

New area 1000’ Tar

2000’

Ranger U. terminal L. terminal

4000’

3000’ 4000’

Union pacific 5000’ Miocene 6000’

Ford 237

5000’ 6000’

7000’

7000’

8000’

8000’

9000’

9000’

10000’

10000’

Figure 17.35 Geologic section along axis of Wilmington Anticline showing approximate water/oil limits. (After Mayuga, 1970; in: Chilingarian et al., 1995, p. 289, figure 6.3.)

Subsidence as a Result of Gas/Oil/Water Production

313

The lower three zones are comprised of the Union Pacific, Ford and 237 zones and consist primarily of thin to massive sands ranging in grain size from fine to coarse and pebbly. The shales vary from soft claystones and mudstones to true, hard, dense shales. Generally, the amount of subsidence in these zones is considered to be small. (See Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 291.) The sands of the Union Pacific and Ford zones are thin-bedded to massive, fine-to coarse-grained, fairly well to poorly sorted and are interbedded with hard, dense, dark grey to black siltstones and shales. Hard sandstone members, previously called “shells,” are more prevalent in these formations. Usually, during coring operations the core barrel has to be pulled out of the hole in order for the “shells” to be drilled with a rock bit and, thus, resume coring operations. The Union Pacific Zone is thinly bedded, with the sands becoming massive, coarse and pebbly in the lower part of the Ford Zone. The degree of induration of sediments is, in general, directly related to the depth of burial. The hard dense shales in the deeper horizons grade to siltstones, soft claystones and mudstones. (See Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 291.) The 237 Zone consists of 2,000 ft of massive, poorly sorted, locally friable to well cemented arkosic sandstones interbedded with dense black shales. The lower 650 ft consist of black, dense, locally fractured, well-bedded shale, with brown phosphate nodules and occasional thin interbeds of hard, medium- to coarse-grained sandstone. The fractured nodular shale and the upper 100 ft of fractured basement is oil productive in the East Wilmington portion and is known as the “D-118” sub-zone. The Wilmington Oilfield structure is a large, broad, asymmetrical anticline having a northwest-southeast axial trend. The low angles of dip of the unconsolidated beds near the crest, the presence of tension faulting and the heavy overburden result in an unstable structure susceptible to compaction. The structure is cut by numerous major and minor faults thus dividing it into hundreds of fault blocks, down-dropped wedges and individual reservoirs. The Wilmington Oilfield geologic structure and the geologic structures surrounding it are extremely complex. Flow paths and pressure conduits exist peripheral to the field and there is no guarantee that all fluids injected into the reservoirs for subsidence control will remain within the Wilmington Oilfield structure. As a matter of fact, chances are they will not. Constant surveillance and monitoring of pressures are and will be of extreme importance for a considerable time into the future in order to prevent a renewal of Long Beach’s past disastrous subsidence. According to Colazas and Strehle (1995; in: Chilingarian et al., 1995, p.291), geodetic leveling surveys established that the San Pedro-to-Seal

314

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Beach coastal areas have been naturally subsiding since the early 1900s. Since the 1930s, survey crews from the cities of Los Angeles and Long Beach, the United States Coast and Geodetic Survey, and other agencies have regularly conducted leveling surveys across the Wilmington area. Generally, during this time, the surveys indicated an average subsidence rate of between 0.02 and 0.04 ft per year. During the summer of 1941, the U.S. Coast and Geodetic Survey conducted a first order leveling survey from the cities of Redondo Beach and San Pedro to a point east of Long Beach over the same level network they had established in 1931. This latest survey showed a subsidence of 0.2 ft at the west city boundary of Long Beach with a gradual increase to 1.3 ft at the easterly end of Terminal Island and then gradually decreasing to practically zero under the City of Long Beach. Inasmuch as the area of maximum subsidence coincided with a Navy dewatering project for the construction of a dock, it was thought that subsidence would stop and perhaps part of the lost elevation would be recovered when the dry dock construction was completed. In July 1945, the U.S. Coast and Geodetic Survey confirmed leveling surveys of the Long Beach Harbor Department which indicated that the easterly end of Terminal Island had subsided 4.2 ft from 1931 to 1945. The results of these surveys and other data indicated that progressive ground movement, oilfield development and fluid production were perhaps dependent events. Subsidence has caused a great deal of damage because the surface land was the center of a busy port and industrial area. By 1962, the rate of subsidence had been greatly reduced as a result of reinjection of water and subsidence was limited to an area of 8 km2 as a result of waterflooding. Up to this date, little uplift from waterflooding had occurred. The cumulative subsidence costs to 1962 were estimated at $100 million (http://www. longbeach.gov/lbgo/about-us/oil/subsidence/). Figure 17.36 shows the relationship between the cumulative production (oil and water production less water injection) and cumulative total subsidence for the Wilmington Oilfield from 1937 to 1967 (Mayuga and Allen, 1998). A historic presentation of net oil production, water injection and subsidence is presented in Figure 17.37. Along with the problems of subsidence, there also have been several minor earth movements between 1947 and 1952. These earthquakes were caused by slippage along several nearly horizontal planes of shale located at depths between 1,500 ft and 2,000 ft. Well damage in the Wilmington area alone was in the millions of dollars. A large amount of horizontal movement was also occurring on the surface. Most surface and near structures such as railroads,

Subsidence as a Result of Gas/Oil/Water Production Meters

Million Million barrels cubic meters 800

Feet 24

7

120

2

532

16 Cumulative total production

400

12

8

266

Cumulative total subsidence

4

1 0

0

Total oil production

3

Maximum subsidence

4

622

20

6 5

315

80

40

133

1942

1938

1946

1950

0

0

1954

Figure 17.36 Curve showing cumulative total production versus cumulative total subsidence of the Wilmington Oilfield, CA (After Mayuga and Allen, 1998.) 250

150

800

Water injection B/D

600

Net oil B/D

100

50

400 Inches per year

Oil rate-thousands of B/D

200

16 14

Subsidence rate

12 Major injection started

Start of L.B. unit (eastern area) 10 % per year decline

200

Water injection rate-thousands of B/D

1,000

8

0 1937

1947

1957

1967

0

Figure 17.37 Historical oil production, water injection and subsidence in the Wilmington Oilfield, CA. (After Mayuga and Allen, 1998.)

pipelines, and transit sheds were cracked, buckled, and bowed due to subsidence (Colazas and Strehle, 1995; in: Chilingarian et al., 1995, p. 294). While various studies were being made by experts to determine what was causing subsidence, the subsiding area continued to grow, gradually assuming shape of a 20-square-mile area of Long Beach, CA, shown in

316

Fracking 2nd Edition

Figure 17.10. The subsidence rate increased to a maximum in 1951 when the center of the bowl was sinking at a rate of more than 2 ft per year and the field had attained its maximum production of oil and gas (see Figure 17.37). Cumulative subsidence reached 15 ft. By 1952, the ground elevation of the Navy Shipyard had sunk below high tide water. By 1958, the total area affected covered over 20 square miles. Horizontal surface movements of more than 10 ft accompanying vertical subsidence caused extensive damage to the existing structures, oil wells, and the U.S. Navy installations. Early 1940s groundwater pumping contributed to subsidence, but the majority of the subsidence resulted from the oil and gas extraction. An average of 42 gallons of water per gallon of oil have been produced by this oilfield (http://www.longbeach.gov/lbgo/about-us/oil/ subsidence/). Gilluly et al. (1948) prepared a report on subsidence for the Wilmington Oilfield. A modification of this report was later published in the Bulletin of the Geological Society of America (1949). After considering a number of possible causes for subsidence, they demonstrated that the progressive surface depression was likely due to compaction of sediments in the oil zones. They examined the evidence and found that the history of the surface movement since 1937 could be explained by compaction of reservoir sands. At about the same time, Harris (1945) made an extensive study for the U.S. Navy, reaching the same conclusion except that he attributed the subsurface compaction to the reservoir shales. Hudson (1957) and other investigators considered all the following factors in their examination of compaction and surface subsidence in the Wilmington Oilfield: 1. Lowering of hydraulic head due to groundwater withdrawals. 2. Oil reservoir sand compaction owing to fluid withdrawals. 3. Compaction of shales and siltstones interbedded with the oil sands. 4. Surface loading by structures. 5. Vibrations due to land usage. 6. Regional tectonic movements. 7. Lack of rigidity of the Wilmington structure. 8. Movements along known faults in the field. 9. A lack of preconsolidation in the sediments. Most investigators who have studied the problem concluded that withdrawals of fluids from the oil zones and the consequent lowering of pressure

Subsidence as a Result of Gas/Oil/Water Production

317

within these zones resulted in compaction of the oil sands and the interbedded siltstones and shales. The relative amounts of compaction between the sands and shales can be inferred from both laboratory compaction and porosity tests and from oilfield operational practices and measurements. Subsequent to the early studies, some of which concluded that shales were the compacting material and some that sands were, more data has been accumulated and new interpretations prepared. For example, based upon extensive laboratory compaction studies, Chilingarian et al. (1995), concluded that sands are just as compactible as clays. Allen and Mayuga (1969) attributed Wilmington Oilfield subsidence to the following causes: (1) reservoir pressure decline due to rapid development and production of fluids; (2) the unconsolidated reservoir sands having little or no cementation; (3) the thin, interbedded shales being susceptible to drainage; (4) the relatively flat overburden supplying a constant load; (5) the lack of severity of folding causing a weak structure that is incapable of supporting the overburden; and (6) normal tension faulting, which weakens the Wilmington structure, whereas compressional faulting would have strengthened it. The actual mechanics of compaction are believed to include rearrangement of sand grains, plastic flow of soft minerals, some plastic deformation of sand grains, and perhaps some crushing of grains or breakage of sharp corners in exceptionally low-pressure reservoirs or pools. Limited crushing of sand grains was observed in the laboratory but the samples were dry and the pressure ranged to 2,500 psi. Due to the high permeability of the sands, a fairly rapid shift in grainto-grain loading results when fluid pressures are lowered, creating a rapid loss of pore volume. In the case of the shales, however, their extremely low permeability results in a slow transfer of load from the pore fluids to the skeletal structure as the fluids are slowly forced from the shales into the relatively lower pressured and more permeable sand members (Figure 3.38). The length of time required for the Wilmington sands and shales to approach equilibrium has been investigated by Allen and Mayuga (1969), Colazas (1971), Converse Engineering Company (1957) and numerous other investigators. The general conclusion of all investigators was that the degree of compaction is a function of unit thickness, depth of burial, cementation, and permeability. Generally, the deeper the burial, the less the compaction due to the existing natural consolidation state of the sediments. According to van der Knaap and van der Vlis (1966), the time for a Venezuelan shale or clay layer to reach equilibrium increases as the square of the thickness. They found that thin shales or clay layers reached

318

Fracking 2nd Edition Overburden load

Well bore

Shale

Sandstone

Shale

Figure 17.38 Diagrammatic shale-water flow to low-pressure permeable sands. (After Colazas and Strehle, 1995; in: Chilingarian et al., 1995.)

equilibrium within a few days to a few weeks, whereas an 8-ft shale might require 16 years and a 20-ft shale might require upwards of 50 years (Figure 17.39). Sawabini et al. (1974) determined the effective bulk compressibility Vp Vb 1 and pore compressibility 1 of unconsoliVbi pe p T Vpi pe p T t t dated sands from the Wilmington Oilfield, where Vbi = initial bulk volume of sample, cm3; Vpi = initial pore volume of sample, cm3; pe = effective pressure (pt – pp), psi; pt = total overburden pressure, psi; and pp = pore pressure, psi. There is an inverse relationship between the effective (grain-to-grain) pressure and the compressibility. The effective bulk compressibility ranged from 7.4 10 4 to 3 10 5 psi 1 in the 0 to 3,000 psi effective pressure range; whereas the effective pore volume compressibility ranged from 1 10 3 to 1 10 4 psi 1. The void ratios in the same pressure range varied from 0.85 to 0.18.

17.5.9 North Stavropol Oilfield, Russia Ternova and Belov (1965, in: Dobrynin and Serebryakov, 1989) described subsidence at the North Stavropol Oilfield in Russia. Maximum subsidence of 14.1 cm was observed during 1961–1962 after 5–6 years of production (Figure 17.40). They proposed the following formula for the determination of subsidence ( h) of the productive horizon:

Subsidence as a Result of Gas/Oil/Water Production

319

1.0

Fractional compaction

0.8

0.6

2’

4’

8’

20’

40’

0.4

100’

0.2

0 0.1

0.5

1

5 10 Time in years

50

100 200

Figure 17.39 Fractional compaction of clay layers of various thickness following instantaneous drop in reservoir pressure. (After van der Knaap and van der VIis, 1966; in: Colazas and Sterhle, 1995, figure 6.12, p. 300.) Yastrebin oil field # 107 (1.37)

# 113 (1.6)

# 111 (1.0) 1.0

1.5

# 115 (1.8)

(a)

Braguny oil field

# 119 (1.0)

# 83 (2.1)

# 82 (2.2)

# 35 (1.53)

# 63 (2.6)

# 114 (0.95) # 65 (2.2)

(b)

# 91 (2.5)

# 87 (2.6)

# 40 (2.4)

# 59 (2.4)

# 43 (2.3) # 76 (1.57)

# 34 (2.56) # 86 (2.39)

Figure 17.40 Subsidence of the Earth’s surface at the Yastrebin Oilfield (A) and Braguny Oilfield (B). Solid circles indicate borehole locations; numbers between parentheses are Δhcalc, values in m. In the case of open circles, Δhmean values are measured. (After Dobrynin and Serebryakov, 1989, figure 124, p. 282; also in: Serebrybryakov and Chilingar, 2000, figure 2, p. 425.)

h h p

(17.4)

where h is the thickness of compacting formation, p is compacting pressure (MPa), and * is the coefficient of formation compressibility (MPa 1). Eq. 17.4 takes into consideration only the productive horizon. Because the only subsidence considered in Eq. 17.4 is that of the productive horizon, the actual surface subsidence was five times higher than that calculated by this equation.

320

Fracking 2nd Edition f

b

(17.5)

m

where f is the producing formation porosity (fraction), b is bulk compressibility of liquids (cm2/kg), and m is matrix compressibility (cm2/kg). Pore compressibility, p, is equal to

1 dVp Vp dp p

P

(17.6)

where Vp is volume of the pores (cm3), and pp is pore (fluid) pressure (kg/cm2). The formula for the coefficient of irreversible compaction ( i, MPa 1) (Dobrynin, 1970) is: o

e

0.014 i D

(17.7)

where 0 is the initial porosity of clays after deposition, and is porosity of clays at a burial depth D (m). The compaction of associated shales must also be considered when studying subsidence. The Braguny and Yastrebinoye oilfields in the TerskoSunzhenskaya region of Russia were examined using geophysical data for the boreholes. The initial average (weighted) porosity of the producing zone, a1, was h

h

i i a1

i 1 h

hi

Vp

(17.8)

Vb

i 1

where i and hi are the porosity (%) and thickness of the ith layer (in m), and Vp (m3) and Vb (m3) are the pore volume and bulk volume, respectively. Upon decrease in the pore pressure by production of fluids, the porosity decreases to a2:

Vp a1 a2

Vb (Vp V Vp ) (Vb V Vb )

1 1

Vb Vb Vp Vp

(17.9)

Subsidence as a Result of Gas/Oil/Water Production

321

where Vb, and Vp are changes in the bulk volume (m3) and pore volume (m3), respectively. Vb , Eq. 17.9 can be also written as Vb S h and Inasmuch as Vp V… = Sh Vb Sh :

1

a1

Vb Vb

a2

Vp

1

1 1

Vp

h h h a1h

(17.10)

where S is the area of deposits (m2), and h is the thickness of formation (m). Also,

a1

exp[

p

( p1

p2 )]

(17.11)

a2

where p is the weighted average coefficient of pore compressibility (MPa 1), and p1 and p2 are, respectively, initial and final low reservoir pressure due to production (MPa 1 ). Thus, from Eq. 17.10:

h h

exp[ p ( p1 p2 )] 1 1 exp[ p ( p1 p2 )] 1

(17.12)

a1

Eq. 17.12, therefore, can be used to estimate the amount of subsidence, depending on the drop in the formation pressure due to production (p1 p2). Obviously, it is necessary to determine h, a1, and p . The thickness of the formation can be determined using geophysical logging methods (electrical, radioactive, and sonic). Curves for the normally compacted clays are prepared on a semi-logarithmic scale (Dobrynin and Serebryakov, 1978). Figure 17.41 illustrates the zones of abnormally low pore pressure as indicated by an increase in the specific resistivity (ohm-m). The thickness of the formation, h, is 394 m. In a new region, which was not studied, the value of h necessary for estimating Dh is established using an analogy with other regions taking

Lithology

Fracking 2nd Edition Depth, m

322

Resistivity, ohm-m

3650

Depth (h), m

3750 1 - Shale 3850 2 - Sandstone

3 - Resistivity of shales with abnormally-low pressure

3950

4

4050

5 - Resistivity of shales

Figure 17.41 Abnormally low formation pressure in the borehole Number 83, Braguny Oilfield, Russia. Lithology: 1 = shale; 2 = sandstone; 3 = abnormally low pressure zones; 4 = curve for normaly compacted clays; 5 = resistivity of shales (ohm-m). (After Dobrynin and Serebraykov, 1989, Figure 122, p. 272; also in: Serebraykov and Chilingarian, 2000, figure 1, p. 413.)

into account the lithological and hydrodynamic characteristics of the area. The a1 is determined using geophysical data:

hss a1

h

hsh ss

h

sh

(17.13)

where hss and hsh are the sums of thicknesses for sandstones and shales in the low-pressured zone, respectively (m), and ss, and sh are the initial porosities (%) of sandstones and shales, respectively. In order to determine p in the area of pressure reduction, one can use the following methods: (1) repeated leveling measurements of the Earth’s surface (repeated measurements of borehole altitudes after pore pressure reduction), using Eq. 17.12; and (2) repeated measurements in boreholes using radioactive logging before and after production. Changes in density divided by the average density of the formation

Subsidence as a Result of Gas/Oil/Water Production

323

h . Thus, one can determine p from Eq. 17.12 h f without repeated leveling. In new regions, p is estimated using analogy with other regions having similar lithology and hydrodynamic conditions. f

is about equal to

The weighted average porosity was determined from Eq. 17.13. The fss and fsh were determined from graphs and analytical functions of porosity versus depth for the Tersk-Sunzhen petroliferous area of Russia, based on data obtained from repeated leveling surveys after 15 years of production (Table 17.3). Using the average value of 8 10 4 MPa 1 for p , hcalc was calculated in boreholes in which repeated leveling was performed. The values obtained ( hcalc) were compared with those determined by leveling ( hmeas). Average absolute error in four boreholes was 0.24 m. Thus ( hcalc) can be obtained using the average p value (Table 17.4). h Based on data calculated using Eq. 17.12, a relationship between and h pressure drop after production (p1 pa1) (where p1 is the initial pressure and pal is the lower pressure after production) was established (Figure 17.42). Using this figure, Dobrynin and Serebryakov (1989, pp. 280–281) estimated the subsidence (Δh) of the Earth’s surface during production from the Cretaceous deposits of the Tersk-Sunzhen petroliferous area of Russia. Figure 17.40 shows the subsidence of the Earth’s surface during the 1969–1984 period above the Braguny and Yastrebin oilfields, with the maximum subsidence corresponding to the crestal areas of anticlines (maximum production). The amount of compaction of the producing formation (and resulting subsidence of the Earth’s surface) can be predicted from the decrease in pore pressure due to production or vice versa. The method presented here is simple and accurate, provided compressibilities are properly determined or estimated (see Rieke and Chilingarian, 1974), which is commonly not the case. Table 17.4 Values of p determined on the basis of repeated leveling for the Braguny Oilfield, Russia. (After Dobrynin and Serebryakov, 1989; in: Chilingar et al., 2002, table 13.1, p. 356.) Borehole number

Depth of interval, m

Interval thickness, m

Porosity, ,%

34

3,533–3,953

420

35

4,073–4,420

40

3,638–4,045

43

3,840–4,220

hcalc, m

—

× 104, p MPa–1

hsh, m

hss, m

hmeas, m

15.9

317

103

2.56

2.39

8.6

347

16.1

278

69

1.53

2.00

6.1

407

15.8

295

112

2.4

2.30

8.3

380

15.9

283

97

2.39

2.16

8.9

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Fracking 2nd Edition (pi–pf), MPa 0

10

20

30

h/h 10–3

2

40 p

=2

p

=4

p

=6

4

p

10 –4

10 –4

10 –4

=8

10 –

4

p

=

10 10 –

4

=

p

6

12 –4

10

Figure 17.42 Relationship between Δh/h and formation pressure drop due to production (Δp = pi – pf) in MPA 1; Δh = subsidence, m; h = formation thickness, m; pi; = initial formation pressure, MPa 1; pf = final formation pressure after a certain amount of production, MPa 1; = initial porosity = 15.9%; and numbers on curve are p = weighted Pore compressibility. (After Dobryin and Serebryakov, 1989; in: Serebryakov and Chilingarian. 2000. figure 3, p. 415.)

17.5.10 Subsidence over Venezuelan Oilfields Venezuela’s total remaining reserves of heavy, extra heavy crudes and bitumen which are producible by primary and cyclic steam technology are 156.1 109 bbl. This can be increased by an additional 136.1 109 bbl by use of steam drive, thus resulting in a total of 292.2 billion barrels (292.2 109 bbl). An important portion of these reserves, mainly of heavy and extra heavy crude oils, has been exploited for many years in the Bolivar Coastal and Boscan oilfields using well established technologies and at competitive costs. Of these two areas, the Bolivar Coastal Fields, is the most affected by reservoir compaction and subsidence. In these two areas, original reserves of heavy and extra heavy oil, amounted to 33.8 109 bbl, of which 19.0 109 bbl remain. These reserves include only those producible by primary means (mainly compaction). These reserves can be increased by further application of steam drive, which has proven to be very successful in the C-3/C-4 and M-6 projects in the Bolivar Coastal Fields at Tia Juana and the Jobo project in eastern Venezuela, where recoveries in some cases were as high as 40% of STOIP are expected. Inasmuch as most of the heavy and extra heavy Bolivar Coastal Field crudes are suitable for this process, the future additional recoveries by steam drive are estimated to be 11.0  109 bbl (Borregales and Salazar, 1987).

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325

The huge heavy, extra heavy and bitumen accumulations in the Orinoco Belt contain some 1.18 1012 bbl of oil. Approximately 10.1% of the Orinoco Belt’s STOIP is producible by already demonstrated primary and cyclic steam technology, yielding recoverable reserves of 135.4 109 bbl. Application of already existing steam drive technology to the heavy, extra heavy and bitumen accumulations in place in the Orinoco Belt will yield an additional future recovery of 136.1 109 bbl (Finol and Farouq Ali, 1974). All of the Orinoco Belt reserves are found in unconsolidated sands and are consequently predisposed for future reservoir compaction and subsidence (Finol and Sancevic, 1995, p. 339). With respect to production, Venezuela has always been an important producer of heavy oil, owing to the Bolivar Coastal Fields, which have also been affected by reservoir compaction and subsidence. The first commercial development took place in 1917 in the heavy oil Mene Grande field in the Lake Maracaibo Basin, 14 km to the southeast of the Bachaquero Field, the southernmost of the BCF. At present, the total productive capacity of the country is 2.6 106 BOPD of which 40% (or 1.0 106 BOPD) is heavy and extra heavy oil. Throughout its history, the Venezuelan oil industry has produced some 14.8 109 bbl of heavy and extra heavy oil, mostly by compaction/subsidence, which has affected the Bolivar Coastal Fields. Cyclic steam injection at depths of up to about 4,000 ft (1,220 m) has been practiced in Venezuela for over 22 years and has resulted in an accumulated production of over 1.0 106 bbl. Two large-scale steamflood projects, the M-6 project in Tia Juana, Bolivar Coastal Field, which has been in operation since 1977, and the Jobo Project in eastern Venezuela, which has been in operation since 1981, jointly contribute 25,000 BOPD to the production of heavy and extra heavy crudes. The cyclic steam injections as well as steamflood projects cause further compaction and subsidence (Finol and Sancevic, 1995, p. 339).

17.5.10.1 Subsidence in the Bolivar Coastal Oilfields of Venezuela The first oilfield in the area of the Mene Grande Field was discovered in 1914. The first prolific well in what was to become the Bolivar Coastal Fields was drilled near a surface oil seep and completed in 1917, but it was not until 5 years later when the Shell R-4 well blew out (at an estimated 100,000 BOPD) that sufficient stimulus was provided for development. The Bolivar Coastal Fields are located on the eastern margin of Lake Maracaibo and comprise the Tia Juana, Lagunillas and Bachaquero fields (Figure 17.43). When the Bolivar Coastal Fields are considered jointly,

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0

10 Km.

20

Figure 17.43 Bolivar Coastal Fields (BCF). (After Finol and Sancevic, 1995; in: Chilingarian et al., 1955, p. 341.)

they constitute one of the largest oilfields outside of the Middle East and contain heavy and extra heavy crudes having gravities lower than 20° API. There are several types of traps in the Bolivar Coastal Fields: (1) asphalt seals in the oil seepage areas; (2) fault and fold traps; (3) lithological variations that form permeability barriers in the producing members; and (4) stratigraphical unconformity traps, caused by erosion of Eocene sandstones and sealing by overlying Oligocene— Miocene shales. Although many trap units have been recognized in the BCF, a southwest—northeast cross-section of the Bolivar Coastal Fields (Figure 17.44 and Figure  3.45) show the Oligocene—Miocene monocline seal, close to the surface or on the surface, is the most important trap of heavy and extra heavy crudes. Energy-wise, the main primary driving mechanisms in the Bolivar Coastal Fields are solution gas drive, reservoir compaction and waterdrive. The gravity of the oil varies between 8° and 22° API for heavy and extra heavy oil production, and is in the 22–43° API range for minor quantities of medium and light oil (Bockmeulen et al., 1983).

Subsidence as a Result of Gas/Oil/Water Production

Cuat.

AGE

327

Bolivar coastal fields Lacustrine clays and silts

Recent Pleistocene Pliocene

El milagro U La puerta

Miocene

Oligocene U Eocene

M L

Lagunillas Icotea

La rosa ssion Transgre

Members B-1-X A B-5-X Members B-6-X A B-9-X Concep.

L Terciary

Cenozoic

M

Isnotu

Sup.

Members C-1-X A C-3-X

Inf.

C-4-X A

C-7-X

n Transgressio

Paleocene

Cretaceous

Mesozoic

Guasare Mito juan

Upper

Colon clay

Colon

Colon LMSTN

Middle Lower

Cogollo group

La luna Maraca Lisure Apon Transgression

Jurassic Triassic Pre-mesozoic

Igneous and metamorphic rocks

Figure 17.44 Stratigraphic section of Bolivar Coastal Fields. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 343, figure 7.30.)

Figure 17.45 A northeast-southwest crosssection through the Bolivar Coastal Fields (BCF). After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 344, figure 7.4.)

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On land, portions of the Bolivar Coastal Fields reservoirs have crude gravities in the range of 8–18° API, at moderate depths of 100–4,000 ft, net oil sand thicknesses of 50–600 ft, a high porosity of 30–40%, permeability of 1–8 D, initial oil saturation of 80%, and high in situ oil viscosity of 100–10,000 cP. Development of the land portions of the Lagunillas field started in 1926, and the first signs of subsidence were observed in this field’s land operations in 1929. Development of the onshore Tia Juana and Bachaquero fields, and the Mene Grande Oil Co. and Creole concessions on the lake started in the mid-1930s and even later, and where subsidence was also observed. However, it was only before and after World War II that considerable surface subsidence above the three Bolivar Coastal Fields reservoirs occurred, which was due to sharp increases in production. It was at that time that it became evident that the three producers: Shell (onshore), Mene Grande (narrow strip along the shore in shallow water), and Creole (on the lake, in deeper water) were developing different production policies as dictated by the different surface conditions. The areas most affected by subsidence were on land (Shell) and on the lake, close to the shoreline (Mene Grande) operations. Creole’s operations were in deeper water, less affected by subsidence where the policy was to maintain the installations (platforms, etc.) above the water level in case more serious subsidence developed in future. The properties of oil vary, from the northeast to the southwest, with the more viscous lower-API gravity oils in the onshore portion of the reservoir and the less viscous, somewhat lighter, higher API gravity oils in the deeper lake portions of the reservoirs (Finol and Sancevic; in: Chilingarian et al., 1995, p. 345). Owing to the fact that the Bolivar Coastal Fields reservoirs are at relatively moderate depths (1,000–4,000 ft), contain heavy and extra heavy crudes, and are at low pressures, the wells producing from these reservoirs require artificial lift (sucker-rod pumping equipment). At first the wells in unconsolidated sands utilized installation of slotted or wire-wrapped liners to help prevent sand entry into the wellbores; however, this technique was replaced by gravel packing with a slotted liner. This was more effective in controlling sand entry into the wellbore and decreased the number of liner failures, e.g., wells sanding up, and, consequently, reducing the number of workovers and well-repair jobs (Finol and Sancevic; in: Chilingarian et al., 1995, p. 345).

17.5.10.2 Subsidence of Facilities Prior to the start of oil operations in the Bolivar Coastal Fields in 1926, the eastern coasts of Lake Maracaibo were typical of lacustrine environments:

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flat and swampy (Lagunillas in Spanish means small lagoons or marshes) barely above lake level and composed mostly of sandy-silty soils. These swamps were separated from the lake by a comparatively narrow strip of land slightly higher than the lake water level, so that these strips were flooded during high tides, storms and strong onshore winds. The coastal plains are characterized by savannas with gentle slopes (0–8 in/km), extending from the western foothills of the Ziruma Mountain Range to the coast. The area includes the deltas of the Tamare, Pueble Viejo, Machango and Misoa rivers. Shallow gutters connecting the swamps and the lake afforded drainage of flood waters during the rainy season from the shore to the lake and, during the dry season, from the lake into the swamps (Finol and Sancevic; in: Chilingarian et al., 1995, p. 346). For a number of years oilfield operations were concentrated on the onshore coastal strip of land of the Tia Juana, Lagunillas and Bachaquero fields, so that additional small earthen dikes were built by hand labor along the shore, often using foreshore vegetation as breakwaters. During this early period, subsidence was not yet apparent, but in 1929 the Lagunillas dike was breached and the resulting flooding of the camp area drew attention to this phenomenon. For the first time, this led to the suspicion of the occurrence of ground subsidence because the foreshore became permanently submerged and the vegetation started to disappear, leaving the earthen dike exposed to wave action. Once observed, it was hoped that the subsidence phenomenon would not persist and an attempt was made to protect the earthen dike against wave erosion by use of various improvised materials to resist water-breaks, such as junk (old tank plates, corrugated iron sheets, etc.), building palisades, clay facing, grooved wooden sheet piling with pine boards, facing with gravel and bitumen, etc. All of these types of protection, obviously, failed and it was soon realized that the improvised structures had to be replaced by a more permanent structure, particularly over those parts of the shore where most of the subsidence occurred. Consequently, a concrete protection of the dike and a drainage system was built to protect the area from flooding (Finol and Sancevic, 1995, p. 346). Almost from the start of the subsidence, it also became necessary to construct inner dikes and a drainage system to dispose of the run-off by pumping it into the lake. A system of bench marks was installed in 1939 and precise levels were taken at periodic intervals to check further ground subsidence. The overall subsidence pattern for this area is shown in Figure 17.46. Figure 17.47 reflects the subsidence measured at the bench mark (BM) AB in this area. As new oil was discovered, both north and south of Lagunillas, the oil companies extended their operations and established new oilfields. Tia Juana

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BM AB

Lagunillas

Lake Maracaibo

Bachaquero

Main levelling line Isosubsidence contours Dykes 0

5

10 Km.

Figure 17.46 Main leveling network and subsidence contours. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 350, figure 7.8.)

to the north and Bachaquero to the south also had to be protected by means of the construction of polders similar to the one in Lagunillas. The Mene Grande Oil Company, exploiting their concessions in the lake on a narrow strip along the coast and the Standard Oil (Creole), with their activities in deeper lake waters, had their bases of operation on the Bolivar Coast, either in Lagunillas or in Tia Juana. Both companies also began to protect their installations from the lake waters by means of small hand-built earth dams (Finol and Sancevic, 1995, p. 347). Given the experience of the Dutch in coastal engineering and land reclamation, the VOC was asked in 1937 by Mene Grande and Standard to undertake the design and carry out the construction of properly engineered Earth dikes. Initially, these dikes were built along the coast as “simple” elevated roads behind a sheet-piled construction. The continued subsidence made it

Subsidence as a Result of Gas/Oil/Water Production

331

0

Subsidence (m)

–1 2 –3 –4 –5 –6 1920

1940

1960 Year

1980

Figure 17.47 Cumulative subsidence of bench mark (BM) AB (see Figure 3.47 for location). (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 350, figure 7.9.)

necessary to uplift and widen the dikes continually. With time, the initial simple elevated roads became fully developed earth dams. Figure 17.48 shows the cross-section of succession of raising the dike at this location as subsidence progressed. According to Finol and Sancevic (1995), on the basis of historic subsidence predictions (Figures 3.48 and 3.49), it’s expected that the Tia Juana and Bachaquero dikes will have to be raised an additional 1.0–1.5 m, whereas the Lagunillas dike may have to be raised 4.0 m, because additional subsidence is expected, due to the exploitation of superposed reservoirs, Laguna and Lower Lagunillas (Figures 3.50 and 3.51). As construction proceeded, the coastal protection system gradually took shape and proper “polders” were produced in the Tia Juana, Lagunillas and Bachaquero/ Pueblo Viejo consisting of: (1) a coastal dike to protect the subsided area from lake water flooding; (2) inner diversion dikes to prevent run-off from the area outside moving into the subsided polder area; (3) drainage channels to convey the water to the pumping stations constructed along the coast; and (4) pumping stations to dispose of the water over the dike and into the lake (Finol and Sancevic; in: Chilingarian et al., 1995, p. 347). As shown by Finol and Sancevic (1995, p. 355), the main driving mechanism for the reservoirs is compaction. Thus, repressurizing of Venezuelan reservoirs is problematic; stopping subsidence by water injection, for example, results in lower production and recovery. This problem was faced by a small

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Cummulative subsidence 0.93 m. o.oo

1939

1960

1963

1970

2.22 m. o.oo

3.07 m. o.oo

3.16 m.

o.oo

3.49 m. o.oo

1971

1976

3.55 m.

o.oo

3.85 m.

o.oo

1977

3.91 m. o.oo

1978

3.97 m. o.oo

Figure 17.48 Progressive raising of the dike with respect to time. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 348, figure 7.5.)

Bench marks (approx. 12 Km)

Subsidence (m)

1.0 2.0 3.0 4.0 5.0

0

196

0

197

4 198 0 0 0 2

Prediction Real

2030

6.0

Figure 17.49 Subsidence history and prediction along the Bachaquero dike. (After Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 349, figure. 7.6.)

Subsidence as a Result of Gas/Oil/Water Production

333

Bench marks (approx. 17 Km) 0.50 1932

Subsidence (m)

1.00 1.50 2.00

1942

2.50

1952 1962 1972

3.00 3.50

1 1 982 1998884

4.00 4.50 5.00

Figure 17.50 Subsidence history and prediction along the Lagunillas dike. (Modified after Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p.349, figure 7.7.) 0

Subsidence (m)

–1

–2

–3

–4

–5

–6 1920

1940

1960

1980

Year

Figure 17.51 Cummulative subsidence of bench mark (BM) 215 B (see Figure 3.46 for location). (After Finol and Sancevic, 1995; in: Chilingarian et al.,1995, p. 351, figure 7.9.)

group of experts on compaction/subsidence sent to Venezuela by the DOE in 19831. Figure 17.52, presents the relative contributions of various drive mechanisms in the Bachaquero Reservoir, Venezuela, with respect to time. 1

Professor G. V. Chilingar was a member of the delegation headed by Prof. E. Donaldson.

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Land

Percent, %

10 8 Gas 6 4

Compaction

2 Water

0 1945

1950

1955

1960

1965

1970

Year 12 10

Lake

Percent, %

8 6 Gas

4 2

Compaction Water

0 1945

1950

1955

1960 Year

1965 1970 Start W.I. lake

Figure 17.52 The relative contributions of various drive mechanisms, Bachaquero Reseervoir, Venezuela. Reservoir volumes of free gas, compaction, and invaded water (percent of initial pore volume). (After Merle et al., 1975; in: Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 355, figure 7.13.)

According to Finol and Sancevic (1995), water injection must be limited to portions of reservoirs where the mobility ratios (M) of displacing and displaced fluid are not extremely adverse. On land, portions of Bolivar Coastal Fields, the high-viscosity, low-gravity crude oil recoveries are negatively affected by water injection. Even more so, injection of high-mobility gas contributes to the losses of reserves. Nunez and Esojido (1976) found that a straight-line relationship exists between the subsidence and reservoir withdrawal in strongly subsiding

Subsidence as a Result of Gas/Oil/Water Production

335

oilfields after an initial period of low subsidence when solution gas-drive predominates as the reservoir energy mechanism. One should keep in mind that the incremental subsurface volumes of produced gas, oil and water is approximately equal to the incremental surface subsidence volumes (Finol and Sancevic, 1995; in: Chilingarian et al., 1995, p. 356). The cyclic steam injection process (steam soaking and huff-and-puff) contributes to additional compaction/subsidence. Steam injection, however, was responsible for the rejuvenation of the onshore Bolivar Coastal oilfields (see Finol and Sancevic, 1995, for details).

17.5.11

Po-Veneto Plain, Italy

There are several subsiding basins overlying hydrocarbon-bearing reservoirs in the Po-Veneto Plain of Italy shown in Figure 17.53. Over the last 30 years, land subsidence has occurred due to production of fluids. The fluids consist of predominantly dissolved methane-bearing brine water. Several confined aquifers have been produced in this plain. Brighenti et al. (1995) have presented in detail the geologic history of this plain with its aquifers. They noted that the Po-Veneto Plain is a wide sedimentary basin, which has experienced intense and differential subsidence due to fluid withdrawal. In certain areas of this plain, the depth to the base of the Pliocene sediments exceeds 8,000 m and that the Pleistocene sediments at times measure 3,000 m in thickness. This Pliocene sedimentary

46°

45°

44°

5°

4°

3°

2°

1°

0°

1°

Figure 17.53 Simplified view of the Po-Veneto Plain. The triangles indicate main hydrocarbon reservoirs. After Btrighenti et al., 1995; in: Chilingarian et al., 1995.)

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subsiding basin extends beyond the confines of the current Plain and is included as a part of the Apennine area and the northern and eastern PreAlps. Considerable volumes of terrigenous sediments have been deposited in subsidence basins. There is a prevalence of sedimentation over the subsidence during most of the recent Quaternary, as a result of which the sea withdrew and continental alluvium covered the marine sediments. In some subsidence areas the thickness of the alluvium layer reaches 400–500 m. The entire Plain has a vast and complex regional hydraulic system, nourished from its sides (Alps and Apennines) by surface waters with the formation of fluvial fans. There is a deep and complex aquifer system, characterized by a hydrodynamism towards the east (Brighenti et al., 1995; in: Chilingarian et al., 1995, p. 217). The search for oil and gas has helped in defining the geology of this petroleum basin (Brighenti et al., 1995). The petroleum basin is characterized by a wide and diversified spectrum of hydrocarbon generation and migration (Mattavelli et al., 1983; Borgia and Ricchiuto, 1985; Borgia et al., 1987). The central-eastern part of the Plain is characterized by the presence of numerous biogenic gas reservoirs (which are almost always autochthonous), located particularly in the vicinity of the plicated systems (submerged Apennine area). During the Pliocene-Pleistocene there was a widespread formation of structural stratigraphic traps which allowed for gas retention in this area. The development of biogenic gas was favored by the abundant and long-lasting sedimentation. This gas, which is very light isotopically, was formed by immature sediments at a low temperature. In certain areas, e.g., Ravenna, the gas formed and accumulated in large quantities after synsedimentary tectonic activity in the presence of thick sand and clay banks. This resulted in the formation of abnormally deep biogenic gas (Brighenti et al., 1995, in: Chilingarian et al., 1995, p. 217).

17.5.11.1

Po Delta

The Po Delta (Figure 17.54) was the first major subsidence area studied closely in Italy. Subsidence, which reached its peak in the early 1950s, was caused by the withdrawal of gas-bearing waters (Borgia et al., 1982). A schematic cross-section of the Po Plain sediments is shown in Figure 17.55. This subsidence was aggravated by the overlapping effects of: (1) recent land reclamation, (2) the natural settlement of young soils, (3) the rise in the average sea level (about 1 mm/year over the past century with a sharp increase in the past 20 years), and (4) an added effect of the embankment of the drainage system, which prevented river sediments from spreading onto the surrounding area (Bondesan and Simeoni, 1983). As a result, today the middle

Subsidence as a Result of Gas/Oil/Water Production

km 0

337

10

Figure 17.54 Land subsidence in the Po Delta in the period of 1951 to 1962 expressed in cm. The grey area indicates the area in which in 1960 the withdrawal of gas-bearihg water was discontinued. (After Borgia et al., 1985a; in Chilingarian et al., 1995, p. 239, figure 5.18.) Alps

Apennines 0 2 4 6 8 km

Ravenna

PO R. Quaternary

Pliocene S

Venice

Pre-pliocene km 0

50

N

Figure 17.55 Schematic cross-section of the Po Basin. (After Brighenti et al., 1995; in Chilingarian et al., 1995, p. 239, figure 5.19.)

section of the delta as shown in Figure 3.55, appears “spoon-shaped”, with a depression of over 3 m deep in the middle. The survival of the whole basin is dependent on the effectiveness of the man-made water control works (Brighenti et al., 1995). This is especially critical at its eastern edge bordering on the sea where there has been subsidence of the order of 2 m in the last 40 years (Brighenti et al., 1995; in: Chilingarian et al., 1995, p. 238). A detailed description of the geology can be found in Brighenti et a1. (1995). Looking at the subsidence area, it is bounded to the north by the lower course of the Adige River and to the south by the northern section of the Ferrara Province. Thus, it is located in the eastern part of the Po Plain covered by fairly thick Quaternary sediments of marine and continental origin.

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In the past, there was a brisk extraction of gas-bearing waters from Quaternary reservoirs over a surface area of about 1,000 km2. Large quantities of gas dissolved in the brine were stored in these reservoirs. There is a considerable accumulation of gas-bearing waters; with an estimated several dozens of billions of cubic meters of solution gas dissolved in water. The gas-bearing interstitial brines are quite similar to sea water in their composition. They are, however, characterized by a lower salinity (5–27 g/1) and can be interpreted as residual, brackish water, sea water, or a mixture of freshwater and fossil waters (Brighenti et al., 1995; in: Chilingarian et al., 1995, p. 240). Although the existence of gas reservoirs has been known for a long time, their systematic exploitation began only in the late 1930s, at a time of great shortage of oil in Italy. In the post-war period, production gradually increased and in the late 1950s reached 300 million scum per year. Based on drilling, the gas-bearing Quaternary layers reach down to a depth of about 800 m. Five horizontal, often not well-defined layers can be distinguished between 100 and 600 m (Brighenti et al., 1995; in: Chilingarian et al., 1995, p. 240). At the height of development, about 1,700 wells were in production, drawing water primarily from strata down to a depth of 600 m. It is estimated that a total of over 3,700 wells were drilled, especially in the Rovigo Province. The average well depth, estimated at about 200 m in the first decade of exploitation activity, increased steadily as deeper aquifers were developed. Initially, water flowed spontaneously from the wells. As fluid production lowered the reservoir pressure, there was a decrease in the hydraulic head and submersible pumps and/or gas lift became necessary to produce the wells. The gas was separated from the brackish water and the water was discharged into a surface drainage system. The gas was sent to compression plants. A gas pipeline network, extending approximately over a length of 650 km and connected to the national gas pipelines, was established in this area to convey gas to gasworks in several nearby towns, including Padua and Venice. Due to its low GWR ratio (1–1.4 scum/m3), extraction of gas in the delta area involved massive brine water withdrawals, estimated at 3 billion scum. This, in turn, caused substantial subsidence of the hydraulic head, which originally almost reached the land surface. At this time, the relationship between pore-pressure change and sediment compaction was not undisputed, as large-scale subsidence was also known to occur in the Po Delta due to the production of fluids long before gas extraction was started.

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According to Brighenti et al. (1995), during 1845–1875, considerable natural subsidence was recorded, with peaks of 70–80 cm. Elevation measurements conducted between 1884–1887 and 1950 revealed average sinking rate in the middle of the delta area of about 0.5 cm/year. In the 1950s, when the land-subsidence became greater, subsidence was regarded by many as a temporary accentuation of known phenomena. However, the progressive impairment of the area (decreased embankment clearance, reverse gradients of canals, and lowering of drainage plants) turned out to be an impending threat to the local population who were hit by frequent floods. It was then decided that a number of field measurements (mainly topographic and piezometric surveys) should be made by private and public institutions (Brighenti et al., 1995). Just a few examples are sufficient to reveal the severity and the impact of subsidence. In the withdrawal areas, subsidence of the water-table surfaces down to a depth of 50 m was recorded. At this time, subsidence proceeded at a rate of up to 25–30 cm/year in the middle area of the delta (Figure 17.54) and reached a total of 2.5 m over the 1951–1962 period. The average land subsidence of the whole delta in the same period was estimated at 115 cm. Inasmuch as a considerable amount of the data suggested that gas-bearing water extraction was the main cause of the phenomenon, a committee appointed by the Italian government stopped gas production over the 25,000-acre area where subsidence was greatest (Figure 17.54, shaded area). This step, implemented in 1960, proved highly successful in showing a close relationship between subsidence and gas production. As a result, this committee decided to extend this policy over all the delta (1961) and, later, in the remaining areas, i.e., in the entire Rovigo Province in 1963 and Ferrara Province in 1965. The average subsidence rate in the delta area and the natural gas production per year are presented as a function of time in Figure 17.56. As shown, the sinking decreased rapidly once production of the gas-bearing water was discontinued. The discontinuance of the water extraction activities caused the surface of the water-table to rise rapidly. The subsidence rate decreased exponentially with time. Based on recordings at a number of bench marks (Zambon, 1967), the relationship between sinking (h, m) and time (t, yr) can be expressed by the following equation:

h hoe

kt

(17.14)

where ho = maximum sinking, and k is a dumping constant varying from 0.24 to 0.70.

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14 12

300

10 8

200

6 4

Annual production, 106 scum/year

Average sinking rate in Po delta,cm/year

16

100

2 0

1956

1957 1958 1959 Year

1960

1961

0

Figure 17.56 Average sinking rate (solid line) and annual gas production (dashed line) in the period of 1956–1961 in the Po Delta. (After Borgia et al., 1985a; in: Chilingarian et al., 1995, p. 243, figure 5.22.)

A change in elevation with respect to a surface bench mark does not allow the thickness of layers to be established, unlike well measurements using extensometers. Figure 3.57 demonstrates the length variations of a nearly 700 m deep well located close to Ca’ Vendramin (within the grey area of Figure 17.54) obtained through measurements carried out during a period of about 3.5 years, starting from May 1960, using a specially designed movable extensometer (Borgia et al., 1982). These measurements showed that ground-sinking was related to the compaction of layers up to a depth of 700 m. This was further proved by the fact that total well shortening, over the period under consideration, turned out to be very close to the subsidence values as measured through specially performed geometric leveling, deviation being less than 8%. Moreover, even the dumping constant (k = 0.39) was in agreement with the values obtained using surface measurements (see Brighenti et al., 1995, in: Chilingarian et al., 1995, p. 295). Other series of tests were carried out in three abandoned wells close to the previous one, ranging from 180 to 415 m in depth. The data obtained

Subsidence as a Result of Gas/Oil/Water Production

341

230 210

h = 242 exp[–0.39233 t]

Depth, m

190 170 150 130 110 90 70

696.050 m 50 0

0.274 0.548 0.822 1.096 1.370 1.644 1.918 2.192 2.466 2.740 3.014 3.288 3.562

Years

Figure 17.57 Depth variation of a nearly 700-m deep well located in the Po Delta, measured by means of a moveable extensometer. h = depth (m), t = time (years). (After Borgia et al., 1982; in: Chilingarian et al., 1995, p. 244, figure 5.23.)

were in agreement with that shown by specially designed leveling. This confirmed the reliability of extensometer measurements. As pointed out by Brighenti et al. (1995; in: Chilingarian et al., 1995, p. 295) the delta area displays unique hydraulic and environmental conditions, where sea, river and continental environments coexist in a delicate equilibrium. The understanding of the system was enhanced from the recordings at times of greatest stress and in the following stages during attainment of equilibrium. The ground-sinking charts of some significant benchmarks based on the most recent measurements are presented in Figure 17.58. This data confirms the gradual rebound of land, starting in the early 1960s. Figure 17.58 suggests that subsidence has not stopped, because human activities certainly did not stop when the gas extraction was discontinued. In its terminal course the river tends to become deeper, thus impairing the stability of embankments (Figure 17.59). Thus in time, may turn out to be a somewhat critical factor, as here the level of the river is greater than the surface of the land (Brighenti et al., 1995). According to Brighenti et al., (In: Chilingarian et al., 1995, p. 245) efforts have been made to find a remedy, whenever possible, for the disruptive effects in areas where ground-sinking was highest. Measures taken or about to be taken pursue a dual goal: (1) to control floods and restore the water balance, and (2) to prevent the sea from eroding

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Height above sea level, m

2.14

Contarina 4.26

1.70 1.41

Mesola 1.38 0.19 1.03 Donzella

–0.91

Pila 0.48 –0.46 Ca’ Zulian Porto Tolle –1.79

1958 ‘62

‘66

‘70 ‘74 Years

‘78 ‘82

Figure 17.58 Soil-sinking charts of some significant bench marks updated in 1978; heights are expressed in meters and refer to sea level. (Brighenti et al., 1995; in: Chilingarian et al., 1995, figure 5.25, p. 246.)

1980 1954 1967

Sea level 1954 1967 10

1980

m0

100

0m

Figure 17.59 Examples of variation in the cross-section of the Po River which occurred near Polesella, Rovigo Province, Italy, with time. (After Bondesan and Bizzari, in: Brighenti et al., 1995; in: Chilingarian et al., 1995, figure 5.26, p. 247.)

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away the land (Montori, 1983; Carbognin et al., 1984; Gambardella and Mercusa, 1984). In spite of this action, some areas nevertheless had to be abandoned. The “spoon” shape of the delta and the depressions resulting from land reclamation in the northern area of the Ferrara Province (southern part of Po Delta) require that water be drained mechanically, as extensive areas are below sea level by a few meters. Ground-sinking, therefore, impaired the performance of the drainage equipment. Damage to irrigation works and the canal system was also caused by a reduced gradient (or even reverse gradient) of canals. Hence a major part of the water supply system had to be rebuilt (Brighenti et al., 1995; in: Chilingarian et al., 1995, p. 246). River and sea embankments suffered functional damage as a result of a change in pattern and increase in stresses. They had to be repeatedly raised and strengthened in order to prevent blowouts and offset the weakening of embankment structures resulting from increased loading. Further increase in loading on sea embankments was brought about by the lowering of the sea bed, which, in turn, was due to a decrease in the transport of solids by rivers. This resulted in flooding of some beaches and made it necessary to build dams designed to recover at least part of the damaged land, but frequently with disfiguring effects on the landscape. Based on the experience with Japanese reservoirs having similar features (Marsden, 1980), a feasibility study was conducted on the possibility of maintaining pressure by the injection of de-gassed water back into the formation. One of the issues dealt with was the simulation of a pilot field using a numerical model (Borgia et al., 1985). Among other things, it appeared that the effects of exploitation could be kept within reasonable limits even in the presence of extreme and exceptionally unfavorable anisotropies. Moreover, the simulation proved to be an advantageous tool in selecting the distribution of wells and their rates (Brighenti et al., 1995; in: Chilingarian et al., 1995, p. 247). In their excellent contribution, Brighenti et al. (1995, in: Chilingarian et al., 1995, p. 246) also discussed subsidence mainly due to water withdrawal in Ravenna, Bologna, Modena, and Venice areas of Italy.

17.5.12 Subsidence Over the North Sea Ekofisk Oilfield The North Sea is located in the western portion of the Northwest European Basin. The Mid North Sea-Ringkobing-Fyb strikes east-west across the North Sea from Denmark to the United Kingdom at 55° to 56°N (Figure 17.60). It divides the North Sea area of the Northwest European Basin into two smaller subbasins: the southern North Sea and the northern North Sea basins. A

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Figure 17.60 Location map of the North Sea oilfields. (After the Petroleum Resources of the North Sea Energy Administration; in: Chilingarian et al., 1995, p. 324, figure 8.1.)

detailed discussion of the geology, production and problems of this field are presented by Zaman et al. (1995; in: Chilingarian et al., 1995, p. 373.) The northern North Sea Basin consists of several subbasins, platforms, plateaus, grabens, and embayments. Most of the major hydrocarbon accumulations are associated with the Central and Viking grabens. These grabens form part of the same Mesozoic rift system but they are different especially in the age of the producing reservoirs and type of structural traps containing hydrocarbons. Almost all of the fields currently producing oil are located in two grabens and one subbasin: (1) the Viking or East

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Shetland Basin, (2) Central grabens and (3) the Moray Firth (Zaman et al., 1995, in: Chilingarian et al., 1995, p. 373). The southern North Sea Basin includes a belt of natural gas fields that extend from southern England through the North Sea, the Netherlands, and northern Germany to Poland. Permian Rotliegendes Sandstone is the main reservoir in this area. It also contains natural gas accumulations in tilted fault blocks, horsts, faulted domes and anticlines (Dietzman et al., 1983). The North Sea covers several smaller sedimentary and structural basins of different geologic ages. The rocks range in age from Paleozoic to Tertiary and consist of sandstones, shales, carbonates and evaporites. The most productive of the salt-induced domes are located in the Norwegian sector of the Central Graben where the Ekofisk and other nearby fields, commonly referred to as the Ekofisk complex, produce hydrocarbons from Upper Cretaceous and Lower Paleocene chalk (Dietzman et al., 1982; also in: Chilingarian et al., 1995, p. 373). The Ekofisk field is located in the Central Graben in the southern part of the Norwegian sector of the North Sea (Sulak and Danielson, 1989). It is the largest of six fractured chalk fields operated by Phillips Petroleum Co. Norway on behalf of the Phillips Norway Group. Water depth in the area is about 235 ft (72 m). The presence of massive Danian limestone is the key to Ekofisk success. The porosity of the limestone is 30% in a relatively homogeneous and clean section. Primary matrix permeability can be lower than 1 mD in some sections. However, extensive natural fracturing is found in all Ekofisk wells which results in an average 12 mD permeability to oil, calculated from well test pressure analysis. Additional Ekofisk reservoir data is shown in Table 17.5 (Snyder, 1971). A cross-section of the sedimentary basin running north to south through the area is shown in Figure 17.61. Salt domes and ridges pushing up from the basin floor create anticlinal structures in the sedimentary layers. Seismic maps of the area reveal many such structures with different sizes and shapes, which have probably increased the reservoir permeability by contributing to fracturing in the massive, brittle Danian carbonates (Snyder, 1971).

17.5.12.1 Production Norway’s first significant oil production from the North Sea was obtained in 1971, whereas in the case of the U.K., it was 1975. Most of the oil accumulations found to date are located in the Moray Firth, the Viking Graben, or the Central Graben. As of January 1, 1982, there were at least 242 developed and undeveloped oilfields in the North Sea that originally

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Table 17.5 Subsidence of the Earth’s surface ( h) at the Tersk-Sunzhen petrolif— erous area using p = 8 × 10–4 MPa–1. (After Dobrynin and Serebryakov, 1989; in: Chilingar et al., 2002, table 13.2, p. 357.) Borehole no.

Interval depth, m

Interval thickness, m

Porosity, ,%

hsh, m

hss, m

Pressure drop, MPa

h, m

59

3,635 to 4,057

422

15.9

319

103

38.4

2.4

63

3,507 to 3,963

456

15.9

345

111

36.4

2.6

65

3,667 to 4,062

395

15.8

287

108

37.9

2.2

76

4,222 to 4,506

284

15.7

198

86

37.9

1.57

82

3,635 to 4,047

412

15.8

299

113

36.3

2.2

83

3,706 to 4,100

394

15.7

275

119

36.4

2.1

86

3,696 to 4,161

465

15.9

351

114

34.6

2.39

87

3,459 to 3,944

485

16.0

381

104

35.6

2.58

91

3,491 to 3,978

487

15.7

340

147

35.1

2.5

Braguny oilfield

Yastrebinoe oilfield 107

3,587 to 3,977

390

16.1

317

73

23.2

1.37

111

3,502 to 3,900

398

16.0

312

86

25.4

1.52

113

3,578 to 3,923

345

16.0

271

74

29.0

1.5

114

3,773 to 4,002

229

16.1

186

43

27.4

0.95

116

3,443 to 3,881

441

15.9

333

108

27.4

1.8

119

3,654 to 3,890

236

16.0

185

51

28.4

1.0

contained about 96 billion barrels of oil in place and had an estimated proved reserves of 19.8 billion barrels and undeveloped reserves of 5.7 billion barrels of oil remaining to be recovered. Cumulative production until then was 3.6 billion barrels, giving a total estimated ultimate oil recovery of 29.1 billion barrels and a recovery efficiency of 30.5% of the original oil-in-place (Zaman et al., 1995; in: Chilingarian et al., 1995, p. 373). Oil production from the North Sea has increased steadily since its inception in 1971 with the exception of a very minor reversal in 1973. Since then output reached a rate of 216 thousand barrels of oil per day in 1975, doubled in 1976, doubled again by 1980, and in 1981 oil production was estimated to be about 2.3 MM bopd (Dietzman et al., 1983). Production at the Ekofisk started in July 1971 and reached a peak rate of 349,000 B/D (55,500 m3/d) in 1976.

17.5.12.2 Ekofisk Field Description The Ekofisk reservoir is large and shaped like a shallow, elliptical dome about 22,000 ft (67 m) wide and 30,800 ft (9,390 m) long. The crest of

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Figure 17.61 Promising structures within the major sedimentary basin that runs north to south through the North Sea, based upon seismic data. Ekofisk production is from 700 ft of lower Tertiary limestone as illustrated in the basin cross-section on a line from Norway to England. (After Snyder, 1971; in: Chilingarian et al., 1995, p. 376, figure 8.2.)

the reservoir is approximately 9,500 ft (2,900 m) below sea level, and the pay zone is nearly 1,000 ft (300 m) thick. The reservoir initially contained undersaturated volatile oil with the properties listed in Table 17.6. The Ekofisk Formation, which is located at a depth of 9,500 ft is of Danian of the Paleocene Period, whereas the Tor Formation, which underlies Ekofisk Formation, is of the Cretaceous Period. The Tight zone, which exists between the Ekofisk and the Tor formations, forms an impermeable barrier between the two producing formations (Figure 17.62). The porosity of chalks ranges from 25% to 48% with permeabilities up to 100 mD. The overall pay thickness reaches 1000 ft and more (Boade et al., 1989). The reservoir is covered with a 9,300-ft thick overburden, mostly composed of clays and shales interbedded with silty streaks. The overburden is overpressured below about 4,500 ft. Permeability is extremely low (10 6 to 10 9 D), and there is no indication of pressure communication between the reservoir layers and overlying sediments (Sulak and Danielson, 1989.

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Table 17.6 Ekofisk reservoir data. (After Snyder, 1971; in Chilingarian et al., 1995, table 8.1, p. 375.) Total porosity, %

30

Permeability to oil, mD

12

Temperature, oF

268 3

Solution GOR, ft /bbl API gravity,

o

1707 35.6

Initial BHP, psia

4135

Bubble point pressure, psia

5560

17.5.12.3 Enhanced Oil Recovery Projects Enhanced oil recovery methods have significantly increased the oil and gas production from the seven fields. The excess gas which could not be sold was injected back resulting in high gas injection rates. Waterflooding was initiated in 1987 to cover the Tor Formation in the northern two-thirds of the field (Sylte et al., 1988; Hallenbeck et al., 1989). It was expanded in 1988 to include the southern portion of the Tor field as well as to the Lower Ekofisk. Nitrogen injection into the crest of the Upper Ekofisk was also planned to start in late 1993 (Thomas et al., 1989). Production from the Ekofisk field has increased steadily. Two-thirds of that increase is due to waterflood response. The other third is due to an effective remedial work program implemented over the past few years as well as improved communications across disciplines which has reduced the well failures (Sulak, 1991).

17.5.13

Platform Sinking

In the early 1980s, after more than a decade of production, it was noticed that the Ekofisk platforms were sinking. A boat-landing on the east side of the Ekofisk complex was more or less under water, whereas it had previously been visible in the 1970s. The same was true for a landing on the horizontal bracing on the jacket below the 2/4-C platform. Initially no one gave any attention to check if the platforms really were sinking. In fact, many natural conditions can contribute to the variation of sea level. Late in the fall of 1984, however, the matter was given serious attention. It started with sounding measurements on the bridges to check clearance margins for anchor-handling boats. The results were compared with the relevant data from 1974. Photographs taken in the early and mid-1970s were also

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Porosity (%) 10 20 30 40 Layer 1 Layer 2 Layer 3 Layer 4 Layer 5 Layer 6

Ekofisk formation reservoir (Danian reservoir)

Layer 7 Layer 8 Layer 9

Tight zone

Layer 10 Tor formation reservoir (Cretaceous reservoir)

Figure 17.62 Representative porosity log from an Ekofisk well. (After Boade et al., 1989; in: Chilingarian et al., 1995, p. 378, figure 8.3.)

compared with recent ones (Wiborg and Jewhurst, 1986; Kvendseth, 1988). In November 1984, through measurements from fixed platform references to Kogan sea level, it was finally concluded that the platforms indeed were sinking. This was predicted much earlier by Professor George V. Chilingar given the very high compressibility of chalk. By 1984, the seafloor in the Norwegian Sea was discovered to have subsided by more than 10 ft as a result of production-induced reservoir compaction (Sulak, 1991). The effective stress on the rock (the difference between the overburden load on the rock and the pore pressure within the rock) increases as additional hydrocarbons and water are withdrawn and reservoir pressure declines. Certain rocks, under such conditions, exhibit a sudden increase in compressibility. This sudden increase in compressibility, coupled with a large irreversible deformation, is called pore collapse (Smits et al., 1988). Several investigators have observed this phenomenon in the laboratory also (e.g., Blanton, 1981; Newman, 1983). The compaction resulting from

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the pore collapse in the reservoir rocks is transmitted through the overburden causing the seafloor to subside according to Zaman et al. (1995, in: Chilingarian et al., 1995, p. 380). Pore collapse is believed to be the main cause of reservoir compaction and the seafloor subsidence in the Ekofisk Field. The Phillips Group had discussed the subsidence of the seafloor as a possibility in their application for test production in 1970. But it could not be noticed easily in situ because the subsidence occurred millimeter by millimeter over the years and the people accustomed to sights on an everyday basis could not notice it. Another point is that the measurements taken between the structures in the Ekofisk complex showed no change in elevation from one structure to another, because all structures in the area were moving down as a unit, at approximately the same rate. Also, the Phillips engineers noted that the Ekofisk reservoir is more than 10,000 ft deep, and subsidence was never reported over a 10,000 ft deep reservoir (Kvendseth, 1988). They described methods of measurement of the reservoir compaction and the resulting surface subsidence. Both temporary and permanent solutions to overcome the problem were discussed. A brief description of the factors that affect the subsidence of the ground was provided. This was followed by a discussion of various approaches adopted by research workers to investigate the characteristics and mechanics of reservoir rocks, and to model the observed behavior. Two-dimensional and three-dimensional numerical simulations of the compacting field were undertaken by different investigators. According to Zaman et al. (1995), as a result of compaction and consequent subsidence, it was necessary to raise the Ekofisk complex, at a cost of about $1 billion. It should be kept in mind that compaction drive made a significant contribution to the recovery of hydrocarbons. Sulak et al. (1989) used a three-dimensional reservoir simulator and a three-dimensional (3D) finite element (FE) model to relate rock compressibility to porosity, rock type, reservoir pressure, and areal and vertical location. Boade et al. (1988) simulated compaction/subsidence using FE geomechanics model DYNFLOW.

17.6 Concluding Remarks Bending of rock formations, due to subsidence, results in compression, extension, and shear, which lead to fracturing of rocks. Fractures tend to occur at the periphery of a subsiding basin. Fracturing of rocks damages wellbores and sometimes induces technological earthquakes. These

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fractures may form avenues for the migration of natural gas from the oilfields to the surface. The fact that fluid withdrawal for hydrocarbons is generally from point sources (not evenly distributed over the areal extent of the produced formation) and that the formations above the hydrocarbon reservoir are not composed of homogenous sediments (or in even layers) subsidence tends to be differential. Damage to subsurface pipelines, foundations of buildings, structures, sidewalks, streets and paved areas can often be minimized by recognition of the problem and use of repressuring the reservoir by waterflooding. This type of corrective measure, utilizing water to replace the produced fluids can have beneficial results. This measure helps to maintain the structural integrity of the surface facilities, prevent aquifer invasion by surrounding fluid of greater pressure, e.g., sea water, and help support the pore structure of the formation itself. All economic future development should consider all aspects of production and consequent subsidence because subsidence occurs in most oilfields.

References and Bibliography Allen, D. R. and Chilingarian, G. V., 1995. Mechanics of sand compaction. In: G. V. Chilingarian and K. H. Wolf (Eds.), Compaction of Coarse-Grained Sediments, 1, Elsevier, Amsterdam, pp. 423–477. Allen, D. R. and Mayuga, M. N., 1969. The mechanics of compaction and rebound, Wilmington Oil Field, Long Beach, California, U.S.A. In: Land Subsidence. I.A.S.H.—Unesco, Publ. no.89 AIHS, 2:410–423. Allen, D. R., 1968. Physical changes in reservoir properties caused by subsidence and repressuring operations. J. Pet. Technol., 2:23–29. Allen, D. R., Chilingar, G. V., Mayuga, M. N. and Sawabini, C. T., 1971. Studio e previsione della subsidenza. Enciclopedia della Scienza e della Tecnica. Arnoldo Mondadori Editore, pp.281–292. Applin, P. and Applin, E. R., 1965. Comanche Series and associated rocks in subsurface in central and south Florida, U.S. Geol. Sur., Prof. Pap. 447:84 pp. Armstrong, F. C. and Oriel, S. S., 1965. Tectonic development of Idaho-Wyoming thrust belt. Bull. Am. Assoc. Pet. Geol., 49:1847–1866. Baars, D. L., 1966. Pre-Pennsylvanian paleotectonics - key to basin evolution and petroleum occurrences in Paradox Basin, Utah and Colorado. Bull. Am. Assoc. Pet. Geol., 50:2082–2111. Bara, J. P., 1960. Laboratory studies in loessial foundations and embankment samples - Sherman Dam- Farewell Unit, Nebraska. U.S. Bur. Reclam., Earth Lab., Denver, Colo., Rep., EM-572, 17 pp. Barbat, W. F., 1958. The Los Angeles Basin area, California; in: L. G. Weeks (Editor), Habitat of oil. Bull. Am. Assoc. Pet. Geol., Tulsa, OK, pp 62–77.

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Borgia, G. C., Elmi, C., and Ricchiotu, T., 1987. Correlation by genetic properties of the shallow gas seepage. Proc. XIII-th Int. Meeting Organic Chemistry, Venice, Italy. Borregales, C. and Salazar, A.,1987. The Future for In-Situ Recovery;, Treatment, Trqnsportation of Heavy Oil in Venezuela. Topic 17 on Recovery of Extra Heavy Oils, Natural Bitumens and Shale Oils, 12th World Petroleum Congress, Houston, TX. Bradley, J., 1975. Abnormal formation pressure. Bull. Am. Asoc. Pet. Geol., 59:957–973. Brighenti, G, Borgia, G. C. and Mesini, E., 1995. Subsidence studies in Italy, pp. 215–276. In: G. V. Chilingarian, E. C. Donaldson and T. F. Yen, 1995, Subsidence Due to Fluid Withdrawal, Elsevier Science, 498 pp. Brill Jr., K. G., 1952. Stratigraphy of the Permo-Pennsylvanian zeugogeosyncline of Colorado and northern New Mexico. Bull. Geol. Soc. Am., 63:809–880. Brown Jr., R. D. and Hanna, W. F., 1971. Aeromagnetic evidence and geologic structure, Northern Olympic Peninsula and Strait of Juan de Fuca, Washington. Bull. Am. Assoc. Pet. Geol., 55:1939–1953. Bucher, W. H., 1933. The Deformation of the Earth’s Crust. Princeton University Press, Princeton, N.J., 518 pp. Bullard, E., Everett, J. E. and Smith, A. G., 1965. The fit of the continents around the Atlantic. R. Soc. Lond. Philos. Trans., Ser. A, 258:41–51. Carbognin, L., Gatto, P. and Marabini, M., 1984. Correlation between shoreline variations and subsidence in the Po River Delta, Italy. Proc. 3rd Int. Symp. Land Subsidence, Venice, IAHS Publ., 151:309–320. Chamberlain, C. K, 1971. Bathymetry and paleoecology of Ouachita geosyncline of southeastern Oklahoma as determined from trace fossils. Bull. Am. Assoc. Pet. Geol., 55:34–50. Chase, C. G. and others, 1970. History of sea-floor spreading west of Baja California. Bull. Geol. Soc. Am., 81:491–498. Chilingar, G. V. and Endres, B., 2004. Environmental hazards posed by the Los Angeles Basin urban oilfields: an historical perspective of lessons learned. Environmental Geology, 47:302–317. Chilingar, G. V., Khilyuk, L. F., and Katz, S. A., 1996. Pronounced changes of upward natural gas migration as precursors of major seismic events. J. Petrol. Sci. and Engr., 14:133–136. Chilingar, G. V., Mannon, R. W. and Rieke III, H. H., 1972. Oil and Gas Production From Carbonate Rocks, Am. Elsevier, New York, NY, 408 pp. Chilingarian, G. V. and Wolf, K. H., 1975. Compaction of Coarse--Grained Sediments, 1. Developments in Sedimentology, 18A. Elsevier, Amsterdam, 552 pp. Chilingarian, G. V., Donaldson, E. C., and Yen, T. F., 1995. Subsidence Due to Fluid Withdrawal. Dev. Petrol. Sci. 41, Elsevier, Amsterdam, 498 pp. Chipping, D. H., 1972. Early Tertiary paleogeography of central California. Bull. Am. Assoc. Pet. Geol., 56:480–493.

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Christiansen, F. W., 1952. Structure and stratigraphy of the Canyon Range, central Utah. Bull. Geol. Soc. Am., 63:717–740. Clark, L. M. (Editor), 1954. Western Canada Sedimentary Basin. Am. Assoc. Pet. Geol., Tulsa, Okla., 521 pp. Cline, L. M., 1970. Sedimentary features of Late Paleozoic flysch, Ouachita Mountains, Oklahoma. Geol. Assoc. Can., Spec. Pap., 7:85–101. Colazas, X. C. and Strehle, R. W., 1995. Subsidence in the Wilmington Oilfield, Long Beach, CA, U.S.A.; in: G.V. Chilingarian, E. C. Donaldson and T. F. Yen, Subsidence Due to Fluid Withdrawal, Elsevier Science, Amsterdam, 498pp. Colle, J., Cooke Jr., W. F., Denham, R. L., Ferguson, H. C., McGuirt, J. H., Reedy Jr., F. and Weaver, P., 1952. Volume of Mesozoic and Cenozoic sediments in Western Gulf Coastal Plain of United States. Bull. Geol. Soc. Am., 63:1193–1200. Coney, P. J., 1970. The geotectonic cycle and the new global tectonics. Bull. Geol. Soc. Am., 81:739–748. Contaldo, G. J. and Mueller, J. E., 1991. Earth fissures and land subsidence of the Mimbres Basin, Southwestern New Mexico, U.S.A. In: A. I. Johnson (Ed.), Land Subsidence. IAHS Publ., 200: 301–310. Cramer, H. R., 1971. Permian rocks from Sublett Range, southern Idaho. Bull. Am. Assoc. Pet. Geol., 55:1787–1801. Crittenden Jr., M. D., 1963a. New data on the isostatic deformation of Lake Bonneville. U.S. Geol. Surv., Prof. Pap., 454-E, 31 pp. Crittenden Jr., M. D., 1963b. Effective viscosity of the Earth derived from isostatic loading of Pleistocene Lake Bonneville. J. Geophys. Res., 68:5517–5530. Crittenden Jr., M. D., Schaeffer, F. E., Trimble, D. E. and Woodward, L. A., 1971. Nomenclature and correlation of some Upper Precambrian and Basal Cambrian sequences in western Utah and southeastern Idaho. Bull. Geol. Soc. Am., 82:581–602. Crosby, G. W., 1968. Vertical movements and isostasy in western Wyoming overthrust belt. Bull. Am. Assoc. Pet. Geol., 52:2000–2015. Currie, J.B., 1967. Evolution of stress in rocks of a sedimentary basin. Rock Mechanics in Oilfield Geology. Drilling and Production. Proc. World Petrol. Congr., Mexico City, Mexico. Elsevier, Amsterdam, pp. 1–51. Dallmus, K. F., 1958. Mechanics of basin evolution and its relation to the habitat of oil in the basin. In: L G. Weeks (Editor), Habitat of Oil, Am. Assoc. Pet. Geol., Tulsa, OK, pp. 883–931. Dana, J. D., 1873. On some results of the Earth’s contraction from cooling. Am. J. Sci., 3rd Ser., 5:430; 6:717. Dewey, J. F., 1969. Evolution of the Appalachian-Caledonian orogen. Nature, 22:124–129. Dietz, R. S. and Holden, J. C., 1966. Miogeosynclines in space and time. J. Geol., 74:566–583. Dietz, R. S., 1972. Geosynclines, mountains, and continent-building. In: J. T. Wilson (Ed.), Continents Adrift, Sci. Am., pp. 124–132.

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Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

18 Effect of Emission of CO2 and CH4 into the Atmosphere *Originally published in Environmental Aspects of Oil and Gas Production, by John O. Robertson and George V. Chilingar, copyright 2018, Scrivener Publishing

18.1 Introduction A major environmental concern is the production and burning of hydrocarbons and the releasing of carbon to the atmosphere. It is thought by some, without scientific evidence, that humans are putting carbon (in the form of carbon dioxide, CO2, or methane, CH4) into the atmosphere and that this anthropogenic carbon is responsible for global warming. Syante Arrhenius, a Swedish scientist, was the first to claim that fossil fuel combustion may eventually result in enhanced global warming (Maslin, 2004; in: Enzler, 2015). He proposed that there was a relationship between atmospheric carbon dioxide concentrations in the atmosphere and global temperature. Since then, the concept has been taken as obvious by many without “verification” (Budyko, 1997; Global warming, 1993; Greenhouse effect, 1989). The arguments for, against, and why global warming occurs have grown within the scientific community since his proposal. In examining the relationship between temperature and carbon content in the atmosphere it is critical that we examine not just the recent history, but also

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the Earth’s historical geologic data. The Earth’s climatic changes, as demonstrated in the Antarctic ice, for the last 800,000 years, have been cyclic periods of cooling and warming. A theory of global warming states that heating of the atmosphere occurs as a direct result of additional carbon dioxide (CO2) and methane (CH4) that is added to the Earth’s atmosphere produced by man’s activities (anthropogenic). As a result, the petroleum industry has often been “singled out for blame” for the release of carbon (methane and carbon dioxide) into the atmosphere as it produces and handles hydrocarbons. There are some who believe that today’s increase in atmospheric carbon dioxide, can be entirely attributed to human activities related to release of CO2 or CH4 to the atmosphere. A survey of several thousand scientists conducted by the University of Illinois found that 82% believe that human activity in generating CO2 has been a significant factor in changing mean global temperatures. Climatologists who are active in research showed the strongest consensus on this cause of global warming, with 97% agreeing human activity plays a primary role. Those familiar with hydrocarbons and climate, e.g., petroleum geologists and engineers along with meteorologists were among the biggest doubters, with only 47% to 64%, respectively, accepting the concept of human involvement as a primary cause of global warming. Delingpole (2015) reported that Steven Goddard, 2015, has shown evidence that NASA and NOAA have adjusted the raw temperature values to indicate global warming. He also pointed out that Hansen in a 1989 report observed that over the previous 50 years (which was also a period of significant increase in the production of greenhouse gases) there had been little temperature change. In fact, this period appears to be one of global cooling throughout much of the United States. However, Greenberg (2015) reported that the members of the U.S. Senate voted 98-1 that climate change is real and not a hoax. Today, with more information available, more scientists are beginning to openly disagree with prior concepts that the CO2 released by humans is the cause for increased global temperature (Chilingar et al., 2009 and Chilingar et al., 2014). In fact, as demonstrated in this chapter, CO2 cannot be the driving force to higher global temperatures as shown by both the historic geologic and adiabatic data. These authors note that the scientific community, throughout the world, is today currently divided on the issue of whether man’s activities are truly responsible for global warming or if global warming is a natural process, e.g., the positional interrelationship between the sun and Earth, volcanic activity and other factors related to natural causes. The authors present arguments brought forward

Effect of Emission of CO2 and CH4 into the Atmosphere 363 by scientists such as Sorokhtin et al. (2003, 2004 and 2006), Chilingar and Khilyuk (2007), Chilingar et al. (2009), Chilingar et al. (2014) and many others examining the various “carbon cycles” of Earth and their relationship to global temperature. This chapter is divided into three sections: (1) historic geological evidence showing a historic cycling of temperature long before human existence, (2) adiabatic theory and (3) effect of methane gas in the atmosphere. The historic portion has several subsections: (a) geologic evidence that the Earth’s global temperature has historically been cyclic for the past 800,000 years, and (b) that the geologic temperature vs. CO2 data, indicate that the increase in CO2 did not raise global temperature as the increase in CO2 concentration in the atmosphere occurred after an increase in global temperature (by about 800 to 1,000 years). The adiabatic analysis shown at the end of this chapter is consistent with the presented historic data, demonstrating that temperature fluctuation affects the percentage of carbon content in the atmosphere and not the other way around.

18.2 Historic Geologic Evidence 18.2.1

Historic Record of Earth’s Global Temperature

The historic geologic record of temperature (and carbon dioxide) is presented in Figure  18.1. This figure shows that Earth’s global temperature and % carbon in the atmosphere have varied greatly over geologic time without a distinctive relationship. This geologic record also shows that the Earth has often been much hotter and more humid than it is today. Heib (2009) has noted that the only period of the Earth’s history that appears to have similar values of global temperature and atmospheric carbon content is 300 million years ago during the late Carboniferous Period. Temperature and % carbon in atmosphere data for the Earth’s lower atmosphere has been obtained from several studies of gas bubbles that were trapped in the ice overlying Antarctica. The data from studies of Antarctic ice cores yield a 400,000-year to 800,000-year record of global temperature with a deviation of about 10 °C. Dillon plotted the deviation of temperature relative to the 2000 A.D. temperature for the past 400,000  years (Figure 18.2). This figure indicates a historic temperature cycle ( 100,000 years) of cooling and warming of the Earth’s lower atmospheric global temperature. The Earth’s global temperature cycle of warming and cooling occurred long before human activities.

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Figure 18.1 Schematic showing the relationship between average global temperature (solid line) and atmospheric carbon dioxide (dashed line) over geologic time. The late Carboniferous to Early Permian Period (315 mya to 270 mya) is the only time in the last 600-million years when both the atmospheric carbon dioxide content and temperatures were as low as they are today. (Modified after Hieb, M, 2009, in: Climate and the Carboniferous Period, http//www.geocraft.com/MVFossils/Carboniferous_climate.html., data for temperature obtained from Scotes and CO2 after Berner, 2001.)

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Figure 18.2 Deviation of Earth’s lower atmospheric temperature from 2000 A.D. for the last 400,000 years. (Modified after Dillon, 2015. Data for temperature sources: Satellite stratosphere data (2000–1979); Southern hemisphere ground temp. data (1979–1871); Vostok ice core data (1871–422 k B.P.).)

Today, some investigators suggest that Earth’s global temperature is currently warming; however, Monctkon (2015) in a review of Earth’s lower atmosphere, obtained by satellite, has noted little evidence of either warming or cooling for the past 17 years. Bastasch (2015) in a similar study using data taken by satellite found no evidence of global warming over the past

Effect of Emission of CO2 and CH4 into the Atmosphere 365 22 years (Figure 18.3). A review of temperature deviation data over the past 2,000 years reveals that temperature has been mildly cyclic over this period and that we are currently in a “modern warmer period” cycle that may not have reached its peak global temperature (Figure 18.4). An examination of Figure 18.4 indicates an overall gentle cooling period from 1000 to 1700 AD and that the current warming period is not exceptional. Hiebe (2009) has suggested that we are currently in an ice age climate period. However, “for the last 10,000 years we have enjoyed a warm but

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Figure 18.3 Running centered 13-month average of UAH satellite-based temperature of the global lower atmosphere (version 6.0) from 1979 to June 2015. (Modified after Bastasch, 2015.)

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Figure 18.4 A reconstruction of temperature deviation, to the 1961–1900 mean for the Earth’s northern hemisphere during the last two millennia. This shows that the current warm period is not exceptional. (Modified after Geografiska Annaler, 2010.)

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temporary interglacial vacation.” This is reflected in geological records, e.g., (1) ocean sediments and ice cores from permanent glaciers that have formed in the last 750,000 years and (2) interglacial periods that occur at 100,000-year intervals (see Figure 18.2). Hiebe (2009) also suggested that these cycles have been occurring for the past 2–4 million years although the Earth’s temperature appears to have been cooling for the past 30 million years. In conclusion, the Earth’s global temperature has been cycling about every 100,000  years about 10  °C due to natural causes and not as a result of human influence, e.g., sun-Earth relationship and volcanic activity, for a minimum of the last 800,000 years.

18.2.2 Effect of Atmospheric Carbon Content on Global Temperature

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Figure 18.1 illustrates that there appears to be little relationship between global temperature and the percentage carbon content in the atmosphere during much of the Earth’s geologic history. Global temperature appears to be independent from % carbon in the atmosphere. Archer (2010) found a relationship between % CO2 content in the atmosphere and volcanic activity throughout geologic history (see Figure 18.5).

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Figure 18.5 Schematic showing relationship between the CO2 content in the atmosphere (dashed line) and the volcanic activity on Earth (solid line). (Modified after Archer, 2010.)

Effect of Emission of CO2 and CH4 into the Atmosphere 367 A record of the past 800,000 years is preserved, in gas bubbles, in the ice cover of the Antarctic, which is a source of historic data of global temperature and % carbon in the atmosphere. Several important studies have been made: 1. Fischer et al. (1999) studied air trapped in bubbles in Antarctic ice cores, around the last three glacial periods. This study of air trapped in the bubbles within the ice revealed a record of temperature and the carbon content in the atmosphere for the past 400,000 years. These high-resolution records from the Antarctic ice cores show that carbon dioxide concentrations increased by 80 to 100 parts per million by volume 400 to 600 years after the warming of the last three deglaciations. The carbon content of the atmosphere increased after the temperature had increased (Figure  18.6). Despite strongly decreasing temperatures, the high carbon dioxide concentrations in the atmosphere can be sustained for many years during glaciations before it is absorbed back into the carbon cycle. 2. Monnin et al. (2001), who studied ice cores from the Dome Concordia, Antarctica, found that CO2 concentrations in the atmosphere increased after the global temperature increased after a period of 1000 years. His findings are consistent with the earlier work of Fisher et al. (1999). 3. Caillon et al. (2003) investigated the Vostok ice cores, and also found that the atmospheric CO2 content increased after (800 200-years) after the temperature had increased. All these investigators independently had a similar conclusion that temperature increases preceded an increase in the CO2 content of the atmosphere. Therefore, the evidence is that increases in global temperature results in increasing the carbon content in the atmosphere and that there is no evidence that the change of carbon content in the atmosphere changes global temperature. Evans (2010) summarized his findings on the relationship between atmospheric carbon dioxide content and global temperature. He noted that if the atmospheric carbon dioxide content increased after global temperature increases, then there is no justification for claiming that increased carbon dioxide content in the atmosphere can increase the global temperature. Examining only the supposed human-generated carbon emissions and global temperature one can note that there is a significant lag between the human

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0

Figure 18.6 800,000-year record of atmospheric CO2 content and a reconstruction of temperature from Antarctic ice cores. Temperature values in solid line and percent CO2 in atmosphere in dashed line. (Modified after Shakun, 2012.)

emissions of carbon content to the atmosphere and the temperature increase (Figure 18.7). This also assumes that the increase in temperature is due to the increased CO2 emissions and no other factors, e.g., sun/Earth relationship and volcanism. Giving further support to the position that CO2 emissions are not a factor, Evans (2010) noted that the global warming trend was initiated prior to 1700; however, the additional emissions by humans were negligible from 1850 to 1940, showing that there is no possibility that humans initiated global warming. Evans (2010), looking at this data, questioned that there has been any significant global warming since 1998. Inasmuch as a quarter of all human emissions have occurred in the past 12 years, why have we not seen more global warming? Jones (2009) stated that perhaps human emissions of CO2 have merely aggravated the current global warming trend. He also pointed out that 85% of all human emissions have occurred after 1945. The post-World War II industrialization greatly accelerated human emissions (see Figure 18.7). Bastasch (2015) has reviewed satellite temperature data during a 22-year period (1979–2015) of increased human emissions (see Figure 18.7) and found little or no global warming even though the CO2 emissions significantly increased during this period (Figure 18.3). Hieb (2009) noted that the global temperature and atmospheric concentrations of carbon dioxide (CO2) in the Early Carboniferous Period, were approximately 1500 ppm (parts per million), but by the Middle

Effect of Emission of CO2 and CH4 into the Atmosphere 369 0.8

10,000

8,000 0.4 0.2

6,000

0.0 4,000

–0.2 –0.4

2,000

Human CO2 emissions, mt-carbon/year

Global air temperature deviation, C

0.6

–0.6 Human emissions of CO2 –0.8 0

500

1000

1500

0 2000

Years, (prior to today)

Figure 18.7 Schematic showing relationship between global air temperature vs. human CO2 emissions from 16 AD to 2010. (Evans, 2010, states that these emission figures are not perfect because they omit some minor causes, e.g., deforestation; however, these are relatively minor). Evans also noted that the temperatures from 1850 to 1980 are suspect because they come from land-thermometers. (Modified after Evans. 2010.)

Carboniferous they had declined to about 350 ppm -- comparable to the average CO2 concentrations today. Figure 18.7 does not support a direct relationship between human-generated carbon in the atmosphere and global temperature. Figure 18.7 does show, however, that an increase in global temperature could have affected the carbon content in the atmosphere. Earth’s atmosphere today contains about 380 ppm CO2 (0.038%) as compared to a higher concentration in former geologic times. The CO2 content of our present atmosphere (like the Late Carboniferous atmosphere) is low. Hieb (2009) noted that in the last 600 million years of Earth’s history only the Carboniferous Period and our present age (Quaternary Period) have witnessed CO2 levels lower than 400 ppm. He also noted that historically the concentration of CO2 in the atmosphere has been much higher, e.g., during the Jurassic Period (200 mya), average CO2 concentrations were about 1800 ppm or about 4.7 times higher than today. The highest concentrations of CO2 during all of the Paleozoic Era

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occurred during the early history of Earth (Cambrian Period) when it was, nearly 7000 ppm -- about 18 times higher than today. Possibly, the CO2 content of the atmosphere of Pre-Cambrian time explains extensive formation of dolomites (Chilingar, 1956) and scarcity of fossils due to high Mg/Ca ratio of sea water. The Carboniferous Period and the Ordovician Period were the only geologic periods during the Paleozoic Era when global temperatures were as low as they are today (Hieb, 2009). The Late Ordovician Period was also an Ice Age, whereas, at the same time, CO2 concentrations then were nearly 12  times higher than today, 4400 ppm. According to the greenhouse theory, Earth should have been exceedingly hot. Instead, global temperatures appear to be no warmer than they are today. Again, the carbon dioxide content in the atmosphere appears to have had little effect on global temperature. Clearly, other factors besides atmospheric carbon dioxide content (e.g., temperature of the oceans and volcanism) influence Earth temperatures and global warming/cooling.

18.2.3

Sources of CO2

To answer the question of where the source of CO2 is coming from, one must look at the Earth’s carbon cycle and in particular where carbon is stored on the Earth (Figure 18.8). There are several different forms of carbon that one needs to track in the Global Carbon Cycle (Archer, 2010): 1. Inorganic-C in rocks, e.g., bicarbonate and carbonate. 2. Organic-C, e.g., organic plant material. 3. Carbon gases such as CO2, volcanism and solution gas in the oceans. 4. Methane gas, CH4. 5. Carbon monoxide, CO. Although there are several pathways of carbon cycling, the ocean/ atmospheric cycle is one of the largest. As the global temperature and ocean temperature increase (see Figure 18.9), a large volume of CO2 previously dissolved in the ocean water is released to the atmosphere due to the loss of solubility in warmer water. The oceans are a great storehouse of CO2, covering about 72% of the Earth’s surface. Therefore, an increase in global temperature will directly give rise to an increase in the quantity of CO2 in the atmosphere. Another source of carbon to enter the atmosphere is volcanism. The carbon cycle for outgassing from the Earth’s interior is shown in Figure 18.10. Archer (2010) has shown that over geologic history, there is a close

Effect of Emission of CO2 and CH4 into the Atmosphere 371 K e y

Process Reservoir

Atmosphere Erupting volcano

Photosynthesis Soil respiration

Diffusion Respiration

Burning

Photosynthesis Respiration

Plants

Decomposition

Ocean surface Burning fossil fuels

Food web

Phytoplankton

Soil organic carbon Food web Weathering & erosion

Sinking Coal, oil, gas

Shellfish & corals

Sedimentary rocks

Rock cycle

Deep ocean currents Deep ocean sediments

Credits

Weight in water, g/100 mL

Figure 18.8 Pathways of carbon in the carbon cycle showing storage areas of carbon, e.g., ocean, atmosphere, vegetation, and rock. The ocean is one of the largest storage areas of carbon (After Earth Labs, http://serc.carleton.edu/eslabs/carbon/index.html).

0.3 0.2 0.1 0.05 0 0

10

20

30

40

50

60

Temperature, C

Figure 18.9 Relationship between the temperature and the solubility of CO2 in water. (Data obtained from Wallace, 2009.)

relationship between the atmospheric CO2 content and volcanic activity (Figure 18.5) exists. During higher periods of volcanic activity, CO2 concentration in the atmosphere is higher; therefore, increased CO2 concentration in the atmosphere can also be related to volcanic activity. Figure 18.11 shows the volcanic activity from 1850 to 2010.

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Photosynthesis

CaCO3 burial

Oceanic lithosphere CO2 Mantle

ep

Organic carbon burial Outgassing

Weathering

oce an tre nch

Ca++ HCO3–

Respiration

De

Mi do c rid ean ge

372

Outgassing

Continental lithosphere

Sub duc tio CO2 n Metamorphism zo ne

The carbon cycle

Figure 18.10 Sources of Carbon looking at the rock cycle showing outgassing from the Earth’s interior at Midocean ridges, hotspot volcanoes and subductiuon-related volcanic (breakdown of carbonates, etc. volcanism. (After http//www.columbia.edu/v”d1/carbon.htm).

70

60

Number of eruptions

50

40

30

20

10

1850 1860 1870 1880 1890 1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 Year

Figure 18.11 Global volcanism over time by decade from 1850 to 2010. There has been a general increase in volcanism over the past 100 years. (Modified after http:// informacaoincorrecta.blogspot.com/2011/08/porque-nibiru-nao-existe.html)

Effect of Emission of CO2 and CH4 into the Atmosphere 373 In summary, the increase of CO2 in today’s atmosphere is likely due to: (1) The release of dissolved CO2 from the ocean water occurring as a result of the increase in ocean temperature due to the sun’s irradiation. (2) The exponential increase in volcanic activity from 1950 through 2010. (3)  Human activities. Currently, the increase in the CO2 content in the atmosphere has often been attributed to only human activity.

18.3 Adiabatic Theory 18.3.1 Modeling the Planet Earth The adiabatic theory of the greenhouse effect shows that the temperature distribution in a planet’s troposphere (including the Earth’s troposphere) at pressures >0.2 atm (2.0265 101 kPa) under the greenhouse effect theory can be determined using the following equation:

T

1 4

S(1 A)

b 2

4 2

2

2 1 cos

p po

(18.1)

2

where: S (=1.367 × 106 erg/cm2 s) is the solar constant (flow of the solar energy reaching the Earth); (=5.67 × 10–5 erg/cm2 s °C4) is the Stefan-Boltzmann constant; A is the planet’s reflectivity (albedo) (for the Earth, A  0.3); b is cp ( 1) a scaling factor; is the adiabatic exponent; and , where cv cp and cv, are the specific heats of gas at constant pressure and constant volume, respectively; is the precession angle of the revolving planet (for the present-day Earth, = 23.44°). At  = 23.44°. the denominator in Eq. 18.1 is equal to 3.502 rather that 4.0 in the classic format at = 0. According to current measurements, average near-surface Earth temperature at p = po = 1 atm (1.01324 102 kPa) is approximately equal to 288 K or +15 °C (Bachinsky et al., 1951). Factor b can be determined under the condition that the present-day average Earth’s surface temperature is equal to 288 K at = 0.1905. In such a case, b = 1.597, and for the nitrogenoxygen atmosphere composition, b = 1.093. For a different composition of troposphere, the factor b remains the same, but the ba value changes depending on the adiabatic exponent (Sorokhtin 2006).

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If the specific heat at a constant pressure (cp) is expressed in cal/g °C, and the universal gas constant R = 1.987 cal/mol °C, the relationship between the adiabatic exponent and the composition and humidity of troposphere can be presented by the following equation:

R C w Cr )

(c p cp

[ pN2 c p (N2 ) po2 c p (O2 ) pco 2 c p (CO2 ) pAr cp (Ar)] p

(18.2)

(18.3)

where R = 1.987 cal/mol °C is the gas constant; is the molar weight of atmo28.9E); pN2 0.7551; pCO2 0.00046 spheric mixture (for the Earth, and pAr = 0.0128 atm are the partial pressures of the corresponding gases (Voitkevich et al., 1990); p 1 atm is the total atmospheric pressure at sea level; cp(N2) = 0.248, cp(O2) = 0.218 cal/g °C; cp(CO2) = 0.197 cal/g °C; cp(Ar) = 0.124 cal/g °C are specific heats of nitrogen, oxygen, carbon dioxide and argon at constant pressure (Naumov et al., 1971); Cp and Cr are the correction factors with the dimension of specific heat (taking into account the total heating effect of the water vapor condensation process Cw in a humid atmosphere and the absorption of heat from the Earth and sun Cr by greenhouse gases). From Eq. 18.2;

(Cw

Cr )

R

cp

(18.4)

At = 23.44° and A 0.3, the best fit of the theoretical temperature distribution (Eq.  18.1) within the Earth’s troposphere to the averaged empiric data occurs at = 0.1905 and b = 1.093. For a dry air mixture of the Earth’s atmosphere, cp = 0.2394 cal/g °C. Thus, using Eq. 18.4 for the absorbing-infrared-radiation humid air of the troposphere with the temperature gradient of 6.5 °/km, the Cr + Cw = 0.1203 cal/g °C. For planets with atmospheres of a different composition these parameters should be understood as the description of any thermophysical or chemical processes resulting in the heat release (at Cr + Cw > 0) or absorption (at Cr + Cw < 0) within the troposphere. To determine the Cr and Cw, factors, it is necessary to involve the characteristic temperatures Ts and Te of a planet (Sorokhtin 2001):

Effect of Emission of CO2 and CH4 into the Atmosphere 375

Cr Cw

R

(Ts Te ) Ts R Te Ts

cp

(18.5) (18.6)

On substituting the values of Earth’s parameters into Eqs. 4.5 and 4.6 ( = 0.1905, = 28.9, cp = 0.2394 cal/g °C, Ts = 288 K, Te = 263.5 K and R = 1.987 cal/mol °C), one obtains Cr = 0.0306 cal/g oC; Cw = 0.0897 cal/g °C; and Cr + Cw = 0.1203 cal/g oC. Eq. 18.4 gives the same results. The adiabatic model (Eq. 18.1) was verified with the standard temperature distribution in the troposphere (Bachinsky et al., 1951). The results of the comparison [at y = 23.44° and po = 1 atm (1.01324 102 kPa)] are presented in Figure 18.12.

18.3.2 Modeling the Planet Venus A much more stringent check of the universality of the derived patterns is a computation of temperature distribution in the troposphere of Venus. It is performed based on the given pressure of 90.9 atm (92.1035 102 kPa), 3.18 , and solar constant, S = 2.62 106  erg/cm2, precession angle 20 Elevation above sea level, km

18 16 14 12

3

10 8 6 4

1 2

2 0 200 210 220 230 240 250 260 270 280 290 300 Temperature, K

Figure 18.12 Averaged temperature distributions in the Earth’s troposphere using Eq. 4.1: Model 1 - Earth’s troposphere with a nitrogen-oxygen atmosphere; Model 2 - Earth’s atmosphere composed totally of carbon dioxide; and Model 3 - Earth’s atmosphere composed totally of methane. All other parameters of models 2 and 3 are the same as in model 1. (After Chilingar et al., 2009, p. 1210, figure 2.)

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the molecular weight = 43.5 (Marov 1986; Venus 1989). The results are also presented in Figure 18.13. The best fit of the theoretical temperature distribution with its empirical values occurs at the adiabatic exponent = 0.1786 and b factor of 1.429 (b = 7.37). For Venus, cp = 0.2015 cal/g oC, Ts = 735.3 K and Te = 230.5 K. Then, Cr = 0.1756 cal/gm oC, Cw = 0.1213 cal/g oC and Cq= (Cr + Cw) = 0.0543 cal/g oC. The Cr parameter determines the absorption of the planet’s heat radiation by atmosphere. Its relatively elevated value is apparently due to a high atmospheric pressure and very hot troposphere. Inasmuch as Cw < 0 for Venus troposphere (especially in its lower and middle layers), endothermic reactions predominate (dissociation of some chemical compounds, for instance, dissociation of the sulfuric acid into SO3 and water). For the upper layer of the Venetian troposphere (at the elevations between 40 and 60 km) Cw > 0. Therefore, the exothermic chemical reactions (e.g., the reduction of sulfuric acid) and condensation of water vapor in the clouds prevail. As Figure 18.13 shows, theoretical temperature distribution in the Venetian troposphere, which is completely different from the one on Earth, fits quite well to the empirical data quoted in Venus (1989). The range of relative error through the elevations up to 40 km is 0.5–1.0%. Theoretical temperatures at the elevations ranging from 40 to 60 km are positioned between two series of empirical data corresponding to the measurement at the Venetian high and low latitudes. At the higher altitudes where p < 0.2 atm (Venetian tropopause), the presented theory is not valid. This 80 70

Height (km)

60

2

1

3

50 40 30

4 3 1,2

20 10 0 200

300

400 500 600 Temperature (K)

700

800

Figure 18.13 Distribution of experimentally determined temperature within the Earth’s troposphere and stratosphere (curve 4: Bachinsky et al., 1951) and within the Venetian troposphere (curves 1 and 2: Venus, 1989) as compared to the theoretical distributions (curves 4 and 3). Constructed in accordance with the adiabatic theory of the greenhouse effect. Temperatures are in Kelvin. (After Chilingar et al., 2009.)

Effect of Emission of CO2 and CH4 into the Atmosphere 377 cannot be accidental and most likely is an indication of the validity of the presented theory for the troposphere layer. The temperature distributions presented in Figure 18.13 were constructed based on the adiabatic theory of temperature distribution and are in effect the first theoretical models of the Earth’s and Venus’s tropospheric heat regime, i.e., the models for the planets with totally different atmospheric parameters. The obtained close fit of the theoretical model to experimental data is a strong testimony to the validity of the adiabatic theory of greenhouse effect. The results of comparison indicate that the average temperature distribution in a planetary troposphere is determined by the solar constant, the planet’s albedo (a measure of the reflectivity of the earth’s surface. Ice, especially with snow on top of it, has a high albedo), the mass (pressure) of atmosphere, heat-absorbing capacity of its gaseous mixture, and the planet’s precession angle. By definition, the greenhouse effect T is the difference between the planet’s surface average temperature Ts. and its effective temperature Te:

T = Ts

Te

(18.5)

Average temperature for the entire Earth’s surface is approximately 288 K or +15 °C. Its effective temperature ( = 0) is Te = 255 K or 18 °C. Thus, the present-day value of the greenhouse effect for the Earth is +33  °C. If we take into account that the present-day Earth’s precession angle is = 23.44°, then the effective temperature of Earth turns out to be Te = 263.49 K (Sorokhtin 2006). This adiabatic model allows one to estimate the effect of so-called “greenhouse gases” on the temperature regimes of the Earth’s troposphere and its greenhouse effect. For asymptotic estimates, the writers assumed that the nitrogen-oxygen Earth’s atmosphere is completely replaced by a carbon dioxide one and, then, by a methane one, with the same atmospheric pressure, ps = 1 atm (1.01324 102 KPa). The adiabatic exponents are determined from Eq. 18.2 and 18.3 at CO2 44, and cp = 0.197 cal/gm °C, CH4 16, and cp = 0.528 cal/gm °C. Thus, CO2 0.1423 and CH4 0.1915. Substituting these a values into Eq. 18.1 with the same b factor value of 1.597, one can construct the temperature distribution in the hypothetical carbon dioxide and methane atmospheres. The corresponding near-surface temperature of the hypothetical carbon dioxide atmosphere will be 281.5 K (6.4 °C) lower than that at the nitrogen-oxygen composition of the atmosphere, and for the methane atmosphere it will be 288.1 K, which is just 0.1 °C, above the usual average Earth’s temperature of 288 K. One needs to remember, however, that the carbon dioxide atmosphere is denser, whereas the methane atmosphere

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is lighter so that the same pressures in these atmospheres will be reached at different elevations than those in the nitrogen-oxygen atmosphere,

hCO2

hN2 +O2

N2 O2

(18.7)

CO2

and

hCH4

hN2

N 2 O2

(18.8)

O2 CH 4

Height above the surface of venus, km

where N2 O2 ( 28.9) is the molar weight of the nitrogen-oxygen atmosphere, and CO2 ( 44) and CH4 ( 16) are the molecular weights of carbon dioxide and methane, respectively. The constructed temperature distributions within the hypothetical totally carbon dioxide and totally methane atmospheres are shown in Figure 18.14 together with the already presented (Figure 18.13) temperature distribution in the existing nitrogenoxygen atmosphere. Thus, for the hypothetical carbon-dioxide atmosphere with the same near-surface pressure of 1 atm, the average Earth’s surface temperature declines by approximately 6.5  °C (and not increases significantly as 100 90 80 70 60

2

50 40 1

30 20 10 0 200

300

400 500 600 Temperature, K

700

800

Figure 18.14 Averaged temperature distributions in the Venetian troposphere based on Eq. 4.1: (curve 1) Venus’s carbon dioxide troposphere and (curve 2) the temperature distribution for a hypothetical model of the nitrogen-oxygen troposphere for Venus with all other conditions being equal. (After Chilingar et al., 2009, p. 1210, figure 3.)

Effect of Emission of CO2 and CH4 into the Atmosphere 379 commonly believed). Besides, due to a higher molecular weight of carbon dioxide, temperature within the entire thickness of such a troposphere is always lower than in the nitrogen-oxygen troposphere. For a hypothetical methane atmosphere, the near-surface temperature at 0.195. sea level remains almost unchanged, because N2 O2 0.1905 CH 4 At the same time, in the troposphere it is higher than that for the nitrogenoxygen atmosphere, inasmuch as CH 4 ( 16) N2 O2 ( 28.9), because the methane atmosphere is much thicker than the nitrogen-oxygen one. That is why in the mountainous areas surface temperature may significantly increase under such atmosphere. Similarly, for a hypothetical nitrogen-oxygen Venetian atmosphere at the same pressure of 90.9 atm, its surface temperature will rise from 735 to 795 K (462–522 °C; see Figure 18.14. These estimates show that saturation of the atmosphere with carbon dioxide, with all other conditions being equal, results not in an increase but in a decrease of the greenhouse effect and average temperature within the entire layer of the planet’s troposphere. This happens despite intense absorption of the heat of radiation by CO2. The physical explanation of this phenomenon is clear: molecular weight of carbon dioxide is 1.5 times higher and its heat-absorbing capacity is 1.2 times lower than those of the Earth’s air. As a result, see Eqs. 4.2 and 4.3, the adiabatic exponent for a carbon dioxide atmosphere, at the same conditions, is about 1.34 times lower than that for a nitrogen-oxygen humid air: N2 O2 0.1905. On Venus, the correction factors Cw and Cr are different from those on Earth, and a parameter is different from the carbon dioxide adiabatic exponent. Thus, a carbon dioxide atmosphere may be compared with a thin, dense blanket with a lower heatabsorbing capacity, whereas a nitrogen-oxygen atmosphere is like a downy (fluffy) blanket, characterized by a higher heat-absorbing capacity. From the thermodynamic viewpoint, the explanation of this phenomenon consists in the fact that the heat release from the troposphere occurs mostly due to air mass convection, which is a much more efficient mechanism than heat transfer by radiation. After the greenhouse gases absorb the heat of radiation, the energy of this radiation is converted into energy of thermal oscillations of gas molecules. This, in turn, leads to the expansion of the gas mixture and its rapid rise to the stratosphere, where due to the rarified nature of the stratosphere, the excess heat is radiated into space. Therefore, in a troposphere with elevated carbon dioxide content the convection of the atmospheric gases will accelerate substantially. There is direct experimental data indicating that the fluctuations of the carbon dioxide partial pressure are the effect, and not a cause, of temperature changes (Khilyuk and Chilingar, 2003; Chilingar and Khilyuk 2007).

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Based on the data obtained from the Antarctic ice cores there is a correlation between temperature fluctuations and changes in the partial pressure of carbon dioxide obtained from the air bubbles in the Antarctic ice sheets of Vostok Station. However, a detailed study of the Vostok Station ice cores showed that the temperature fluctuations preceded the corresponding changes in CO2 concentration in the cores (Monin and Sonechkin 2005). Fischer et al. (1999) and Mokhov et al. (2003) also showed that the changes in CO2 concentration in the atmosphere occur after the global temperature changes, on an average by about 500–1,000 years. This is the time needed for a complete stirring of the upper (active) oceanic layer, which is the main “controller” of carbon dioxide partial pressure in the atmosphere. Thus, the data derived from the Antarctic core studies indicate that the temperature changes over the past 800,000 years had always preceded the corresponding changes in the CO2 concentrations of ice cover. This is indisputable evidence to the fact that the changes in CO2 concentrations of the atmosphere are the effect of the global temperature changes, and not their cause. Figure 18.13 shows the temperature distributions for Earth’s atmosphere in: (1) totally carbon dioxide, (2) totally methane, and (3) Earth’s troposphere. The temperature effects of the greenhouse gas emissions are in the same direction (but much lower in value) in proportion to the concentrations of these gases in the nitrogen-oxygen atmosphere (CO2 4.6 10 4 and CH 4 1.2 10 6 ). For instance, the cooling effect for carbon dioxide will be about 2,200 times, and the heating effect for methane, 800,000 times smaller. Therefore, saturation of the atmosphere with carbon dioxide can result only in the accelerated convective mass exchange in the troposphere, and lead to climate cooling (not heating), whereas an increase in methane concentration in the atmosphere practically has no effect on the Earth’s climate.

18.3.3

Anthropogenic Carbon Effect on the Earth’s Global Temperature

The human generated carbon effect on the Earth’s climate is often evaluated on the emotional perception of the fact that greenhouse gases absorb heat of radiation. One can estimate the quantitative effect of anthropogenic carbon dioxide releases into the Earth’s atmosphere on the climate applying the adiabatic theory of greenhouse effect. Various estimates of the volume of current carbon dioxide released by burning of natural fuels are on the order of 7–10 billion tons or 1.9–2.7 billion tons of carbon per year. This large amount of CO2 not only

Effect of Emission of CO2 and CH4 into the Atmosphere 381 changes the composition of the atmospheric gas mixture and decreases its heat-absorbing capacity, but also slightly increases the atmospheric pressure. These two factors operate in opposite directions. As a result, the average atmospheric temperature of the Earth is not significantly changed. Using Eq. 18.1, after differentiation and transition to finite differences (see also Khilyuk and Chilingar 2003), and assuming that ps 1 atm, one can obtain the following equation:

Ts

T

ps

(18.9)

where Ts, is the change in temperature at sea level attributed to the corresponding change in atmospheric pressure ps (average Earth’s temperature T = 288 K) and the adiabatic exponent = 0.1905. For instance, under the doubled carbon dioxide concentration in the Earth’s atmosphere from 0.046 to 0.092 mass % (as anticipated by the year 2100), the pres0.025 C. sure increase ps would reach 0.46 mbar. Using Eq. 18.9, Ts This temperature rise is not associated with the change in the atmosphere’s composition, but only with some increase in the atmospheric pressure. Thus, the anthropogenic carbon dioxide releases into the atmosphere have no practical influence on the greenhouse effect in the atmosphere. According to Henry’s law, most of the carbon dioxide released into the atmosphere is dissolved in the oceanic water, and upon hydration of the oceanic crust it is bound in carbonates (some CO2 is taken up by plants). Part of the atmospheric oxygen, together with carbon, is also fixed in carbonates. Therefore, instead of some increase in the atmospheric pressure one might expect its slight decrease, which results in a slight climate cooling (rather than its significant warming as suggested by some ecologists). In addition, upon hydration of oceanic crust rocks, part of carbon dioxide is reduced to methane. Currently, due to formation of carbonates and methane generation, 2.3 108 tons/year of carbon dioxide are removed from the ocean, and, therefore, from the atmosphere. The potential of this CO2 removal mechanism, however, is much higher. Although the period of this geochemical cycle is over 100 years, the effect is cumulative over the time. Together with the man-made carbon dioxide, some oxygen is removed from the atmosphere. Based on the CO2 molecular stoichiometry, almost 2.3 g of oxygen is removed from the atmosphere with each gram of carbon. Provided the ocean and vegetation absorb all excessive CO2 after the year 2100, this should result in a decline of atmospheric pressure approximately by 0.34 mbar and, therefore, in the additional climate 0.008 C. In reality, however, life activity of cooling by 8.2 10 3 K

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the plants should almost completely restore the equilibrium distorted by humans (accelerated biomass growth). This would restore the climatic balance. One can summarize our findings as follows: 1. The anthropogenic impact on the global atmospheric temperature is negligible, i.e., 5% (Matthews, 1998). 2. Changes in the solar irradiation (global temperature) precede the corresponding changes in the carbon dioxide concentration in the atmosphere (e.g., see Figure 18.15). 3. The saturation of an atmosphere with carbon dioxide could lead to its cooling (and not vice versa). 4. The global natural processes drive the Earth’s climate: “climate will change, either warmer or colder, over many scales of time, with or without human interference” (Gerhard, 2014). 5. Any attempt to mitigate undesirable climatic changes using restrictive regulations are condemned to failure, because global forces of nature are at least 4 orders of magnitude greater than the available human controls. From the above estimates, one can conclude that even significant releases of anthropogenic carbon dioxide into the Earth’s atmosphere practically do not change average parameters of the Earth’s heat regime.

1373

Watts per square meter

330 ppm

1372 1371 1370 1369 1368 1367 1750

278 ppm

1800

1850

1900

1950

2000

Year

Figure 18.15 Solar irradiance (W/m2) and CO2 concentrations in atmosphere (p-pmv) in Northern Hemisphere (solid dots). (Modified after Hoyt and Schatten, 1997.)

Effect of Emission of CO2 and CH4 into the Atmosphere 383

18.3.4 Methane Gas Emissions Methane molecules have a high capacity of absorption of the infrared photons. According to estimates of the U.S. Environmental Protection Agency (EPA), the GWP (Global Warming Potential) of methane is 21 times higher than the GWP of carbon dioxide over the 100-year time span. Light methane released in the atmosphere ascends into its upper layers where it initially reacts with ozone, ultimately producing (through the chain of reactions) water and carbon dioxide. This process of chemical reactions can be summarized in the following equation:

CH 4 O3 solar radiation

CO2 H2O H2 (18.10)

Hydrogen rises into the stratosphere, whereas water vapor and methane gas form light clouds in the vapor layers of the troposphere (at the border of troposphere and stratosphere). The “greenhouse gases” involved in the reaction absorb infrared radiation at different parts of the infrared spectrum. The rate of oxidation primarily depends on availability of the free OH radicals. The estimated life-time of methane in the atmosphere (estimated by IPCC and adapted by the EPA) is in the range of 8–12 years. Based on these considerations one can consider the global warming (cooling) effect of the methane released as the effect of supplying additional amounts of CO2 corresponding to the amount (and corresponding absorption capacity) of CO2. (For every molecule of CH4 one can substitute 21 molecules of CO2). Thus, one can analyze the radiation warming (cooling) effect of methane as the effect of additional concentration 21 times 1.8 ppm of CO2. This additional concentration of CO2 (37.8 ppm) leads to cooling of the atmosphere as a result of increased convection in the lower layers of the troposphere. Oxidation of methane is a main source of water vapor in the upper troposphere. The methane gas together with the water vapor shields the Earth’s surface from the solar irradiation thus lowering the average Earth surface temperature. The U.S. government is preparing regulations to reduce methane emissions by more than 40% over the next 10 years. Does this mean that we have to stop developing huge deposits of hydrates all over the world? The EPA reported that 29% of all methane emissions in 2012 came from the petroleum industry.

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The major sources of methane on the Earth are: (1) volcanic activity, (2) marshes and tundra, (3) rice paddies, (4) cattle, (5) oil and gas production, and (6) natural gas migration (see Chapter 2) to the Earth’s surface. A great volume of methane is emanated as a result of volcanic eruptions. Yasamanov (2003) estimated about 5 1015  g of CH4 are released yearly to oceanic water at the spreading zones of midocean ridges. The amount of methane released to the atmosphere from marshes and tundra is estimated between 5 1013 and 7 1014 g annually. From tundra, the amount of CH4 released is about 4 1013 g/year. Enteric fermentation contributes 2 1013 to 2 1014 g/year. The total amount of methane released annually into the atmosphere from natural sources is estimated at the level of 2.3 1015 g. Methane is also generated as a result of human activities. Rice paddies produce about 5 1014 g of methane annually. Oil and gas production and related operations add up to 9 1014 g of methane annually, which is one order of magnitude lower than the amount of methane released from the natural sources. A great amount of methane is released to the atmosphere as a result of gas migration to the Earth’s surface from coal, oil, and gas deposits and the Earth’s mantle (Khilyuk et al., 2000). The total amount from the latter source has not been estimated at the present time. Probably, it is around 5 1015 g/year, whereas the fossil fuels burning contribute only 1 1013 g/year of methane to the atmosphere. The content of methane in the atmosphere has been gradually increasing over the last century. In spite of the fact that the methane content constitutes only about 1.8  ppm in the Earth’s atmosphere, the national and international policy makers declared the methane gas extremely dangerous to the Earth’s climate because of a high potency (about 100 times more potent than CO2 over the time span of 20 years) of its molecules to absorb the infrared radiation. Together with the growing contents of CO2 and other greenhouse gases it is supposedly capable of causing drastic changes in the Earth’s climate. According to the conventional anthropogenic theory of global warming, as a result of absorption of the infrared radiation by the molecules of the greenhouse gases, these molecules intercept infrared photons in the lower layer of troposphere warming the Earth’s climate. This anthropogenic theory is the “scientific” basis for strong political and economic actions against further expansion of fracking, for example, in the shale-gas production. The conventional anthropogenic theory (backed and promoted by IPCC and other national and international organizations over the last 25 years) completely ignores the main physical phenomena of the heat transfer in the atmosphere. In particular, it assumes that the heat transfer in the

Effect of Emission of CO2 and CH4 into the Atmosphere 385 atmosphere occurs exclusively by radiation. Meantime in the lower dense layer of troposphere it occurs mostly by convection (67% by convection, 8% by radiation, and 25% by water vapor condensation (Sorokhtin et al., 2007)), which is intensified considerably with an additional release of the so-called greenhouse gases. Moreover, analyzing the postulates in the conventional theory one can find out that this theory completely ignores the fact that molecules of methane and other greenhouse gases (H2O, for example) intercept the infrared solar irradiation in the upper layers of stratosphere and, thus, prevent overheating of Earth.

18.3.5 Monitoring of Methane Gas Emissions In an excellent article, Rossenfoss (2015) discussed the need for better monitoring of methane gas emissions. According to the EPA, the natural gas emissions would rise by 25% by 2025 without further action. According to the EPA, since 1990, the industries natural gas emissions are down by 16%. Rossenfoss (2015) stated that this was mainly due to (1) reduced emissions from controlled devices, (2) installation of plunger lift systems, and (3) green well-completion methods, which capture gas that once escaped from fluids flowing back after fracturing. Based on the study done by the consulting firm ICF (commissioned by EDF), the added cost of a 40% reduction in emissions from natural gas production processing and delivery system would cost about 1 cent per MCF produced using available technology. Rossenfoss (2015) showed that great strides have been made by oil/gas companies in the field of emission control. Operators should regularly monitor and maintain their gas-producing wells and equipment. In conclusion, the authors believe that a voluntary effort on the part of the oil/gas industry to reduce emissions is better than EPA’s planned regulations.

References Allen, D. et al., 2015. Methane emissions from process equipment of natural gas production sites in the United States. Env. Sci. & Technol., 49:641–648. Archer, D., 2010. The Global Carbon Cycle. http://globalchange.umich.edu/ blobalchange1/current/lectures/kling/carbon_cycle/html Bachinsky, A. U., Putilov, V. V. and Suvorov, N. P., 1951. Handbook of Physics. Uchpedgiz, Moscow, 380 pp.

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Bastasch, M., 2015. Satellites: Earth is nearly in its 22nd year without global warming. http://dailycaller.com/authoir/michaelb/. Brandt et al., 2014. Methane leaks from North America natural gas system. Science, 14 Feb. Chilingar, G. V. and Khilyuk, L. F., 2007. Humans are not responsible for global warming. SPE 109202, Paper presented at SPE Technical Conference and Exhibition, Anaheim, California, 11–14 November, pp. 1–12. Chilingar, G. V., Sorokhtin, O. G. and Khilyuk, L. F., 2014. Do increasing contents of methane and carbon dioxide in the atmosphere cause global warming? Atmospheric and Climatic Sciences (ACS), 4:819–827. Chilingar, G. V., Sorokhtin, O. G. and Khilyuk, L., 2009. Greenhouse gases and greenhouse effect. Environ. Geology, 58:1207–1213. Chilingar, G.V., 1956. Relationship between Ca/Mg ratio and geologic age. Bull. Am. Assoc. Petrol. Geol., 40(a):2256–2266. Delingpole, J., 2015. Global Warming ‘Fabrication’ by NASA and NOAA. http:// www.breitbart.com/london/2014/06/23/global-warming-fabricated-by-NASA and-NOAA/ Dillon, R. S., 2015. Scientific Facts and Climate Change: CO2 and Global Cooling. 62 pp. Enzler, S. M., 2015. History of the greenhouse effect and global warming. http:www. lenntech.com/greenhouse-effect/global-warming-history.htm#ixzz3fLgle620. EPA, 2010. Methane and nitrous oxide emissions from natural sources. U. S. Environmental Protection Agency, Washington, DC, USA. Evans, D., 2010. Is the Western Climate Establishment Corrupt, part 5: CO2 Emissions versus Temperature? http://joannenova.com.au/2010/10/is-the-western-climateestablishment-corrupt-part-5. Fischer, H., Wahlen, M., Smith, I., Mastronianni. D. and Deck, B., 1999. Ice core records of atmospheric CO2 around the last three glacial terminations. Science, 283:1712–1714. Geografiska Annaler, 2010. Physical Geography, 92 A(3):339–351, September. Gerhard, L. C., 2004. Climate change: conflict of observational science, theory and politics. Bull. Am. Assoc. Petrol. Geol., 88(9): 1211. Gore, A., 2006. Inconvenient Truth. Rodale Books, 328 pp. Greenberg, J., 2015, Climate scientists “fabricated” temperature data. Fox News, February 13th at 10:11 a.m. Hieb, M., 2009. Climate and the Carboniferous Period. http://www.geocraft.com/ WVFossils/Carboniferous_climate.html. Howarth, R., W., Santoro, R. L., and Ingraffes, A., 2011. Methane and the greenhouse gases footprint of natural gas from shale formations. Climatic Change Letters, DOI:10.1007s 10584-011-0061-5. Keigwin, I. D., 1996. The little ice age and medieval warm period in the Sargasso Sea. Science, 274:1504–1508. Khilyuk, L. F. and Chilingar, G. V., 2004. Global warming and long-term climatic changes: a progress report. Environ. Geol., 46:6–7.

Effect of Emission of CO2 and CH4 into the Atmosphere 387 Khilyuk, L. F. and Chilingar, G. V., 2006. On global forces of nature driving the Earth’s climate. Are humans involved? Environ. Geol., 50:899–910. Khilyuk, L. F. and Chilingar, G.V., 2003. Global warming: are we confusing cause and effect? Energy Sources, 25:357–370. Kotlyakov, V. M., 2000. Glaciology of the Antarctic. Moscow, Nauka, 432 pp. Landau, L. D. and Lifshits, E. M., 1979. Statistical Physics, Part 1. Moscow: Nauka, 59 pp. Landscheidt, T., 2003. New little ice age instead of global warming? Energy and Environment, 14:327–350. Legates, D. R., 2012. Carbon dioxide and air temperature: who leads and who follows. Cornwall Alliance. Marov, M. Y., 1986. Planets of the Solar System. Moscow, Nauka, 320 pp. Matthews, M. Jr., 1998. Who’s afraid of CO2? Nast. Center for Policy Analysis. http://www.ncpa.org/pub/ba256. Mokhov, I. I., Bezverkhniy, V. A. and Karpenko, A. A., 2003. Milankovitch cycles and evolution of the climatic regime and atmospheric composition evolution based on the ice core data from the Antarctic “Vostok” Station. Mater. Glaciol. Stud., 95:3–8. Monckton, C. 2014. Updated Global Temperature: No global warming for 17years. http://www.climatedepot.com/2014/03/04/ Monin, A. S., Sonechkin, D. M., 2005. Climate fluctuations based on observation data: the Triple Sun Cycle and Other Cycles. Moscow, Nauka, 191 pp. Monnin, E. A., Indermuhle, A., Dallenbach, J., Fluckiger, B., Stauffer, T. F., Stocker, D., Raynaud, D. and Barnoa, J. M., 2001. Atmospheric CO2 concentrations over the last glacial termination. Science, 291;112–114. Naumov, G. V., Ryzhenko, B. N. and Khodakovsky, I. L., 1971. Handbook of Thermodynamic Values (for Geologists), Atomizdat, Moscow, 240 pp. NOAA, 2015. 8 reasons why climate change critics are wrong. http://energysocialnetwork.com/blog/8-reasons-why-climate-change-critics-are-wrong. Robinson, A. B., Baliunas, S. L., Soon. W. and Robinson Z. W., 1998. Environmental effects of increased atmospheric carbon dioxide. J. Am. Physicians and Surgeons, 3:171178. Robinson, A. B., Robinson, N. E. and Soon, W., 2007. Environmental effects of increased atmospheric carbon dioxide. J. Am. Physicians and Surgeons, 12:79–90. Rossenfoss, S., 2015. Pressure to reduce methane emissions highlights the need for better monitoring. J. Petrol. Eng., 67(3):46–57. Shakun, J., 2012. Global warming controversial: “Temperature vs CO2: which is the cause and which is the effect?” http://www.abovetopsecret.com/form/ thread826768/pg1 Sorokhtin, O. G., 1990. Greenhouse effect of atmosphere in the geological history of Earth. Doklady AN SSSR, 315, 3:587–592. Sorokhtin, O. G., 2001. Greenhouse effect: myth and realty. Bull. RAEN, 1(1):8–21.

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Sorokhtin, O. G., 2006. Evolution and Forecast of Changes in Earth’s Global Climate. Institute of Computer Studies; NITs Regular and Chaotic Dynamics, Moscowlzhevsk, 88 pp. Sorokhtin, O. G., Chilingar, G. V. and Khilyuk, L. F., 2007. Global Warming and Global Cooling. Evolution of Climate on Earth. Elsevier Amsterdam, 330 pp. Sorokhtin, O. G., Chilingar, G. V., Khilyuk, L. F., and Gorfunkel, M., 2006. Evolution of the Earth’s Global Climate. Energy Sources, 28:1–19. Sorokhtin, O. G., Chilingarian, G. V. and Sorokhtin, N. O., 2011. Evolution of Earth and Its Climate (Birth, Life and Death of Earth). Developments in Earth and Environmental Sciences 10, Elsevier, 576 pp. Venus, 1989. (Atmosphere, Surface, Internal Structure), I Nauka, Moscow, 482 pp. Voitkevich, G. V., Kokin, A. V., Miroshnikov, A. E. and Prokhorov, V. G., 1990. Handbook of Geochemistry. Nedra, Moscow, 480 pp. Wallace, E., 2009. Forced Carbonation: Stupid Easy. http://chanticleersociety.org/ forums/p/843/5678.aspx Yasamanov, N. A., 2003. Modern global warming: causes and ecological consequences, Bull. Dubna Int. University for Nature, Society, and Man, 1(8):12–21.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

19 Fracking in the USA

The following is information on each state and their position on hydraulic fracturing.

Alabama According to the Oil & Gas Journal (2006), coalbed methane (CBM) from the Black Warrior Basin “is the backbone of northwest Alabama’s [gas] production.” The Journal also discussed emerging shale plays in the state like Floyd as potentially boosting the state›s gas production.[1] Fracking is used to access gas in both CBM and shale plays. For CBM, the hydraulic fracturing involves forcing a pressurized fluid mixture including water, acid, surfactant, gel, chemicals, and sand into the earth around coal seams, ranging from 350 to 2,500 feet deep.[2] History The first drilling for coalbed methane in Alabama occurred in the Black Warrior Basin in the 1970s, and took off commercially in the 1980s. Tens

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of thousands of acres in the Basin are leased for drilling wells to access the coal seams; by 2012, there were over 5,500 coalbed methane (CBM) - natural gas - wells operating in the Black Warrior River watershed. Extraction involves hydraulic fracturing.[2] According to the Oil & Gas Journal, “since 1994 Black Warrior CBM wells have consistently produced in the vicinity of 310 to 325 million cubic feet of gas per day, combined.”[1] In the Black Warrior Basin, coalbed methane drilling targets the Pennsylvanian Pottsville Formation, which is part of an unconfined aquifer, and the Cretaceous outcrop, which is associated with high groundwater salinity.[2] Industry focus has also shifted toward shale gas. Shale gas formations in the state include Floyd, Gadsden, Birmingham, and Tuscaloosa. Shale plays

Conesauga Shale, Alabama Wells are currently being drilled to produce gas from the Cambrian Conasauga shale in northern Alabama.[3] Activity is in St. Clair, Etowah, and Cullman counties.[4]

Floyd Shale, Alabama The  Floyd Shale  of Mississippian age is a current gas exploration target in the Black Warrior Basin of northern Alabama and Mississippi.[5][6] The Floyd is found at depths between 4,000 and 6,000 feet and reaches a thickness between 100 and 200 feet.[1] Public lands The U.S. Bureau of Land Management planned to auction off oil and gas excavation rights to 43,000 acres of Talladega National Forest in Alabama on June 14, 2012. If the auction winners determine the land beneath the virgin forests contains petroleum or gas, the likely method of extracting it will be hydraulic fracturing.[7] The NRDC challenged the auction, saying it violated federal law since the BLM did not do a site-specific analysis of the effects, but instead relied on a 2004 analysis that assumed only one well would be drilled in the entire Talladega in a ten-year period. According to the NRDC, the study is inadequate and outdated, as it does not consider fracking and its effects.[8]

Fracking in the USA 391 After public pressure the auction was delayed, but state officials have said the auction could occur in 2013.[9] In September 2013, it was reported that the Alabama state government would join Oklahoma, Montana and Alaska in protesting Bureau of Land Management plans to regulate hydraulic fracturing on federal land.[10] Citizen groups Stop fracking in Alabama

References 1. Peggy Williams, Alabama Hat Trick, Oil & Gas Journal, Mar. 2006. 2. Coalbed Methane & Fracking, Black Warrior Riverkeeper, accessed Jul. 2013. 3. Alabama State Oil and Gas Board (Nov. 2007): “An overview of the Conesauga shale gas play in Alabama,” downloaded 10 Jun. 2009, PDF file. 4. Operators chase gas in three Alabama shale formations, Oil & Gas Journal, 21 Jan. 2008, p.49-50. 5. Mark J. Pawlewicz and Joseph R. Hatch,  “Petroleum Assessment of the Chattanooga Shale/Floyd Shale Total Petroleum System, Black Warrior Basin, Alabama and Mississippi,” US Geological Survey, Digital Data Series DDS-69-1, 2007, PDF file. 6. Alabama Geological Survey, “An overview of the Floyd Shale/Chattanooga Shale gas play in Alabama,” Jul. 2009, PDF file. 7. Fracking risks in Alabama, Decatur Daily, Jun. 1, 2012. 8. Amy Mall, “NRDC challenges illegal oil and gas leasing in Alabama National Forests,” NRDC, Apr. 17, 2012. 9. Mike McClanahan,  Fracking still a possibility in Talladega National Forest, CBS, Apr. 26, 2013. 10. Montana joins 3 other states in protesting fracking rules, Associated Press, Aug. 29, 2013.

Alaska Fracking takes place regularly on about 20 percent of conventional wells in Alaska, according to Energywire in January 2013. Alaska’s North Slope region has been estimated by the U.S. Geological Survey to contain up to 2 billion barrels of oil and 80 trillion cubic feet of gas–second in shale oil only to the Bakken formation in North Dakota. But the agency has admitted that the figures are uncertain, as the region›s shale rock is untested.[1]

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In 2012, the U.S. Geological Survey released an assessment estimating that Alaska’s North Slope shales may hold as much as 80 trillion cubic feet of shale gas, and as much as 2 billion barrels of tight oil (often referred to as shale oil).[2] The report noted that high development costs and limited infrastructure have prevented companies from producing shale resources in Alaska, although Great Bear Petroleum,  Halliburton, and Royale Energy began exploring for tight oil shortly after the 2012 assessment release, thanks in part to the state’s exploration tax credits.[3] Great Bear Petroleum bought 500,000 acres of northern Alaska state land in 2010, hoping to produce 200,000 barrels of crude per day by 2020 (as well as natural gas liquids), shipped via the Trans-Alaska Pipeline. Fracking may begin in winter 2013.[4] The gas resources, unlike the tight oil resources, will likely not be developed without a massive gas pipeline from the remote North Slope to transport it.[3] History: Gas Alaskan gas wells are located in two regions. The largest source is the North Slope area around Prudhoe Bay Oil Field in Prudhoe Bay where gas was discovered along with oil in 1968. In 1974, the State of Alaska’s Division of Geological & Geophysical Surveys estimated that the field held 26 km3 of natural gas.[5] Because there is no way to transport the Prudhoe Bay gas to markets, as gas comes out of the wells, it is separated from the oil stream and reinjected into the ground to maintain the oil reservoir pressures. There are several proposals to transport the Prudhoe Bay gas. The second source is located on the Kenai Peninsula on the South coast of Alaska. The DOE believes there are probable gas reserves of 1,726.4 BCF in this area.[6]  Most of this gas is exported to Japan through a liquefied natural gas terminal located on the Cook Inlet. The Cook Inlet basin contains large oil and gas deposits including several offshore fields. As of 2005, there were 16 platforms in Cook Inlet, the oldest of which is the XTO A platform first installed by Shell in 1964, and newest of which is the  Osprey  platform installed by Forest Oil in 2000. Most of the platforms are operated by Union Oil, which was acquired by Chevron in 2005. There are also numerous oil and gas pipelines running around and under the Cook Inlet. The main destinations of the gas pipelines are to Kenai where the gas is primarily used to fuel commercial fertilizer production and a liquefied natural gas (LNG) plant and to Anchorage where the gas is consumed largely for

Fracking in the USA 393 domestic uses. ConocoPhillips and Marathon Oil operate the LNG terminal under a series of two-year long licenses issued by the U.S. Department of Energy under Section 3 of the Natural Gas Act. When these companies applied for another two-year extension of the license, various Alaskan entities, including the local fertilizer plant, opposed the application on the grounds that there was not sufficient gas to meet local requirements as well as the proposed exports. The Agrium fertilizer plant claimed it closed because it could not obtain a gas supply. On June 3, 2008, the Department of Energy granted the extension saying there were sufficient supplies for Alaska’s needs.[6] Estimated reserves In 2012, the U.S. Geological Survey said it estimates that Alaska’s North Slope shales may hold as much as 80 trillion cubic feet of shale gas, and as much as 2 billion barrels of shale oil. The USGS said that the assessment, which was first made of North Slope shale resources, is based on estimates from extracting oil and gas from similar formations, such as the Marcellus Shale. The estimate will increase the pressure for even more access to oil and natural gas resources in Arctic land and waters.[7] Petroleum geologist Ed Duncan, CEO of Great Bear Petroleum LLC, believes that Alaska’s “North Slope geology will yield bountiful untapped resources as vast as the unconventional oil plays at Texas’ Eagle Ford and North Dakota’s  Bakken shale  fields. He estimates that it would produce 200,000 barrels of crude per day by 2020. He expects production to peak at 600,000 bpd in 2056. Duncan’s estimates have not been verified by others in the industry.[8] Gas pipeline BP Employee Explains Alaska’s Proposed Denali Gas Pipeline The State of Alaska has adopted legislation that would provide $500 million of starter funding for a new pipeline to transport Prudhoe Bay gas. The selected proposal from TransCanada would go through Canada without connecting to the existing natural gas system in Southern Alaska, although three Boroughs have formed the Alaskan Gasline Port Authority to build a line from Prudhoe Bay to Valdez that would connect to the existing system. The gas pipeline emerged as an issue in the 2008 United States elections because Alaskan Governor Sarah Palin cited her actions on the gas pipeline as evidence of “standing up to Big Oil”[9] while her opponents claim it was a political reward to her political supporter TransCanada Corp.[10][11] LNG terminals As of 2012, Alaska is the only U.S. state operating an LNG export plant, owned by  ConocoPhillips  near Kenai. In 2012  ExxonMobil,  BP,

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and ConocoPhillips proposed a $50 billion pipeline and export terminal to increase LNG exports to Asia.[12]

Kenai LNG Kenai LNG is located in Nikiski on the Kenai Peninsula in Alaska, and services the Kenai LNG Plant, which is owned by ConocoPhillips Alaska (70% ownership) and Marathon (30% ownership).[13][14] The Kenai LNG Plant complex includes import and export facilities to transport LNG. The LNG terminal has been operating for 40 years, shipping LNG primarily to Japan. The site’s lease expired in March 2011, and remained inactive for over two years. A lease renewal was granted in April 2014 by the United States Department of Energy. The lease allows the export of the equivalent of 40 BCF of LNG over a two-year period.[13][15] The Kenai LNG Plant complex includes import and export facilities to transport LNG. The LNG terminal has been operating for 40 years, shipping LNG primarily to Japan. The site›s lease expired in March 2011, and remained inactive for over two years. A lease renewal was granted in April 2014 by the United States Department of Energy. The lease allows the export of the equivalent of 40 BCF of LNG over a two-year period.[13][16] The Alaska Oil and Gas Conservation Commission released draft fracking regulations in December 2012. According to the proposed rules, drillers would have to give notice to all landowners and operators within a quarter-mile of the well’s path before fracking it. Shale drillers would also have to evaluate nearby aquifers and take samples from water wells before and after completing an oil and gas well, testing for metals, methane, dissolved solids, and other contamination indicators. The rules would also strengthen existing well construction standards in Alaska, requiring drillers to pressure-test well casing, evaluate well site geology to ensure that fluids don’t pollute water and soil, and consider fault lines that could lead to seismic activity at the fracture site. Under the proposed chemical disclosure rule, companies will not be able to keep trade secrets for hydraulic fracturing ingredients. Drillers would have to disclose all fracking fluid ingredients on the industry-supported website FracFocus.org, including the volume, description, and Chemical Abstracts Service number. The oil and gas commission will hold a public hearing on the proposed rules in February 2013.[17]

Fracking in the USA 395 In September 2013, it was reported that the Alaskan government would join Alabama, Montana, and Oklahoma in protesting Bureau of Land Management plans to regulate hydraulic fracturing on federal land.[18] In November 2013, Alaska regulators issued revised hydraulic fracturing rules that would give oil and gas companies broad discretion to claim as secret the make of their fracking fluids.[19]

References 1. Ellen M. Gilmer, “Fracking trade secrets would get no protection under draft Alaska rule,” E&E News, Jan. 3, 2013. 2. Katarzyna Klimasinska,  “N. Alaska May Hold 80T Cubic Feet of Shale Gas,” Bloomberg, Feb. 24, 2012. 3. Alex DeMarban,  New report reveals vast stores of Alaska shale oil and gas, Alaska Dispatch, Feb. 24, 2012. 4. Margaret Kriz Hobson, Scrappy wildcatters at Great Bear Petroleum go after Alaska›s untapped shale oil, E&E News, Sept. 26, 2013. 5. “Estimated Speculative Recoverable Resources of Oil and Natural Gas in Alaska,” Division of Geological & Geophysical Surveys. Department of Natural Resources, State of Alaska, Jan. 1974 (Adobe Acrobat *.PDF document). 6. DOE Opinion and Order No. 2500 (PDF), p. 45. U.S. Department of Energy (Jun. 3, 2008), retrieved 2008-09-15. 7. Katarzyna Klimasinska,  N. Alaska May Hold 80T Cubic Feet of Shale Gas, Bloomberg, Feb. 24, 2012. 8. Geologist›s Alaska gamble could turn into America›s next big shale play, Energywire, Apr. 3, 2013. 9. “Sarah Palin,” JohnMcCain.com, retrieved 2008-09-15. 10. “GOP Convention Spin, Part II,” FactCheck.org (Sept. 4, 2008), retrieved 2008-09-15. 11. Conflict?”, Anchorage Daily News editorial (2007-12-15). Marty Rutherford, who leads Gov. Sarah Palin’s gas pipeline team, made $40,200 in 2003 while consulting in June for a pipeline subsidiary of TransCanada. TransCanada is one of the companies bidding for a state license to build a pipeline to carry gas to market from Alaska’s North Slope. It’s not a disqualifier, but the past connection deserves a second thought. 12. Eric Roston,  “Shale Fracking Makes U.S. Natural Gas Superpower. Now What?” Bloomberg, Sep 25, 2012. 13. Kenai LNG Exports, ConnocoPhillips Alaska, accessed Nov. 10, 2015. 14. Kenai Alaska Lng Terminal, A Barrel Full, accessed Nov. 13, 2015. 15. Alaska Kenai LNG to resume exports in May: date, Argus, Apr. 30, 2015. 16. Alaska Kenai LNG to resume exports in May: date, Argus, Apr. 30, 2015.

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17. Ellen M. Gilmer, Fracking trade secrets would get no protection under draft Alaska rule, E&E News, Jan. 3, 2013. 18. Montana joins 3 other states in protesting fracking rules, Associated Press, Aug. 29, 2013. 19. Margaret Kriz Hobson,  Revised Alaska fracking rules protect trade secrets, E&E News, Nov. 18, 2013.

Arizona About 10 Arizona wells have been test-fracked in the past 15 years for  CO2, which is used as a form of enhanced oil recovery to stimulate aging oil wells in Texas and New Mexico. In 2012, the pipeline company KinderMorgan paid $30 million for fields rich in CO2 (and helium) near the town of St. Johns in eastern Arizona.[1] Fracking has yet to take place in the state for oil or gas, but exploration of the prospect is underway. Northeastern Arizona is part of the Mancos Shale, a 90-million-year-old, 60-billion-barrel formation spread under much of the West. Almost all of Arizona’s Mancos Shale is on the Navajo reservation, near the Navajo Generating Station in Page. Researchers say they don’t yet know if Arizona’s portion of the Shale contains shale oil, as “there is almost no data on the oil or gas potential of the Mancos in Arizona,” according to the Arizona Geological Survey. The Navajo Nation Oil & Gas Company said in 2013 that it would seek a state permit from the Oil & Gas Conservation Commission to explore the Shale.[1]

Reference 1. Tom Marcinko, Frack Attack? Phoenix Magazine, Jul. 2013.

Arkansas The Fayetteville Shale is a geologic formation of Mississippian age (354– 323 million years ago) composed of tight shale, named for Fayetteville, Arkansas. It stretches from Morrilton on the western side to Searcy on the eastern side. Hydraulic fracturing is increasingly used to access the natural gas.[1] It accounts for 75% of gas production in the state.[2] From 2005 through 2012, over 4,000 wells were fracked in the Fayetteville Shale,[3] with natural gas production in the state increasing from 200,000 mmcf/year in 2005 to over 900,000 mmcf/year in 2010.[2]

Fracking in the USA 397 History Fracking in Arkansas The Mississippian Fayetteville Shale contains gas in the Arkansas part of the Arkoma Basin. The productive section varies in thickness from 50 to 550 feet, and in depth from 1500 to 6500 ft. The shale gas was originally drilled through vertical wells stemming back to the 1920s, but operators are increasingly going to horizontal wells in the Fayetteville. Producers include SEECO, a subsidiary of  Southwestern Energy  credited with discovering the play, as well as Chesapeake Energy, Noble Energy, XTO Energy,  Contango Oil & Gas,  Edge Petroleum,  Triangle Petroleum, and Kerogen Resources.[4] Production In December 2010,  ExxonMobil  subsidiary  XTO Energy  purchased 150,000 acres from Petrohawk in the Fayetteville Shale Trend in Arkansas, bringing XTO’s total acreage in that play to 560,000 acres, and over 10,000 wells.[5] Water Issues A 2015 Stanford study found that Arkansas, Louisiana, West Virginia and Pennsylvania had the highest average water use per each hydraulic fracturing job.[6] Tremors The state is home to the Guy-Greenbrier fault line. According to the documentary, Land of Opportunity, the fault registered over 1,300 earthquakes since it was discovered in 2010.[7] In April 2009, 1- to 3-kilometer-deep fracking wastewater disposal wells were sunk in the vicinity of Guy (population 706) and Greenbrier (population 4706), Arkansas. Shortly after, there was a cluster of earthquakes near Greenbrier. The Guy-Greenbrier area had had only one quake of magnitude 2.5 or greater in 2007 and two in 2008, but there were 10 in 2009, the first year of deep disposal, and 54 in 2010. Geologists warned the Arkansas Oil and Gas Commission, the state agency that regulates deep injection, to “watch out” for more earthquakes. In October 2010, a magnitude 4.0 struck about a kilometer northeast of the deeper of the two new wells, and on November 20, a magnitude 3.9 struck 2 kilometers farther to the northeast toward Guy. Then, in February 2011, magnitude-4.1 and -4.7 quakes struck to the southwest of the deeper well, toward Greenbrier. By spring 2011, nearly 1000 recorded quakes had struck the area since the wells had started.[8]

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The State Oil and Gas Commission was concerned enough about a probable link between the disposal wells and the earthquakes that in July 2011 it ordered that one well be shut down, and it placed a moratorium on new ones in an 1,100-square-mile area. Three other disposal wells closed voluntarily. While small earthquakes are still occurring in the area, their frequency has declined substantially.[9] An article in Science later explained that data from the seismometer network... painted a detailed picture of exactly how the injected wastewater triggered the [Arkansas] quakes. It was injected into an aquifer 3 kilometers down, where it increased the pressure of groundwater in the rock’s pores and fractures. From there the increased pressure due to injection spread through a previously unknown buried fault into the underlying rock, triggering quakes on the fault as it went.”[10] In 2012, some residents of Faulkner County affected by earthquakes filed a lawsuit against subsidiaries of  Chesapeake Energy, which operated two of the wells, and  BHP Billiton, which acquired the wells from Chesapeake as part of a larger purchase in 2011. The suit alleges that the quakes were caused by negligence, amounted to trespassing, and created a public nuisance, and that the companies knew of the risks.[11] According to Reuters, over a dozen residents of Greenbrier have filed five federal lawsuits against the drillers. The first of the suits, filed in U.S. District Court in Eastern Arkansas, is scheduled to go to trial before Judge J. Leon Holmes in March 2014, though the parties have been engaged in settlement talks, according to the court docket.[12] Air pollution

Silica In July 2012, two federal agencies released research highlighting dangerous levels of exposure to silica sand at oil and gas well sites in five states: Colorado, Texas, North Dakota, Arkansas, and Pennsylvania. Silica is a key component used in fracking. High exposure to silica can lead to silicosis, a potentially fatal lung disease linked to cancer. Nearly 80 percent of all air samples taken by the National Institute of Occupational Safety and Health showed exposure rates above federal recommendations. Nearly a third of all samples surpassed the recommended limits by 10 times or more. The results triggered a worker safety hazard alert by the Occupational Safety and Health Administration.[13]

Fracking in the USA 399 Citizen activism In 2012, some residents of Faulkner County affected by earthquakes filed a lawsuit against subsidiaries of  Chesapeake Energy, which operated two wells in the area, and  BHP Billiton, which acquired the wells from Chesapeake as part of a larger purchase in 2011. The suit alleges that the quakes resulted from wastewater disposal and were caused by negligence, amounting to trespassing and creating a public nuisance, and that the companies knew of the risks.[14] According to Reuters, over a dozen residents of Greenbrier have filed five federal lawsuits against gas drillers in the area. The first of the suits, filed in U.S. District Court in Eastern Arkansas, is scheduled to go to trial before Judge J. Leon Holmes in March 2014, though the parties have been engaged in settlement talks, according to the court docket.[15] Legislative issues and regulations Regulators: The Arkansas Oil & Gas Commission (AOGC) and the Arkansas Department of Environmental Quality (ADEQ) perform inspections of well sites and other aspects of gas extraction like disposal sites. The AOGC typically regulates drilling and what happens below ground, while ADEQ regulates practices that could have an effect on the land, water, and air in the area. List of regulations in the state Regulations include surface casing cement requirements and fracking fluid disclosure. In October 2010, the Arkansas Oil and Gas Commission issued proposed amendments to Commission Rule B-19 “Requirements for Well Completion Utilizing Fracture Stimulation.”[16] Regulatory violations From June to September 2012, spills have been reported at natural gas well sites belonging to an Exxon subsidiary,  XTO Energy, in Cleburne, Independence, Faulkner, and White counties.[17] On June 28, 2012, the Oil and Gas Commission sent a notice of violation to R&J Trucking Co. for dumping about 3,780 gallons of production fluids at an XTO Energy natural gas well site.[18]

Diesel in Fracking From 2010 to July 2014, drillers in the state of Arkansas reported using 1,989.67 gallons of diesel injected into 172 wells. The Environmental

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Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[19] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[20]

References 1. “About the Fayetteville Shale,” University of Arkansas, retrieved on Jul. 25, 2011. 2. Bill Powers, Cold, Hungry and in the Dark, New Society Publishers, 2013. 3. Where it happens, Arkansasfracking.org, accessed Sep 2013. 4. Nina M. Rach, “Triangle Petroleum, Kerogen Resources drilling Arkansas’ Fayetteville shale gas,” Oil & Gas Journal, Sept.17, 2007, p.59-62. 5. Jack Williams, Shale Gas: The Keys to Unlocking its Full Potential: Speech by XTO President Jack Williams, ExxonMobil Website, Jun. 14, 2011. 6. Evan Hansen, Dustin Mulvaney, and Meghan Betcher,  The Depths of Hydraulic Fracturing and Accompanying Water Use Across the United States, Environmental Science & Technology, Jul. 2015. 7. “Land of Opportunity,” Emily Lane, 2014. 8. Richard Kerr, Learning How to NOT Make Your Own Earthquakes: As fluid injections into Earth’s crust trigger quakes across the United States, researchers are scrambling to learn how to avoid making more, Science, Volume 335, May 23, 2012. 9. Henry Fountain, Add Quakes to Rumblings Over Gas Rush, New York Times, Dec. 12, 2011. 10. Richard Kerr, Learning How to NOT Make Your Own Earthquakes: As fluid injections into Earth’s crust trigger quakes across the United States, researchers are scrambling to learn how to avoid making more,  Science, Volume 335, May 23, 2012. 11. Mike Soraghan, Drillers face first class-action suit for triggered temblors, E&E News, Jul. 5, 2012. 12. Mica Rosenberg, Insight: Arkansas lawsuits test fracking wastewater link to quakes, Reuters, Aug 27, 2013.

Fracking in the USA 401 13. Adam Voge, Fracking dust alert not shocking in Wyoming, Wyoming Star Tribune, Jul. 30, 2012. 14. Mike Soraghan, Drillers face first class-action suit for triggered temblors, E&E News, Jul. 5, 2012. 15. Mica Rosenberg, Insight: Arkansas lawsuits test fracking wastewater link to quakes, Reuters, Aug 27, 2013. 16. Regulations, GroundWork, accessed Apr. 24, 2012. 17. State agencies probe fluid dumping, Jessica Seaman, Arkansas Online, Sept. 1, 2012. 18. State agencies probe fluid dumping, Jessica Seaman, Arkansas Online, Sept. 1, 2012. 19. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 20. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014.

California The oil and gas industry is touting the potential of fracking in California to tap the largest  tight oil formation in the continental United States, which they say contains up to 64 percent of the nation’s deep-rock oil deposits.[1] Fracking in California is primarily used to extract oil. In some cases, fracking is taking place on private land without the owner’s knowledge.[2] The  Western States Petroleum Association  (WSPA), whose members account for 80 percent of the oil and natural gas drilled in California, said WSPA companies fracked 628 oil wells in 2011 -- about a quarter of all oil and gas wells drilled across the state that year.[3] In 2013, California’s Department of Conservation director Mark Nechodom estimated the state “might see around 650 hydraulic fracturing jobs a year.”[4] More common than fracking in California is acid jobs, an old well completion method that involves pumping chemicals such as hydrofluoric acid into wells to melt rocks and other impediments to oil flow. Companies are not required to report when they do it.[5] A report released in January 2015 stated that nearly half of all new oil wells in the state of California employed the use of fracking.[6] In a 2008 paper prepared for a meeting of the Society of Petroleum Engineers, Pinnacle Technologies reported the fracking process “has been applied to a large scale in many Central and Southern California fields

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to enable economic development and reasonable hydrocarbon recovery. Example formations include the Belridge Diatomite, Stevens Sands, Etchegoin, Antelope shale, McLure shale, McDonald shale, Point of Rocks sands, Kreyenhagen shale, Ranger sands, the Ford Shale, and the Monterey shale.” It also stated that “[b]ased on the initial experience and formation properties, it is believed that hydraulic fracturing has a significant potential in many Northern California gas reservoirs.”[7] Before 2014, the Division of Oil and Gas of the California Department of Conservation did not monitor, track or regulate hydraulic fracturing,[8] stating in a Feb. 16, 2012 update to its website that “fracking is used for a brief period to stimulate production of oil and gas wells” in California, but “the Division doesn’t believe the practice is nearly as widespread as it is in the eastern U.S. for shale gas production,” negating the need for monitoring. What the Division does not say, according to the Environmental Working Group, is that most fracking in California is used for oil, not gas, production.[9] The passing of State Senator Fran Pavely’s SB 4 put in place some process to track hydraulic fracturing and another enhanced well completion form called acidizing. Center for Biological Diversity researchers note that ten California counties: Colusa, Glenn, Kern, Los Angeles, Monterey, Sacramento, Santa Barbara, Sutter, Kings and Ventura.[10] The exact number of fracked wells in the state is unknown, but the Environmental Working Group states that it “is clear that the total likely reaches into the thousands. Industry documents show that by the mid-1990s, more than 600 wells had been fracked in one Kern County oil field alone. Representatives of  Halliburton  told EWG in the fall of 2011 that 50-to-60 percent of new wells being drilled in Kern County were hydraulically fractured.[9] In June 2013, the Los Angeles Times reported that a USC/LA Times poll showed that more than 70% of California voters favored banning or heavily regulating chemical injections into the ground to tap oil and natural gas. [11]  It was reported in September 2013 that Californians (51 percent) continue to oppose than favor (32 percent) increased use of fracking, according to a statewide survey released Wednesday evening by the non-partisan Public Policy Institute of California.[12] Hydraulic fracturing - creating fractures from a wellbore drilled into reservoir rock formations - has been used on thousands of wells in California for over fifty years, according to a review of scientific articles by the Environmental Working Group.[9][1] The current fracking technique of high-pressure water, chemicals, and sand is often seen as originating in the late 1990s, in the Barnett Shale in Texas.[13]

Fracking in the USA 403 In November 2011, the Los Angeles Times reported that Gov. Brown fired Derek Chernow, then head of the Department of Conservation, as well as Chernow’s deputy, Elena Miller, after they generated a memo highly critical of “unconventional” oil extraction methods, primarily steam injection but also encompassing fracking. The process was put under a microscope in 2011 after an oil company worker died in Kern County from falling into a boiling cesspool of fracking discharge. Brown pushed Chernow to relax the regulations in 2011, but instead Chernow generated the memo concluding that relaxing regulations would violate federal laws. Shortly thereafter, Brown fired Chernow and his deputy, and installed Mark Nechodom, who sided with Brown and reduced the heightened scrutiny that had been placed on underground injection. In January 2012, The Times reported that Occidental Petroleum made a $250,00 contribution to Brown. Shortly after, the state Division of Oil, Gas and Geothermal Resources said it did not plan to monitor or manage use of the technology unless the legislature requires it or the agency is handed “evidence of manifest damage and harm.”[14] In 2012, regulators told the Los Angeles Times that they monitor drilling operations quite thoroughly under existing law, but also said there is a need for more disclosure of what chemicals are used in oil production. According to the Times: “State Sen. Fran Pavley (D-Agoura Hills), chairwoman of the Committee on Natural Resources and Water, wrote to state regulators [in 2011] asking basic questions: ‘Where does fracking take place; How often is it used; And what are the potential risks?’ Regulators had few answers, saying they had ‘limited data’ because the state has no reporting requirements.”[1] Many state regulators assert that fracking in California is “radically different” from drilling in other parts of the U.S., saying the process has long been performed in the state for shorter duration with much less water to loosen crude in depleted oil wells.[1] At a March 28, 2012 hearing, lawmakers criticized the Gov. Brown administration’s lack of actions on fracking, and state environmental officials requested that energy companies disclose where they conduct fracking operations and what chemicals they inject into the ground to tap oil deposits. At the time, only 78 of the tens of thousands of California oil field injection wells where fracking may be taking place were listed on a national fracking registry. Regulators also are considering whether to launch an independent study to assess effects of the practice, and are planning to undertake a statewide listening tour for public comment. [15]

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Oil and gas estimates California is estimated to have more  tight oil  (shale oil) than  shale gas. Most estimates focus on the Monterey Shale, a rib-shaped formation that extends from northern California down to the Los Angeles area, offshore, and onto the outlying islands, spanning 1,750 square miles. Counties include Kern County, Orange County, Ventura County, Monterey County and Santa Barbara County, California. It is composed of many substances[16]  and is not flat like other shales due to frequent earthquakes. [17]  Some companies have called the Monterey Shale arguably the largest shale play in the US.[18] Estimates vary about how much oil lies in the state’s shale rock formations. The estimate of “technically recoverable oil” is determined by

Monterey Shale Formation in California

Fracking in the USA 405 multiplying the total amount of “oil-in-place” by the “recovery factor,” or the percentage of oil that can be recovered with today’s technology.[19] Venoco, one of the companies with a significant presence in Monterey, once said there might be 300 billion barrels of oil in the Monterey Shale, but their first well was labeled “uneconomical,” and their estimate has been seen as far too high.[20] In 2011, the U.S. Energy Information Administration said there could be up to 15 billion barrels of crude in the Monterey Shale,[20] an estimate repeated by the Department of Energy[21] and the New York Times. In May 2014, the EIA said 600 million barrels of oil could be extracted from the Monterey Shale with existing technology, cutting by 97% its earlier estimate of 13.7 billion barrels.[23] In October 2015, the U.S. Geological Survey trimmed the  Monterey Shale  estimates further. The organization now estimates that the San Joaquin Basin portion of the Monterey Shale to 21 million. [24]

Production The Energy Information Administration estimated that Monterey would produce 550 million barrels total per well, but “operators today are reporting typical flow rates averaging only around 350 to 400 barrels per day, according to a November 2012 article in  World Oil  (fee required). According to Dave Roberts at Grist: At 400 barrels a day, it would take a well 3,767 years to hit 550 million barrels.[19] Geologist J. David Hughes of the Post Carbon Institute argued “initial productivity per well from existing Monterey wells is on average half to a quarter” of EIA assumptions, and cumulative recovery of oil per well “is likely to average a third or less of that assumed by the EIA.” This estimate comes from his 2013 analysis of existing data: “1,363 wells have been drilled in shale reservoirs of the Monterey Formation. Oil production from these wells peaked in 2002, and as of February 2013 only 557 wells were still in production. Most of these wells appear to be recovering migrated oil, not ‘tight oil’ from or near source rock as is the case in the Bakken and Eagle Ford plays.” He concludes that the EIA’s 15 million barrel estimate is likely highly inflated.[25] Drilling wells The database maintained by the oil and gas industry’s website FracFocus, where companies can voluntarily disclose information about their fracking practices, lists 78 wells in California as of Feb. 21, 2012. According to the Environmental Working Group: “Of these, one is in Los Angeles, one in Ventura County and two are off the coast of Long Beach. One is shown

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near Santa Barbara on a map, but the attached documentation places the well in Kern County. The other 73 wells are also in Kern County. All of these wells were fracked sometime in 2011 or 2012. Listings on FracFocus are entirely voluntary and are known to be incomplete, so this accounting is not likely to be comprehensive.”[9]

Use of Diesel Fuels In 2011, a Congressional investigation determined that 26,444 gallons of diesel fuel had been injected into California wells in hydraulic fracturing fluids from 2005-2009.[9]

Natural Gas In 2011, notices to drill new natural gas wells in Northern California were received at a rate not seen in over twenty years. As of August 2011, the California Department of Conservation issued 178 permits to drill new wells in Butte, Colusa, Contra Costa, Glenn, Solano, Sutter, Yolo, San Joaquin, Sacramento and Tehama counties. At that rate, 267 notices would be filed by the end of 2012, compared to 137 in 2000 and 78 in 1995.[26]

Los Angeles County In October 2015, DOGGR released to the public an audit of its regulation program. The audit concluded that since 2007, most oil projects in the Los Angeles area had not been subject to a required annual review.[27]

Inglewood In 2012, it was reported that PXP was using fracking in the Inglewood oil field, the nation’s largest urban oil field, which has been operating in Los Angeles since the 1920s and extends through parts of the central coast and San Joaquin Valley. A 2006 release of noxious gases at the Inglewood Field galvanized community members and environmental groups to sue Los Angeles County, forcing it to augment protections the county had previously created in partnership with PXP. The parties reached a settlement in 2011 that further limited PXP’s oil drilling activities, including reducing the number of

Fracking in the USA 407 wells the company could drill. As part of the settlement agreement, PXP agreed to conduct a study that examined the feasibility and impact of current and future fracking at the oil field. It would be the first study to look at the impact of fracking in California, including its impact on groundwater. According to the Natural Resources Defense Council, the community that surrounds the oil field did not know about the 2012 test fracking until March 9, after the fracking was complete. According to FracFocus, the two vertical wells were fracked in September 2011 and January 2012. PXP used to 168,000 gallons of water laced with chemicals in one well to a depth of about one and half miles. The Regional Water Quality Control Board, Los Angeles Region, is concerned the impact such practices may have on the above water supplies.[28] Over one million people live within five miles of the site. The fracking site also sits atop a fault line capable of 7.4 magnitude earthquake.[29] On October 10, 2012, the environmental consulting firm Cardno ENTRIX released a  report  commissioned by PXP, entitled “Hydraulic Fracturing Study: PXP Inglewood Oil Field,” which concluded that fracking could be done safely in the area and seismicity could be mitigated. Cardno Entrix had previously been hired by  TransCanada  to do the environmental impact statement (EIS) for the Keystone XL Pipeline. PXP and Los Angeles County contracted with JPMartin Energy Strategy LLC to peer review the report. J.P. Martin is director of the Shale Resources and Society Institute, which was created after a gas industry-funded lecture series on shale gas at SUNY Buffalo. SSRI produced a study in May 2012 finding no adverse effects with fracking; all four co-authors were later found to have ties to the oil and gas industry, prompting 83 SUNY Buffalo faculty and staff members to call for an independent investigation into the origins of the SRSI.[30]

Long Beach Fracking takes place off the coast of Long Beach, California on man-made oil islands. It was reported in 2013 that 203 fracking operations had taken place offshore Long Beach at six different sites over the past 20 years.[31] An April 2015 investigative piece in OC Weekly noted that since 2012 there have been at least 22 hydraulic fracking operations completed offshore in Long Beach as well as at least 150 acidizing operations and 90 gravel packing jobs.[32] In late June 2015, Thums Long Beach Co applied for nine fracking permits for offshore operations in Long Beach. The permits, which are the first

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step to get the operations approved, were okayed by the California Division of Oil, Gas and Geothermal.[33]

Kern County Kern County produces the most oil of any county in the U.S. In 2015, Kern had around 42,000 active wells. The county is responsible for 75% of California’s oil wells and 95% of the fracking[34] As of May 2012, there are 95 drilling wells posted on FracFocus, with the vast majority of the fracking projects reported in Kern County. FracFocus pinpoints a cluster of 58 wells fracked in 2011 between Lost Hills and McKittrick by XTO Energy/ExxonMobil. Many of the frack jobs pumped several hundred thousand gallons of water into wells about 3,000 feet deep. Another cluster of 12 wells in the Wasco-Shafter area was fracked in 2011 by Occidental Petroleum.[35] In May 2012, Kern County’s biggest oil producers, consenting to a request by state regulators, agreed to share information about their fracking operations by the end of June 2012. Chevron, Berry Petroleum Co., Bakersfield’s Area Energy LLC and other members of the  Western States Petroleum Association will disclose data on their work with fracking on FracFocus.[36] NASA found the second brightest methane hot spot in the U.S. from space appears to be above Harris Ranch, California’s largest beef producer, and near the Bakersfield oil fields.[37] In November 2015, the Kern County Board of Supervisors unanimously voted to approve one single environmental to take in effect December 2015 that would fast track individual projects in as little as seven days. Three oil industry groups spent more than $10 million in crafting the proposal.[38]

Monterey County As of 2012, Venoco holds about 256,000 gross acres in the Monterey Shale formation, which starts in Monterey County and stretches across central California. An additional 60,000 acres have already been drilled. The firm has drilled more than 20 wells across the formation since 2010, and invested $100 million -- or nearly 40 percent -- of its 2012 expenditure budget to exploring for oil. The company has drilled four exploratory wells in Monterey County and plans for nine more.[39] A move to ban fracking in Monterey County is slated for the November 2016 election.[40]

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Santa Barbara County In 2011, County of Santa Barbara made it difficult to frack onshore by mandate that all hydraulic fracturing on unincorporated county land be reviewed and approved. The county did not subject cyclical steaming and acidizing to this process. This happened after  Venoco spilled wastewater in a field of Riesling grapes in northern Santa Barbara County near Vandenberg Air Force Base. [41] Based on information gathered from a 2010 oil prospectus from Venoco, investigated by the Environmental Defense Center (EDC), and confirmed by the federal government, there was fracking done in 2009 on the Gail oil platform in the Sockeye field in federally controlled waters near Santa Cruz Island in the Channel Islands. In another financial disclosure document, there are hints from Venoco’s public filings that the company planned to enhance, through prop fracture (an older method of enhancing older wells) or possibly fracking, their other active offshore oilfield in California state waters, known as the South Ellwood -- a field approximately seven miles long and part of the northern flank of the Santa Barbara channel and extending to the Ventura basin.[42]

Offshore Offshore Fracking in California In July 2013, the news site Truthout reported that federal regulators approved at least two hydraulic fracturing operations on oil rigs in the Santa Barbara Channel off the coast of California since 2009 without a dated environmental review to account for modern fracking technology. Regulators approved both operations by signing off on modifications to existing drilling permits. In an internal email, the Bureau of Safety and Environmental Enforcement (BSEE) Chief of Staff Thomas Lillie wondered how the agency could allow fracking offshore without producing an environmental impact statement (EIS) on the effects. No studies have been performed on the effects of fracking fluids on the marine environment.[43] It was later reported that the BSEE gave “categorical exclusions” to oil companies for frack jobs on existing offshore oil rigs, allowing them to proceed with the activity in the federal waters off California without public disclosure or environmental impact analysis. According to federal

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guidelines, categorical exclusions are intended for projects that don’t warrant an environmental review because they don’t normally “result in significant environmental harm.”[44] According to a BSEE fact sheet, fracking has occurred 11 times in the Pacific drilling region during the past 25 years, although BSEE officials say the number is only an estimate. Under heavy pressure from environmental groups and state politicians, the California Coastal Commission launched an investigation into offshore fracking, saying it was not aware that fracking technology was being used offshore. On August 6, nine California lawmakers sent letters to the Interior Department and the EPA demanding a federal investigation into offshore fracking, and asking the coastal commission to review federal offshore fracking permits and use its authority to block fracking activities that could harm the California coast.[43] An October 2013 Environmental Defense Center review and analysis of federal records received through the Freedom of Information Act (FOIA) showed that at least 15 fracs have occurred offshore California, with several more proposals pending. But according to EDC: “More fracs have almost certainly been conducted, however, as federal regulators were until recently unaware that the practice was being used.” Saying the offshore frac jobs raise questions about compliance with environmental laws, EDC recommends a “moratorium on offshore fracking and other forms of well stimulation unless and until such technologies are proven safe through a public and transparent comprehensive scientific review” and to “prohibit the use of categorical exclusions (exemptions from environmental review) to authorize offshore fracking and other forms of well stimulation.”[45] According to interviews and drilling records obtained by the Associated Press in October 2013, energy companies employed offshore fracking at least 203 times at six locations over the past two decades. The drilling sites included waters off Long Beach, Seal Beach, and Huntington Beach, all popular tourist areas.[46] A settlement to a lawsuit filed by the Center for Biological Diversity against the U.S. Department of the Interior prompted an offshore fracking moratorium off the California coast. A press release by the Center for Biological Diversity stated that the “agreement requires the Interior Department’s Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement to analyze the environmental dangers of offshore fracking and acidization under the National Environmental Policy Act. The settlement also prohibits federal officials from authorizing these inherently dangerous practices in federal waters until that analysis is concluded.”[47]

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Oil Spill in Santa Barbara In response to a moderate sized oil spill off the coast of Santa Barbara in May 2015, environmental groups warned that such spills are likely to happen again as long as offshore oil drilling, including fracking, continues to take place off the coast of California.[48] On May 19, 2015 a rupture in a pipeline owned by All American Pipeline caused over 142,800 gallons to spill on the beach and ocean. It is commonly known as the Refugio Oil Spill named after Refugio Beach located just north of Santa Barbara where the majority of the crude landed. State wildlife workers would eventually collect and tall both dead and live birds and animals from the spill. The tally would include 202 dead birds, 65 live ones, 99 dead mammals, including 15 dolphins, and 63 live mammals. Sixty-nine pelicans, sea lions, loons, and others would be treated and later freed.[49] Sea mammals were found washed up in the cities of Ventura and Oxnard south of the spill. Federal regulators from the Pipeline and Hazardous Materials Safety Administration determined in February 2016 that external corrosion was the cause of the spill.[50] The Santa Barbara Independent reported that federal regulators determined that All American Pipeline employees waited 89 minutes to report the spill.[51] Many onshore and offshore oil employees facilities lost their jobs because oil was no longer transported through the area.[52] ExxonMobil’s Heritage, Harmony, and Hondo platforms were out of commission after the Refugio Oil Spill shut down the All American Pipeline. Venoco  was one of several local operating companies negatively affected by the pipeline spill. On February 16, 2016 Venoco missed submitting its $13.7 million semi-annual interest payment. Venoco, ExxonMobil, Freeport-McMoRan offshore oil platforms ceased operating shortly after the spill because the federal Pipeline and Hazardous Materials Safety Administration shut down pipelines moving crude oil to refineries. In November 2015, Venoco reported a net loss of $203.3 million for the third quarter.[53]

Ventura County Oxnard, California is home to an active tar sands field located in a large field of farmland. The Oxnard oil field has both wells drilling to the Monterey

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Shale  and cyclical steaming wells to attract bitumen, also known as tar sands. In 2011 tar sands drilling destroyed a field of broccoli. [54]

Public Lands In October 2013, Los Angeles County leaders voted unanimously to oppose a plan to drill for oil in publicly owned parkland in the Whittier hills, saying the proposal would undermine open space protection throughout the county. The drilling was proposed by Matrix Oil Co. in agreement with the city of Whittier, neither of which said they would recognize the county’s vote. Litigation is underway. The dispute is over whether the city has the right to allow oil drilling on 1,280 acres it purchased in 1994 with about $17 million of Proposition A funds, which were intended for conservation purposes. Under terms of the proposed lease, Matrix would use slant-drilling technology to tap an estimated 20 million barrels of tight oil, in exchange for the city receiving royalties. Whittier officials believe that they are legally entitled to the oil because they say the city retained the mineral rights, even if the land was purchased with county bond money for conservation purposes.[55] Fracked oil by rail In October 2014, the Wall Street Journal reported that California rail depots that will begin to handle oil from North Dakota’s Bakken Shale. In order to handle the demand, Alon USA Energy Inc. is building the state’s largest oil-train terminal Kern Country. That terminal, which is to be completed in 2015, will receive 150,000 barrels of oil a day in Bakersfield, California. Additionally, Plains All American Pipeline is opening a 70,000-barrel-a-day oil-train terminal, also located in Bakersfield. The oil for this terminal will also come from fracked gas from North Dakota’s Bakken Shale.[56] The Phillips 66 Santa Maria Refinery in Arroyo Grande, California plans to expand its rail line. The first Environmental Impact Review indicated the oil on the rail would be the North Dakota Bakken formation Shale. The October 2014 Environmental Impact Report indicated the rail would only haul Canadian tar sands from Alberta›s boreal forests. Trains coming and going from Santa Maria Refinery would travel the path of the Union Pacific Rail, on tracks shared by Amtrak. They would make the journey north through Ventura and Santa Barbara County to the Nipomo Mesa, through Paso Robles, Salinas, and San Jose. Then they head

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California Oil Imports Rising

through Richmond, then Berkeley. The cities of Moorpark, Richmond, and Berkeley city councils passed resolutions calling for stricter regulations on crude oil trains. [57] Water use and wastewater The average fracked well in California used 166,714 gallons of water, according to a 2013 Ceres report.[58] In 2011, onshore oil and gas drilling wells in California produced more than 2.5 trillion barrels of produced water; over 126 million was produced at the Inglewood oil field of Los Angeles County.[59]

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A 2014 report by World Resources Institute found that ten gas deposits “sit atop aquifers that are being withdrawn at rates that far exceed their natural recharge rate,” including California’s Monterey formation, which covers the southwest coastal region around Los Angeles and inland near Bakersfield as well as in Texas and the Rocky Mountains.[60] In 2014, fracking in California used 75 million gallons of water.[61]

Risk Assessments As of 2012, California has not assessed fracking’s risks to California’s groundwater, according to a 2012 Environmental Working Group (EWG) report. The report cites a 2011 letter in which Sen. Fran Pavley asked state regulators to “provide the results of any risk assessments that the State of California has conducted regarding potential groundwater contamination associated with hydraulic fracturing.” The agency responded: “The division does not know of any state risk assessment regarding potential groundwater contamination associated with hydraulic fracture.”[9] According to Clean Water Action (CWA), fracking poses many risks for California’s water supply since a single frack well can use wards of hundreds of thousands to millions of gallons of water. Additionally, CWA second’s EWG’s report that fracking could pollute groundwater supplies in the state.[62] A 2015 report by EWG, which analyzed data released by the state during the first year of new reporting requirements, found high levels of benzene in fracking wastewater. Additionally, the study revealed “the presence of hundreds of chemicals, including many linked to cancer, nervous system damage and reproductive disorders.”[63]

Leaks, Spills, and Accidents In 2009, a jury in Kern County found that 96 million barrels of wastewater from drilling had leached from holding ponds onto a farmer’s property, resulting in contamination of the aquifer beneath his land.[64] According to the Environmental Working Group: “It’s unknown if any of this wastewater came from hydraulic fracturing; what is clear is that California’s ground and drinking water are not being adequately protected from the hazards of fracking and oil and gas operations in general.”[9] In 2010, contaminants from a wastewater injection well bubbled up in a west Los Angeles dog park.[65]

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California Aquifers Contaminated In July 2014, California state regulators shut down 11 fracking wastewater injection wells over concerns that the wastewater might have contaminated aquifers used for drinking water and farm irrigation. Following the shutdown, the EPA ordered a report within 60 days. In October 2014, the California State Water Resources Board has sent a letter to the EPA which confirmed that “at least nine of those sites were in fact dumping wastewater contaminated with fracking fluids and other pollutants into aquifers protected by state law and the federal Safe Drinking Water Act.”[66]

Benzene Data released in February 2015 from a report on California fracking found that there was 700 times the federal standard amount of Benzene in fracking waste fluids. The raw data showed that 98% of wastewater samples taken from 329 fracking sites in the state had dangerous levels of benzene, which is a known carcinogen. The data was gathered over a one-year period by the Center for Biological Diversity.[67] The EWG ran tests on 293 wastewater for the organization’s 2015 wastewater report. Benzene was found in 99 percent of the samples. All detections exceeded the California drinking water standard. Eighty percent exceeded it by factors of 100 to 1,000. [68]

Toluene Toluene, a neurotoxin classified as a potent reproductive toxin under Proposition 65. The EWG ran tests for toluene in 293  hydraulic fracking  wastewater samples. EWG detected toluene in 83 percent of the samples at levels above the drinking water standard. [69]

Illicit Dumping In February 2015, Kern County water officials discovered hundreds of unlined fracking wastewater pits that were operating without permits. The Central Valley Regional Water Quality Control Board found that more than one-third of the region’s active disposal pits were operating without proper permits. The unlined pits raise concerns that groundwater could

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be contaminated in the area. The operators of these sites will not be shut down, but will have to apply for permits and monitor the sites if they are near water sources.[70]

Farming Impacts In August 2015, California State Assemblyman Mike Gatto, who represents the Los Angeles area, introduced a bill that will be considered as part of the California Legislature’s Special Session on health. The bill, if it passes, would require labels to be placed on food that was grown using fracking wastewater.[71] Injection wells Over 25,000 oilfield injection wells are operating in the state. Injection wells are used to increase oil recovery and to dispose of the salt and fresh water produced with oil and natural gas. Class II wells involve injecting fluids associated with oil and natural gas production operations - generally the brine that is produced when oil and gas are extracted from the earth.[72] On July 7, 2014 California’s Division of Oil and Gas and Geothermal Resources “issued cease and desist orders to seven energy companies warning that they may be injecting their waste into aquifers that could be a source of drinking water, and stating that their waste disposal ‘poses danger to life, health, property, and natural resources.’” In all, 11 companies were ordered to stop injections, while 100 more were being reviewed in California’s Central Valley, which has been impacted by a severe threeyear drought. State officials were concerned that toxic waste from injection wells could enter groundwater supplies that farmers are using to irrigate crops in the region.[73] In March 2015, California regulators ordered a halt to wastewater injection operations at 12 underground well sites in Kern County. The action was part of a systematic statewide review of injection related to the oil and gas industry.[74] In 2015, the U.S. EPA conducted an investigation into the state’s regulation of wastewater injection wells. The U.S. EPA charged the state for allowing drillers to inject oil waste into federally protected aquifers. More than 2,500 illegal injection wells were identified in California. [75] In October 2015, the state shut down 33 wells that were injecting wastewater into California aquifers. As of October 2015, the state shut down a total of 56 wells in the state that were pumping wastewater into local aquifers.[76]

Fracking in the USA 417 In 2016, Stanford University scientist, Rob Jackson, identified hundreds of  hydraulic fracturing  wells drilled into California aquifers located less than 2,000 feet below the surface.[77]

Earthquakes According to USGS Earthquake Science Center’s Art McGarr, there are no high-volume wastewater injection wells in California located within areas of high population density, to his knowledge. There is also, however, no way to verify this due to the lack of state and federal disclosure laws. [78]  Wastewater injection into disposal wells has been linked to a series of small earthquakes in Ohio[79] and the U.S. mid-continent.[80] Geologists in a February 2016 article in Geophysics Research Letters tied a September 2005 swarm of earthquakes near the White Wolf fault in Kern County to three wastewater disposal wells nearby. Using hydrogeological modeling, the authors found that wastewater disposal likely contributed to seismicity via localized pressure increase along the active fault.[81]

Exemptions A 2012 ProPublica investigation into the threat to water supplies from underground injection of waste found the EPA has granted energy and mining companies exemptions to release toxic material in more than 1,500 places in aquifers across the country. The EPA may issue exemptions if aquifers are too remote, too dirty, or too deep to supply affordable drinking water; however, EPA documents showed the agency has issued permits for portions of reservoirs that are in use, assuming contaminants will stay within the finite area exempted. More than 100 exemptions for natural aquifers have been granted in California, some to dispose of drilling and fracking waste in the state’s driest parts. Though most date back to the 1980s, the most recent exemption was approved in 2009 in Kern County, an agricultural area.[82] Porter Ranch storage container leak As of December 31, 2015, a natural gas leak outside of Los Angeles at Porter Ranch, was releasing 110,000 pounds per hour for at least two months. The leak was described as the worst environmental disaster in the United States since the BP oil spill. The seeping gas was being released from a storage facility in Porter Ranch, where experts state the leak was being caused by a well casing failure deep underground.[83]

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On January 6, 2016, Gov. Jerry Brown declared a state of emergency in Porter Ranch, California because of the gas leak, which has led to thousands of residents leaving their homes.[84] Other oil recovery methods

Acidizing Acidizing, also referred to as “matrix acidization,” typically involves the injection of high volumes of hydrofluoric acid, a powerful solvent (abbreviated as “HF”) into the oil well to dissolve rock deep underground and allow oil to flow through the well. Conventional fracking, in which water and other chemicals are pumped at high pressure to create fissures in the rocks, reportedly does not work well in many parts of the Monterey Shale – a rock formation known for its complexity and low permeability, which makes fracking less effective. Acidizing, in contrast, is popular in California because the oil-bearing shale is already naturally fractured and buckled from tectonic activity.[85] Hydrofluoric acid corrodes glass, steel, and rock. Drillers have been injecting it underground for years in diluted quantities (to 9% HF) to get out the last bits of oil from nearly depleted wells, and injecting in stronger concentrations to dissolve oil-bearing shale. The concentrations of HF acid used by oil companies are unknown, as is what happens over the long term to the rock, and to the HF acid-laced water. Drillers must get a permit from the state Division of Oil, Gas, and Geothermal Regulations, but do not have to tell the state if they are fracking, using acid, or something else, although SB4, passed in September 2013, does include fracking and acidizing under state purview.[86] HF is one of the most hazardous industrial chemicals in use, according to the U.S. Centers for Disease Control. The United Steelworkers want its use phased out of oil refineries entirely, calling it a risk too great for the steelworkers and the 26 million Americans living near refineries. The California Occupational Safety and Hazard Administration is not tracking HF acid usage underground within the state.[86] Currently, large amounts of HF (precise volumes are an industry secret) are routinely trucked around California and mixed at oilfields, creating the potential for spills and leaks.[85]

Cyclic Steam Stimulation Steam injection is an increasingly common method of extracting heavy crude oil. It is considered an enhanced oil recovery (EOR) method and is

Fracking in the USA 419 the main type of thermal stimulation of oil reservoirs. There are several different forms of the technology, with the two main ones being Cyclic Steam Stimulation and Steam Flooding. Steam injection is widely used in the San Joaquin Valley, Santa Maria, Oxnard, and other parts of California. Some have compared the process of Cyclic Steam Stimulation (CSS) to a chemical-free version of fracking. Unlike the more common well stimulation practice called steam flooding, cyclic steaming injects steam at high pressure specifically to break relatively shallow, diatomaceous soil. CSS is used with ultra heavy oil and oil sands, also known as tar sands. CSS is also called “huff and puff.” In CSS, drillers install two wells, one of which goes for the heavy oil or tar sands. A second well nearby uses natural gas to fire up generators to heat the ground to 550 degrees Fahrenheit. The steam melts the oil or tar sands allowing it to move to the surface. A similar technique is called steamassisted gravity drainage (or SAG-D), which is common in the tar sands fields of Alberta. SAG-D is a hyped up version of huff-and-puff that uses multiple steam sessions and hotter temperatures to recover the naturally solid tar sands. SAG-D is commonly used in the Oxnard tar sands field.[87] California state regulators began scrutinizing the practice in the aftermath of a Chevron manager’s sinkhole death at the Midway-Sunset oil field in 2011.[88]  The theory behind the sinkhole is that high-pressure steam migrated from a nearby injection project and escaped through Chevron›s problem well.[89] According to The Bakersfield Californian, CSS created ongoing problems at the oil fields: “Other oil fields in Kern County have repeatedly experienced seepage and even violent volcanoes in which oil, water, and rocks can shoot 50 to 60 yards through the air. In fact, about a month and a half after [Chevron manager] Taylor’s death, one such insertion at the sinkhole site continued for three days. That event prompted DOGGR to shut down steam injection activity within 500 feet of Chevron’s ‘broken’ well.”[89] Citizen activism

State Lawsuit On October 16, 2012, environmental groups sued the state of California, accusing state regulators at the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources with failing to evaluate the risks of fracking, even as fracking was used for 600 wells in 2011. Earthjustice filed the lawsuit in Alameda County Superior Court on behalf

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of the Center for Biological Diversity, Earthworks, the Environmental Working Group, and the Sierra Club.[90] In July 2016, the Center for Biological Diversity sued the state of California for “finalizing an inadequate environmental review of fracking eight days before the release of a state-mandated study showing that fracking and oil industry pollution threatens air, water and public health.”[91]

Federal Lawsuit Hydraulic Fracturing in Inglewood In late December 2011, environmental groups including the Center for Biological Diversity and the Sierra Club filed a lawsuit against the Bureau of Land Management claiming the bureau leased more than 2,500 acres of public land in Monterey and Fresno counties to oil companies without doing a thorough analysis of the potential environmental impacts of fracking.[92] The lessees have 10 years to develop the land, after which it reverts back to the federal government if not drilled.[93] On April 8, 2013, a federal judge ruled that the Obama Administration violated the National Environmental Policy Act when it issued oil leases in Monterey County, Calif., without considering the environmental impacts. As reported by Bloomberg: “U.S. Magistrate Judge Paul Grewal in San Jose, California, said the BLM violated the National Environmental Policy Act by relying on outdated reviews, conducted before the extraction process known as fracking spurred massive development of energy deposits, when the U.S. sold four leases in 2011 for 2,700 acres of federal land in Monterey and Fresno counties.”[94]

Santa Barbara County In June 2011, Los Alamos rancher and vineyard owner Steve Lyons contacted Santa Barbara county officials after discovering that  Venoco  had fracked a well on his property. After a series of public hearings and forums, the Santa Barbara County Board of Supervisors decided unanimously in December 2011 that companies planning to frack would have to apply for a special permit from the county planning commission.[95] Voters in Santa Barbara voted against a ballot measure in November 2014 that would have banned the practice of fracking in the county. The “no” vote constituted 63% of the total vote tally.[96][97]

Fracking in the USA 421 In December 2014, the Environmental Defense Center filed a lawsuit against the U.S. Department of the Interior. The suit claims that Environmental Defense Center and two of its subsidiary agencies “approved 51 permits to drill from oil and gas platforms in the Santa Barbara Channel without properly conducting environmental studies or permitting public comment.”[98]

San Benito In November 2014, voters in Santa Benito County banned the practice of fracking through a ballot initiative.[96]  San Benito voters passed the ban with 57% support. Oil companies spent $7.7 million to defeat fracking ban ballot measures in California in 2014, outspending opponents by nearly $7 million. The companies include Chevron Corp. and Occidental Petroleum. The spending was more than Neel Kashkari, a Republican running to be California’s governor spent on his campaign in 2014.[99][100][101] In February 2015, Citadel Exploration, based in Newport Beach, California, sued to block San Benito County’s voter-approved fracking ban in San Benito County Superior Court. Citadel claimed that local governments don’t have the authority to impose bans.[102]

Mendocino County In November 2014, 67% of voters in Mendocino County voted to ban the practice of fracking in the county.[103]

Monterey County After a Monterey county administrator approved a Venoco permit for nine exploratory wells using hydraulic fracturing, a local land trust appealed. The issue was set to be heard at an Oct. 26, 2011 planning commission meeting, but Venoco pulled its permit application after the commission released a meeting agenda noting that it recommended supporting the appeal and denying the project.[9]

Los Angeles County On May 15, 2012, Food & Water Watch joined with Gasland’s Josh Fox, Environment California, Citizens Coalition for a Safe Community,

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Grassroots Coalition, and residents of surrounding neighborhoods to call for a ban on fracking in California, presenting the signatures of 50,000 Californians who have signed petitions supporting a ban. The protest was held at the Inglewood Oil Field in Baldwin Hills, the largest urban oilfield in the nation that also sits atop a fault line capable of 7.4-magnitude earthquake.[104] On June 12, 2012, Food & Water Watch held a protest outside Culver City City Hall, demanding that fracking in Culver City and beyond be banned. In addition, a group called “Moms Against Fracking + Dads Too” was also meeting to participate in the protest event.[105] On February 20, 2013, a group of California residents yesterday denounced the state’s proposed rules on hydraulic fracturing of oil and gas. About 80 people who filled a hotel ballroom here rattled off what they saw as flaws with the draft regulations, including that the proposed rule fails to provide enough advance warning when fracking will occur and would not force public disclosure of all chemicals used.[106] Long Beach, California has employed fracking for the past 17 years. The city’s Department of Gas and Oil estimates less than 10 percent of wells involve the process. Long Beach averages five ‘fracs’ per year, all under the oversight of the state’s Department of Oil and Gas. Additionally no contamination has been detected in local groundwater supplies, which produce about 60 percent of Long Beach’s drinking water. This oil is being produced in the Wilmington field, near the Long Beach Oil Field.[107] In November 2014, residents of La Habra Heights, a town in Los Angeles County, succeed in qualifying a fracking ban for March 2015 ballot.[108] However, the measure was defeated in early March 2015 during the city election.[109] In December 2015, activists in the Los Angeles area called for a moratorium on fracking in California, arguing that during a drought a waterintensive activity such a fracking is not viable.[110]

Lawsuit Against the City of Los Angeles In November 2015, Youth for Environmental Justice and the South Central Youth Leadership Coalition filed an environmental justice lawsuit against the city of Los Angeles.[111] The lawsuit alleges that Los Angeles has a history of “rubber stamping” drilling applications, allowing oil operations to move through the permitting process without requiring the necessary environmental reviews dictated under California state law. According to the lawsuit, most of the

Fracking in the USA 423 drilling operations have ended up concentrated in and around low-income minority areas of South Los Angeles and Wilmington. It is alleged that the city allows noisy, high emission-polluting diesel run rigs at oil wells in South Los Angeles and Wilmington, while requiring cleaner-running electric rigs in high-income whiter areas on the Westside.

Demonstrators Disrupt DOGGR Workshop On March 24, 2015 activists disrupted a workshop held in Long Beach, California by Division of Oil, Gas and Geothermal Resources (DOGGR) on “aquifer exemption”. The activists offered DOGGR officials fracking  water and unrolled a banner which read, “Gov. Brown, Stop Letting Big  Oil Poison Our Water.” The activists were removed from the meeting.[112]

Group Attempts to Stop Long Beach Fracking Permits In late June 2015, in response to California’s Division of Oil, Gas and Geothermal Resources okaying permits for nine fracking operations off the coast of Long Beach, Center for Biological Diversity urged Gov. Jerry Brown these fracks, which would be the first in California waters since 2013.[113]

Long Beach On July 14, 2015 a group of anti-fracking activists in Long Beach gathered outside Long Beach City Hall to protest offshore fracking scheduled to take place in Long Beach Harbor. In July 2015, the California Department of Conservation’s Division of Oil, Gas and Geothermal Resources approved fracking of about a dozen wells operated by THUMS Long Beach, including five new operations. The fracks would be the first since 2013. Activists are concerned that drilling could result in an environmental disaster, such as an oil spill.[114] On October 7, 2015, anti-fracking activists marched through downtown Long Beach to call for an end to fracking offshore in the city’s waters. The activists called for a stop to the 13 new frack jobs of Long Beach’s oil islands that were approved earlier by the California Department of Conservation’s Division of Oil, Gas and Geothermal Resources.[115]

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In December 2015 the City of Long Beach cancelled its plans to frack 13 new wells on its offshore platforms. These fracks would have been the first new offshore fracks in the state since 2013.[47]

Culver City On July 2, 2012, the Culver City Council approved a resolution urging Gov.  Jerry Brown  and the California Department of Conservation›s Division of Oil, Gas & Geothermal Resources to impose a ban on hydraulic fracturing until regulations have been adopted ensuring the protection of public health, safety, and the environment. The council’s unanimous decision came a week before the completion of a  PXP fracking study at the Inglewood oil field.[116]

Orange County In Orange County, California activists are attempting to raise awareness and one day ban the practice of fracking. Activists in the city of Brea are concerned fracking may cause groundwater pollution as well as earthquakes from injection wells.[117]

Carson On January 26, 2015, California Resources Corp announced they would no longer seek approval for a large oil-drilling project in Carson, California. The company planned to drill 200 wells that was to initially employ the use of fracking. Local environmentalists had successfully lobbied the Carson City Council to pass a 45-day moratorium on new oil drilling in March 2014. California Resources Corp soon dropped their plans to frack, yet environmentalists continued to oppose the operation until it was abandoned.[118]

State level In February 2015, dozens of environmental groups filed a legal petition that asked California Gov. Jerry Brown (D) to ban hydraulic fracturing for oil and natural gas in the state. The petition was preceded by a rally in Oakland that was attended by 8,000 people that supported a ban.[119]

Fracking in the USA 425 Fracking studies In a Government Accountability Office report released in July 2014, the independent oversight agency reported the “EPA’s role in overseeing the nation’s 172,000 wells, which either dispose of oil and gas waste, use ‘enhanced’ oil and gas production techniques, store fossil fuels for later use, or use diesel fuel to frack for gas or oil. These wells are referred to as ‘class II’ underground injection wells and are regulated under the Safe Drinking Water Act. Oversight of these wells varies by state, with some coming under the regulatory authority of the EPA, including the 1,865 class II wells in Pennsylvania. The GAO faults the EPA for inconsistent on-site inspections and guidance that dates back to the 1980's. Of the more than 1800 class II wells in Pennsylvania, the GAO reports only 33 percent were inspected in 2012. Some states, including California, Colorado and North Dakota, require monthly reporting on injection pressure, volume and content of the fluid. As more oil and gas wells across the country generate more waste, the GAO highlights three new risks associated with these wells — earthquakes, high pressure in formations that may have reached their disposal limit, and fracking with diesel.”[120] Legislation

Regulations SB 4 - passed California’s Senate in 2013 and Assembly on September 11, 2013. Governor Brown signed the bill into law shortly after.[121][122] According to Earthworks, the bill means:[123] Frackers will now be required to report on water use and chemical use (with exceptions for “trade secrets”), and a permitting regime will come into place; Landowners, adjacent property owners, and tenants will be notified prior to fracking taking place; A plan for disposal of wastewater must be in place; and SB 4 is the first time that state will regulate acidizing and other forms of unconventional well stimulation for oil and gas. Yet the Natural Resources Defense Council, California League of Conservation Voters, Clean Water Action, and Environmental Working

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Group, which backed earlier versions of the measure, withdrew their support for the final bill, saying it was too watered down. Last-minute amendments to the bill included requiring state regulators to green-light all fracking requests by oil and gas companies in California until at least July 1, 2015 (when the state is scheduled to complete an environmental review of fracking in California), and allowing the head of DOGGR to rule whether the California Environmental Quality Act applies to oil and gas, mirroring the federal loophole that oil and gas gained from the National Environmental Policy Act.[124] According to Earthworks: “Over the past year, we watched SB 4 weaken – especially if the bill harms our ability to apply CEQA to oil and gas fracking and acidizing in the state.”[123] On July 1, 2015 the state of California finalized its regulations for SB 4, despite the fact its own fracking study was not yet completed. The study on fracking’s potential impacts was to be published on January 1, 2015, which prompted some in the environmental community to criticize Gov. Brown for passing a law that had not yet come under official environmental and health review.[125] On July 9, 2015, the California Council on Science and Technology (CCST) released its report on well-stimulation in California, which was pursuant to Senate Bill 4. CCST noted that, “The purpose of the report was to synthesize and assess the available scientific information associated with well stimulation treatments (WST) in California.”[126] The study noted that state agencies should ban the practice of reusing fracking wastewater for any purpose that could impact human health or the environment until further testing of its potential impacts could be done. The study also stated that thus far, no California agency had conducted a systematical study of the possible impacts from the reuse of fracking wastewater.[127]  The study also noted that there was lax oversight for fracking operations in California.[128]

Disclosure AB 591 - introduced by Assemblyman Bob Wieckowski (D-Fremont) in 2011 was originally touted as a way to require oil companies to disclose where they employ the fracking process, what chemicals they use, and how much water they pump. The lawmaker described it as a deliberately modest step. Among the chief opponents was Halliburton, who argued that full disclosure of the chemicals in its fracking fluid would compromise valuable trade secrets.

Fracking in the USA 427 According to the Los Angeles Times: “although Halliburton never registered as an official opponent, Halliburton and its lobbyists ran a quiet campaign to weaken the legislation, meeting privately with lawmakers and state agencies. During a committee hearing, lobbyist Terry McGann of the California Strategies firm, acknowledged that Halliburton does ‘want to protect the tens of millions of dollars in investments they’ve made for their particular hydrofracking fluid combination.’” The bill later stalled.[129] The amended version of the chemical disclosure bill,  AB 591, allows energy firms to withhold certain chemicals from public disclosure by filing a trade secret claim with state regulators.[130] It did not make it to the Senate for a full vote.[131] Additionally, concerns that the new provision to the bill could open the doors to “fracking before regulations are finalized, expected in 2015.” Some organizations that oppose the bill claim it could block Gov. Brown from instituting a moratorium on fracking before 2015.[132]

State and City Moratoriums AB 972 - the bill would Bar the supervisor from issuing a permit for an oil and gas well that will be hydraulically fractured until regulations governing its practice are adopted.” Passed by the Senate Environmental Quality Committee on July 2, 2012, but did not make it to the Senate for a full vote.[133] In May 2013 a trio of bills aiming to impose a moratorium on fracking in California were given the go-ahead from the state Assembly’s Appropriations Committee. It was reported, “Assemblyman Richard Bloom’s (D-Santa Monica) bill would put a moratorium on fracking and require legislative action to lift it, while Assemblywoman Holly Mitchell’s (D-Los Angeles) bill would only lift the moratorium after an independent commission studies the practice’s environmental effects. Assemblyman Adrin Nazarian’s (D-Van Nuys) bill only applies to the area surrounding sources of groundwater that could theoretically be contaminated by the release of fracking wastewater.”[134] Mitchell’s bill, AB 1323, was rejected by a 37-24 vote in late May 2013.[135] It was reported that ban’s proponents blamed lobbying by the oil industry, which spent nearly $1.5 million in three months fighting the bill.[136]

L.A. City Council On September 4, 2013 Los Angeles City Council members Paul Koretz and Mike Bonin introduced a motion to place a moratorium on fracking within

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the city of Los Angeles and along the city’s water supply route. According to EcoWatch, “They were joined outside beforehand by the consumer advocacy group Food & Water Watch, the environmental health group Physicians for Social Responsibly-Los Angeles, Citizens Coalition for a Safe Community (CCSC) and the Sierra Club to announce the motion at a press conference.”[137]

Beverly Hills Moratorium In early May 2014 Beverly Hills became the first California city to pass a fracking moratorium after a unanimous city council vote. Although Beverly Hills has no active fracking operations, the ban took effect on June 6, 2014.[138]

Compton Moratorium On April 15, the Compton City Council voted on enacting a moratorium on “fracking, acidizing, or any form of well-stimulation”. On July 21, the Western States Petroleum Association (“WSPA”) filed a lawsuit in an attempt to overturn Compton’s ban on fracking in L.A. County Superior Court. WSPA claims “such fracking bans are preempted by state regulation of well stimulation, Senate Bill 4 (“SB 4”) and the Division of Oil, Gas and Geothermal Resources’ (“DOGGR”) regulations. WSPA alleges several other legal grounds for the ordinance’s invalidity. The industry group claims that the city failed to give adequate notice of the ordinance, violating state and federal Constitutional due process guarantees. Additionally, the lack of public debate when passing the ordinance violated the City’s policy powers. Mineral rights holders were not given a forum for public input.”[139]

Santa Barbara County Moratorium Measure P, if passed by voters in the 2014, “would prohibit high intensity oil and gas production in unincorporated Santa Barbara County,” which includes fracking. Currently there are not reporting fracking operations taking place in Santa Barbara County. As of September 2014 opponents of Measure P “raised $1,950,000, while the Yes on P campaign has brought in a meager $95,000.””Santa Barbara County anti-fracking activists wildly outspent” CalCoastNews.com, September 23, 2014.

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Notification of Drilling SB1054, as amended (March 29, 2012), would require the drilling operator to file a written notice of intention to commence drilling, and submit to the Legislature an annual written report regarding the implementation of the notice requirement. The bill does not call for a public disclosure of the chemicals being used.[140] On May 30, 2012, the Senate defeated the legislation by a bipartisan vote of 17-18. According to Republican Senator Jean Fuller of Bakersfield: This bill would have resulted in the delay of gas and oil production in California.[141]

Water Use and the California Drought In April 2012, a bill regulating water use by oil producers cleared its first legislative test. The bill, authored by Assemblymember Mark Stone, would require companies to “disclose the source and amounts of water used in production, including fracking. It also demands they get approval from state water regulators on how the water would be disposed.” It passed the Assembly’s Natural Resources Committee on a 6-3, party-line vote.[142] In April 2015, Gov. Brown announced emergency water restrictions across California in an effort to battle the state’s severe drought. However, oil and gas companies were not forced to curtail water use in oil and gas operations, which included fracking.[143] Environmentalists were not pleased with Gov. Brown’s decision. “Governor Brown is forcing ordinary Californians to shoulder the burden of the drought by cutting their personal water use while giving the oil industry a continuing license to break the law and poison our water,” said Zack Malitz of environmental group Credo said to Reuters.[144] Regulations

Governor Brown Considers Fracking Standards As of 2012, California had no rules specific to fracking, although the California Division of Oil, Gas and Geothermal Resources (DOGGR) engineers approve fracking wells on a case-by-case basis. The Department of Conservation, DOGGR’s parent agency, has announced plans to contract an independent scientific study of hydraulic fracturing in California. Depending on the results of that study and input gathered at community

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workshops, the department may begin drafting fracking regulations in 2013.[145] In March 2012, California Governor Jerry Brown stated that his administration is looking into standards for fracking in the state. Brown stated that “California is the fourth-largest oil-producing state, and we want to continue that.”[21]  That month, the lower house›s subcommittee on resources tabled the Gov. Brown administration›s request for an additional 18 positions in the state›s oil and gas agency, saying that 35 positions and $3.2 million had already been approved in the last two years, in part to develop fracking regulations that have yet to be developed. The state›s nonpartisan legislative analyst reported that 13 of those slots remain vacant.[146] On May 9, 2012, the Assembly Subcommittee on Resources and Transportation approved Gov. Jerry Brown’s request for an additional 18 positions. Lawmakers also set guidelines for fracking rules, adopting budget language that gives regulators until 2014 to finalize regulations.[147]

Regulations Proposed In December 2012, CA Gov. Brown proposed regulations that would require energy companies to disclose their fracking plans to the state 10 days before starting operations. The companies also would be required to post to an online database - FracFocus - with the locations of their work and the chemicals used, and they would face new rules for testing and monitoring their wells. Critics said the rules would require only three days public notice of the fracking site before work begins, do not require notification of adjacent property owners, and do not include an appeals process for property owners who oppose the fracking work. The rules require for the first time that energy companies disclose the chemicals they are using, but the database for that information - FracFocus - is not subject to public records laws. And companies may claim “trade secrets” exemptions to withhold the names of the chemicals they inject.[148] The proposed rules were released in December 2013.[149]

Well Classification Type In 1983, the EPA granted the California Division of Oil, Gas and Geothermal Resources (DOGGR) “primacy,” or primary authority, for regulating what

Fracking in the USA 431 are known as Class II injection wells -- including wells in which operators inject fluid deep into the earth to enhance oil recovery or to dispose of fluid wastes associated with oil and gas production (disposal wells). Class II injections wells use well injecting fluid associated with the production of oil and gas. Congress in 2005 exempted fracking from the Safe Drinking Water Act, putting the responsibility on states.[150] In 2011, the EPA evaluated how the California state agency “oversees and manages the permitting, drilling, operation, maintenance and plugging/abandonment of Class II [underground injection wells].” The federal regulators found that the California agency’s program did not meet a number of federal requirements, and in July 2011, sent a letter to the division highlighting a variety of “program deficiencies that require more immediate attention and resolution.”[151] According to the state Department of Conservation (DOC), DOGGR has regulations in place for enhanced oil recovery (EOR) utilizing steam flood and water flood injection through its Underground Injection Control (UIC) program, and “any alternative methods for EOR – such as hydraulic fracturing -- would require additional regulations and/or statutes.” In some locales, environmental groups have made a push that fracking should be considered as “injection,” and the well that is being fractured should be considered as a UIC Class II injection well. Other state regulators in the oil and gas arena have countered that hydraulic fracturing should be considered a “well treatment” not subject to UIC. If hydraulic fracturing were considered as UIC, it would bring in a host of review and testing requirements along with oversight by USEPA:[152] the DOC states that injection project permits often include conditions, such as approved injection zones, allowable injection pressures, and testing requirements. State regulations were designed to ensure that injected fluids are confined to the project area and zone, and that formation pressures are not exceeded to the extent that damage occurs.[153] According to the California Independent Petroleum Association, fracking is not a Class II well, and fracking is indirectly regulated by the state’s regulation of non-disposal drilling wells.[154]

Public Disclosure On March 28, 2012, the California Division of Oil, Gas and Geothermal Resources sent letters asking California’s oil producers, on a voluntary basis, to post records of their fracking activity to FracFocus.[155]  In May 2012, the oil industry group Western States Petroleum Association said

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its members that use fracking to extract oil will voluntarily post information about their operations on the industry website, likely by the end of June 2012.[156] Rules proposed in December 2012 would make that posting mandatory, although the information is not be subject to public records laws, and companies could claim trade secrets exemptions to withhold the names of the chemicals they inject.[157]

Study on Hazards In August 2013, the U.S. Bureau of Land Management reported that it would launch California’s first statewide study of fracking and its potential hazards.[158] Lobbying As of 2012, the oil and natural gas industry spends more than $4 million a year lobbying the California legislature.[159] The Western States Petroleum Association spent the most on lobbying in Sacramento in the first six months of 2013 of any interest group, spending over $2.3 million in the first two quarters, according to quarterly documents released by the California Secretary of State. All but one bill to regulate or ban fracking was defeated in the Legislature in 2013.[160] A March 2013 study by USC and the Communications Institute, a Los Angeles think tank, estimated that development of the Monterey Shale could generate half a million new jobs by 2015 and 2.8 million by 2020, and boost the state’s economy by 14 percent. As reported in DeSmogBlog: “the report acknowledges financial support - though failing to disclose how much funding - from the Western States Petroleum Association (WSPA) and one of the co-authors of the ‹study› - Fred Aminzadeh - is currently an oil and gas industry employee. Aminzadeh is founder and President of global oil and gas industry consultancy firm FACT-Corp. and on the Advisory Board of both Western Standard Energy Corp. and Saratoga Resources.[161]

EWG The 2012 Environmental Working Group report,  “California regulators: See no fracking, speak no fracking,” examines the issue of fracking, oil and gas, and regulations in the state and recommends that:[9]

Fracking in the USA 433 1. The Division of Oil and Gas date its fact sheet to acknowledge that fracking is currently taking place in California and has been for decades. 2. The Division should identify and track where fracking is taking place and post the information on a state-run website. 3. California state agencies should develop regulations that require oil and gas companies to disclose what chemicals they are using to frack each well (with volume and concentrations), the amount of water used, the source of the water, and whether any radioactive tracers are being used, to allow regulators, scientists and landowners to learn what substances to test for in nearby water supplies. 4. Landowners within at least two miles of proposed drilling or fracking operations should be notified and given an opportunity to weigh in on permit decisions. 5. Oil and gas companies should be required to pay for testing and monitoring of nearby groundwater before and after drilling and fracking by independent laboratories selected by potentially affected landowner, similar to an EPA recommendation to New York State authorities. 6. Water recycling should be mandatory for oil and gas operations. 7. Drilling and fracking should not be allowed close to residential areas or drinking water sources, to prevent risks.

EWG Wastewater In 2015, the Environmental Working Group (EWG) published “TOXIC STEW: What’s in Fracking Wastewater,” which responded to the first year of California’s fracking disclosure program created by State Senator Fran Pavely’s bill Senate Bill 4 in 2014.[162]  Hazardous chemicals as  benzene, formaldehyde, toluene, chromium-6, and arsenic, and metals as lead, and radiation were found wastewater. Some detected at average levels that according to the EWG are hundreds or thousands of times higher than the state’s drinking water standards or public health goals. Since December 2013 to the publication of the EWG report in 20105, drillers in California reported using more than 200 different chemicals in hydraulic fracturing fluids. They include neurotoxins and known carcinogens identified on California’s Proposition 65 list.

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Benzene in wastewater was of particular concern to EWG report. One of the 293 samples tested contained benzene at levels ranging from twice to more than 7,000 times the state drinking water standard. EWG analyzed all available state records of wastewater samples from wells fracked and acidizing well stimulation in 2014.

DOGGR Well Injection In October 2015, DOGGR, under the Department of Conservation, released a well injection report heavily criticizing their own well injection program. The report charged that the agency oversight of wastewater injection wells failed because of inadequate recordkeeping, lack of regulators, inconsistent enforcement, inaccurate permitting and poor monitoring. For 32 years, state officials permitted drillers to pump leftover wastewater back into the ground, on the assumption that federal officials had granted exemptions from laws that protect groundwater aquifers from contamination. The US Environmental Protection Agency claims no exemptions were granted.[163] The agency charged that their own well records were often incomplete or missing. Approximately 47% of the files did not contain enough information about well casings.[164] Seventy-eight percent of the projects did not undergo a required geologic and technical analysis. Only five projects had undergone this analysis from 2010 to 2015.[165] Resources

References 1. Michael J. Mishak,  Oil extraction method widely used in California with little oversight,  Los Angeles Times, Mar. 14, 2012. 2. Stephen Stock, Liza Meak, and Mark Villarreal, “California’s Controversial Oil Drilling,” NBC Bay Area, Apr. 27, 2012. 3. John Cox, Oil companies agree to post fracking data, Bakersfield.com, May 15, 2012. 4. Amy Harder, California›s Top Oil Regulator on Fracking, Climate Change, and Fossil Fuels, Oct. 16, 2013. 5. Rory Carroll and Braden Reddall, Insight: California environmentalists fear frack fight a distraction, Reuters, May 28, 2013.

Fracking in the USA 435 6. Jeremy B. White, “Study: California using fracking in up to half of new wells,” Sacramento Bee, Jan. 1, 2015. 7. El Shaari, N., W.A. Miner,  Northern California Gas Sands - Hydraulic Fracture Stimulation Opportunities and Challenges, SPE Western Regional and Pacific Section AAPG Joint Meeting, Bakersfield, CA Mar. 31-Apr. 2, 2008. 8. Michael J. Mishak, “Gov. Jerry Brown says he’s studying ‘fracking’ in California,” Los Angeles Times, Mar. 23, 2012. 9. Renée Sharp and Bill Allayaud, California regulators: See no fracking, speak no fracking, Environmental Working Group, FebruaryFeb. 2012. 10. Fracking in California: Questions and Answers  Center for Biological Diversity 11. Evan Halper, “Californians uneasy about fracking’s safety, lack of oversight,” Los Angeles Times, Jun. 7, 2013. 12. Most Californians want fracking regulated, Central Valley Business Times, Sept. 25, 2013. 13. Bill McKibben  (8 Mar. 2012). “Why Not Frack?”.  The New York Review of Books 59 (4). Retrieved on 21 Feb. 2012. 14. Tony Z., The Oil Industry›s California Takeover, Daily Kos, Mar. 1, 2012. 15. Michael J. Mishak,  State officials ask energy firms to disclose ‹fracking› sites, Los Angeles Times, Apr. 2, 2012. 16. Monterey Shale California Oil & Natural Gas, accessed Apr. 25, 2012. 17. Dave Roberts, 10 reasons why fracking for dirty oil in California is a stupid idea, Grist, Mar. 18, 2013. 18. Monterey Shale - California›s Sleeping Giant? Rhonda Duey, E&P, Jun. 1, 2011. 19. Dave Roberts, 10 reasons why fracking for dirty oil in California is a stupid idea, Grist, Mar. 18, 2013. 20. Jason Raznick,Four ETFs For The Monterey Shale, Forbes, Oct. 21, 2011. 21. California’s Brown Says He’ll Consider Fracking Standards,  James Nash, Business Week, Mar. 23, 2012. 22. Norimitsu Onishi, “Vast Oil Reserve May Now Be Within Reach, and Battle Heats,” New York Times, Feb. 3, 2013. 23. U.S. officials cut estimate of recoverable Monterey Shale oil by 96%,  Los Angeles Times, May 20, 2014. 24. Ellen Knickermeyer, “Study: No fracking bonanza for California’s Monterey Shale,” Associated Press, Oct. 8, 2015. 25. J. David Hughes,  Drilling California: A Reality Check on the Monterey Shale, PCI Report, Dec. 2, 2013. 26. Spike in California Gas Drilling in California, State of California Department of Conservation, Sept. 10, 2011. 27. Julie Cart,  Fracking in Los Angeles? Oil well oversight in L.A. Basin is inconsistent, audit finds, Los Angeles Times, Oct. 8, 2015. 28. Ngoc Nguyen, Fracking in Los Angeles? Test Wells at Urban Oil Field Spark Water Worries, Inside ClimateNews, Apr. 13, 2012.

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29. Could Fracking in Los Angeles Cause an Earthquake?  Tessa Stuart, LA Weekly, May 17, 2012. 30. Steve Horn,  Frackademia: Controversial SUNY Buffalo Shale Institute›s Reputation Unraveling, DeSmogBlog, Oct. 11, 2012. 31. Alicia Chang, Jason Dearen, “Calif. finds more instances of offshore fracking,” Yahoo! Finance, Oct. 19, 2013. 32. Joshua Frank, “What the Frack Is Happening Under Long Beach?”  OC Weekly, Apr. 22, 2015. 33. Environmentalists want California to stop offshore fracking, Associated Press, Jun. 30, 2015. 34. Heather Kathryn Ross,  One California County›s Fracked Idea, Dec. 09, 2015. 35. John Cox, Fracking data flows from Kern oil fields, Bakersfield.com, Apr. 16 2012. 36. John Cox, Oil companies agree to post fracking data, Bakersfield.com, May 15, 2012. 37. Jonathan Thompson, NASA finds methane hot spot over Four Corners, The culprit is the extensive fossil fuel industry infrastructure, not just fracking or coal mines, High Country News, Oct. 12, 2014. 38. James Burger and John Cox,  Supervisors approve hard-fought oil and gas plan, The Bakersfield Californian, Nov. 9, 2015. 39. Erich Schwartzel and Andrew McGill,  With gas firms entering central California, vineyard owners unsure of fracking effects on land, Pipeline, Oct. 7, 2012. 40. Erich Schwartzel and Andrew McGill, Anti-fracking initiative in the works for Monterey County, KSBW.com, Feb. 04, 2016. 41. Natalie Cherot, “Hooked on Frack? Where Oil Companies Could Be Fracking in Santa Barbara County,”  Santa Barbara Independent, Nov. 15, 2012. 42. Zach Swim and Dina Rasor,  Lack of State and Federal Oversight of Offshore Fracking Could Imperil the Santa Barbara Coastline, Truthout, Oct. 3, 2012. 43. Mike Ludwig, Special Investigation: Fracking in the Ocean Off the California Coast, Truthout, Jul. 25, 2013. 44. Mark Denin and Shiva Polefka, Fracking Goes To Sea: California Regulators Startled To Learn Of Offshore Hydraulic Fracturing, Climate Progress, Oct 24, 2013. 45. Dirty Water: Fracking Offshore California, Environmental Defense Center, 2013. 46. For Calif. officials, offshore fracking flew under the radar, E&E News, Oct. 22, 2013. 47. Kristen Monsell, Lawsuit Prompts Offshore Fracking Moratorium Off California Coast, Center for Biological Diversity, Jan. 29, 2016. 48. Pipeline Owner in Santa Barbara Oil Spill Has Had 175 Spill Incidents Since 2006, Center for Biological Diversity, May 21, 2015.

Fracking in the USA 437 49. Kelsey Brugger, “Refugio Reviewed Did We Learn Our Lesson on Pipeline Safety?” Santa Barbara Independent, Dec. 24, 2015. 50. Lena Garcia, “More Details on Ocean Fracking Revealed as Environmentalists Challenge Federal Regulators,” Santa Barbara Independent, Sept. 15, 2015. 51. Lena Garcia, “More Details on Ocean Fracking Revealed as Environmentalists Challenge Federal Regulators,” Santa Barbara Independent, Sept. 15, 2015. 52. Kelsey Brugger, “PHMSA Releases Detailed Findings on Oil Spill,” Santa Barbara Independent, Feb. 19, 2016. 53. Gina Potthoff, “More Details on Ocean Fracking Revealed as Environmentalists Challenge Federal Regulators,” Noozhawk, Feb. 17, 2016. 54. Natalie Cherot, Amid Farmland, an Oil Field, Earth Island Journal, Spring 2015. 55. Seema Mehta and Louis Sahagun, L.A. County leaders oppose plan to drill for oil in Whittier hills, Los Angeles Times, Oct. 29, 2013. 56. Alison Sider & Cassandra Sweet, “California Finally to Reap Fracking’s Riches,” Wall Street Journal, Oct. 7, 2014. 57. Natalie Cherot, “SLO Refinery Wants Oil by Train Phillips 66 Runs into Public Resistance over Proposal to Lay New Tracks and Unload More Canadian Crude,” The Santa Barbara Independent, Jan. 23, 2015. 58. Nearly half of fracking happens in places short on water,  SF Gate, May 2, 2013. 59. 2010 Annual Report Information, DOGGR 2010 Annual Report. 60. Neela Banerjee, “Limited water presents challenge for natural gas fracking” Los Angeles Times, Sept. 2, 2014. 61. Rory Carrol, “Exclusive: California used 70 million gallons of water in fracking in 2014,” Reuters, Apr. 3, 2015. 62. Oil, Gas and Fracking in California, Clean Water Action, accessed Aug. 1, 2014. 63. Analysis of California’s Fracking Wastewater Reveals a Slew of Toxic Chemicals Linked to Cancer and Other Illnesses, EcoWatch, Mar. 10, 2015. 64. Jeremy Miller,  The Colonization of Kern County: A story of oil and water, Orion Magazine, Jan./Feb. 2011 issue. 65. Abrahm Lustgarten,  Injection Wells: The Poison Beneath Us, ProPublica, Jun. 21, 2012. 66. Confirmed: California Aquifers Contaminated With Billions Of Gallons of Fracking Wastewater Mike G, DeSmogBlog, Oct. 7, 2014. 67. High levels of benzene found in fracking waste water Julie Cart, Los Angeles Times, Feb. 11, 2015. 68. Tasha Stoiber and Bill Walker,  “TOXIC STEW What’s in Fracking Wastewater,” EWG.org, Mar. 10, 2015. 69. Tasha Stoiber and Bill Walker,  TOXIC STEW What’s in Fracking Wastewater, EWG.org, Mar. 10, 2015.

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70. Julie Cart, “Hundreds of illicit oil wastewater pits found in Kern County,” Los Angeles Times, Feb. 26, 2015. 71. Dennis Romero, “Fracking-affected Food Should be Labeled, Lawmaker Says,” LA Weekly, Aug. 17, 2015. 72. Oil, Gas & Geothermal - Injection Wells, CA DOC Website, accessed May 2012. 73. California Halts Injection of Fracking Waste, Warning it May Be Contaminating Aquifers, Mother Jones, Jul. 22, 2014. 74. CALIF. DIVISION OF OIL, GAS, AND GEOTHERMAL RESOURCES SEEKS END TO INJECTION IN 12 KERN COUNTY WELLS  Dept. of Conservation, Mar. 3, 2015. 75. Julie Cart, Fracking in Los Angeles? Oil well oversight in L.A. Basin is ‹inconsistent,› audit finds, Los Angeles Times, Oct. 8, 2015. 76. David R. Baker, “State shuts 33 wells injecting oil wastewater into aquifers,” Oct. 16, 2015. 77. Does living near an oil or natural gas well affect your drinking water?, Phys. org, Feb. 14, 2016. 78. Scott Thrill,  California’s unregulated fracking problem, AlterNet, Apr. 9, 2012. 79. ODNR Releases Preliminary Report on Youngstown Area Seismic Activity, ODNR, Mar. 9, 2012. 80. USGS,  Are Seismicity Rate Changes in the Midcontinent Natural or Manmade? USGS 2012 Report. 81. T. H. W. Goebel, S. M. Hosseini, F. Cappa, E. Hauksson, J. P. Ampuero, F. Aminzadeh, J. B. Saleeby, Wastewater disposal and earthquake swarm activity at the southern end of the Central Valley, California, Geophysics Research Letters, Feb. 2016. 82. Abrahm Lustgarten, Poisoning the Well: How the Feds Let Industry Pollute the Nation’s Underground Water Supply, ProPublica, Dec. 11, 2012. 83. A California Gas Leak Is the Biggest Environmental Disaster Since the BP Oil Spill, Gizmodo, Dec. 28, 2015. 84. Brown declares state of emergency at Porter Ranch amid massive gas leak Alice Walton and John Myers, Los Angeles Times, Jan. 6, 2015. 85. Robert Collier, A New California Oil Boom? Drilling the Monterey Shale Part 1: Distracted by Fracking? The Next Generation, Aug. 2013. 86. RL Miller, Why Oil Companies Want to Drop Acid in California, Take Part, Sept. 2, 2013. 87. Natalie Cherot, Amid Farmland, an Oil Field, Earth Island Journal, Spring 2015. 88. John Cox,  Fracking data flows from Kern oil fields,  The Bakersfield Californian, Apr. 16, 2012. 89. John Cox,  Oil industry frets over sinkhole controversy,  The Bakersfield Californian, Oct 3, 2011.

Fracking in the USA 439 90. Environmental groups sue California regulator over fracking, Reuters, Oct. 16, 2012. 91. Brown Administration Sued for Ignoring Risk Report on Fracking, Center for Biological Diversity, Jul. 30, 2015. 92. Michael J. Mishak,  Oil extraction method widely used in California with little oversight, Los Angeles Times, Mar. 14, 2012. 93. Environmental groups sue to prevent fracking in Calif. Tia Ghose, California Watch, Dec. 19, 2011. 94. Karen Gullo, “First California Fracking Challenge Is Defeat for U.S.” Bloomberg, Apr. 8, 2013. 95. Cooley, M., County-level ‘fracking’ rules get board OK, Santa Maria Times, Dec. 7, 2010. 96. Not Just a Fracking Ban National Review Online, Oct. 23, 2014. 97. Molly Peterson, “Fracking bans pass in 2 counties, fail in Santa Barbara,” KPCC, Nov. 5, 2014. 98. Feds Sued Over Santa Barbara Fracking Permits, ABC News, Dec. 3, 2014. 99. David R. Baker, “To fight fracking bans, oil firms heavily outspend environmentalists,” SF Gate, Nov. 2, 2014. 100. Timothy Cama, “Oil, gas industries fight local anti-fracking measures,” Nov. 13, 2014. 101. CAMPAIGN 2014: Measure J moves forward in San Benito County, Kion, Nov. 5, 2014. 102. Paul Rogers, “Fracking: Oil company sues to overturn San Benito County fracking ban; could affect other counties,”  San Jose Mercury News, Mar. 3, 2015. 103. Bob Downing,  Mendocino County is first California community to enact ban, Akron Beacon Journal, Nov. 5, 2014. 104. Citizens Groups Calling for a Ban on Fracking in California, Food & Water Watch, May 15, 2012. 105. Crystal C. Alexander, “Culver City Moms (and Dads) Unite Against Fracking”  Culver City Patch, Jun. 11, 2012. 106. Calif. walloped with criticisms on proposed fracking rules, Energywire, Feb. 20, 2013. 107. Kristopher Hanson, “Cal Assembly bill seeks to force disclosure of chemicals used in drilling wells,” Press-Telegram, Jun. 28, 2011. 108. Mike Sprague, “La Habra Heights anti-oil initiative qualifies for 2015 ballot” Whittier Daily News, Nov. 3, 2014. 109. Mike Spraugue, “Election 2015: La Habra Heights anti-oil initiative loses,” Whittier Daily News, Mar. 3, 2015. 110. ‘Fracking’ Opponents Renew Calls For Moratorium Amid Drought, CBS Los Angeles, Aug. 13, 2015. 111. Alex Dobuzinskis, “Los Angeles sued over oil well hazards faced by minorities,” Reuters, Nov. 6, 2015.

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112. Lauren Steiner, “Fractivists Bust Aquifer Exemption Workshop,” CounterPunch, Mar. 30, 2015. 113. Just Weeks After Oil Spill, California Officials OK Nine New Offshore Fracks, Center for Biological Diversity, Jun. 30, 2015. 114. Stephanie Rivera, “Environmental Activists Protest Scheduled Fracking in Long Beach,” Long Beach Post, Jul. 15, 2015. 115. Stephanie Rivera, “Environmental Activists Call for End to Fracking Plans at Long Beach Harbor,” Long Beach Post, Oct. 7, 2015. 116. Culver City Council calls on state to ban fracking temporarily, Los Angeles Times, Jul. 3, 2012. 117. Aaron Orlowski, “When it comes to fracking, fracktivist residents see red, not black gold,” Orange County Register, Oct. 13, 2014. 118. Rory Carroll, “California Resources Corp pulls plug on oil drilling project,” Reuters, Jan. 26, 2015 119. Timothy Cama, “Greens petition California to ban fracking,” The Hill, Feb. 26, 2015. 120. Congressional Watch-Dog Warns Fracking Waste Could Threaten Drinking Water, StateImpact, Pennsylvania, Jul. 18, 2014. 121. Capitol Alert: Fracking bill passes California Assembly, The Tribune, Sept. 11, 2013. 122. Jayni Hein, “State Releases New Fracking Regulations Amid SB 4 Criticism, Controversy,” Legal Plane, Nov. 18, 2013. 123. Jennifer Krill,  California Comes out of the Fracking Closet,  Earthworks, Sept. 12, 2013. 124. Robert Gammon,  Lawmakers Should Reject Fracking Bill SB4,  East Bay Express, Sept. 11, 2013. 125. California OKs Fracking Regulations Before Scientists Finish Studying Risks Center for Biological Diversity, Jul. 1, 2015. 126. SB4, CCST Well Stimulation Project, Jul. 9, 2015. 127. Samantha Page, “California Has No Idea What’s In Its Fracking Chemicals, Study Finds,” Climate Progress, Jul. 11, 2015. 128. Amy Quinton, “California Lawmakers Say Fracking Study Shows Lax Oversight,” Central Public Radio, Aug. 25, 2015. 129. Michael J. Mishak,  Oil extraction method widely used in California with little oversight, Los Angeles Times, Mar. 14, 2012. 130. Michael J. Mishak,  California fracking bill would protect industry ‘trade secrets,’ Los Angeles Times, Apr. 18, 2012. 131. Ellen M. Gilmer, Fracking bills derailed in committee, E&E News, Aug. 17, 2012. 132. Trisha Marczak, “Fracking Industry Eyes An Already Water-Starved California,” Mint Press News, Sept. 11, 2013. 133. Ellen M. Gilmer, Fracking bills derailed in committee, E&E News, Aug. 17, 2012.

Fracking in the USA 441 134. Aaron Sankin, “California Fracking Ban: Golden State Moratorium On Controversial Practice Moves Forward,” Huffington Post, May 17, 2013. 135. John Upton, “California, Illinois lawmakers welcome frackers,” Grist, Jun. 3, 2013. 136. Fracking moratorium fails in California despite strong public support, RT. com, May 30, 2014. 137. L.A. City Councilmembers Call for Fracking Moratorium, EcoWatch, Sept. 5, 2013. 138. Beverly Hills becomes first in California to ban fracking, Reuters, May 7, 2014. 139. Industry Group Sues Compton for Moratorium on Hydraulic Fracturing, California Environmental Blog, Jul. 25, 2014. 140. Loretta Red, Fracking, SB View, Apr. 10, 2012. 141. Jim Magill, California Senate votes down fracking notification bill, Platts, May 31, 2012. 142. Jason Hoppin, “California bill would target fracking industry’s water use,” Mercury News, Apr. 16, 2013. 143. Mike Gaworecki, “California Urban Water Use Restricted While Regulators Give Oil Industry Two More Years To Operate Injection Wells In Protected Groundwater Aquifers,” DeSmogBlog, Apr. 8, 2015. 144. California water restrictions should cover oil companies, activists say, Russia Today, Apr. 3, 2015. 145. John Cox, Oil companies agree to post fracking data, Bakersfield.com, May 15, 2012. 146. Michael J. Mishak,  State officials ask energy firms to disclose ‹fracking› sites, Los Angeles Times, Apr. 2, 2012. 147. Michael J. Mishak, California lawmakers push for fracking rules, Los Angeles Times, May 9, 2012. 148. Paul Rogers,  California releases first-ever fracking regulations,  Mercury News, Dec. 18, 2012. 149. Michael J. Mishak, Lawmakers want tougher rules for fracking, Los Angeles Times, Feb. 13, 2013. 150. Division of Oil, Gas and Geothermal Resources, Department of Conservation, UIC Application Guidance, accessed Apr. 2012. 151. Albright, D., Groundwater Protection Office, US Environmental Protection Agency, Letter to Elena Miller, State Oil and Gas Supervisor, Division of Oil, Gas & Geothermal Resources, Jul. 18, 2011. 152. Fact sheet: Hydraulic Fracturing, CA DOC, accessed May 2012. 153. Hydraulic Fracturing, CA DOC, accessed May 2012. 154. Response to EWG on Hydraulic Fracturing,  California Independent Petroleum Association 2012 Report. 155. John Cox, Oil companies agree to post fracking data, Bakersfield.com, May 15, 2012.

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156. Oil industry says it will report California ‹fracking› information, David Siders, The Sacramento Bee, May 16, 2012. 157. Paul Rogers,  California releases first-ever fracking regulations,  Mercury News, Dec. 18, 2012. 158. David Baker, U.S. to start first California study of fracking, SF Chronicle, Aug 3, 2013. 159. Michael Hiltzik, Let›s close the information gap about fracking, Los Angeles Times, Jun. 10, 2012. 160. Dan Bacher, The Ocean Frackers, Counterpunch, Aug. 7, 2013. 161. Steve Horn, “”Frackademia” Strikes Again at USC with “Powering California” Study Release,” DeSmogBlog, Mar. 14, 2013. 162. Tasha Stoiber and Bill Walker,  TOXIC STEW What’s in Fracking Wastewater, EWG.org, Mar. 10, 2015. 163. Molly Petterson, “Oil and gas regulators admit to massive oversight failures in new report,”  Oct. 8, 2015. 164. Julie Cart,  Fracking in Los Angeles? Oil well oversight in L.A. Basin is ‹inconsistent,› audit finds, Los Angeles Times, Oct. 8, 2015. 165. Julie Cart,  Fracking in Los Angeles? Oil well oversight in L.A. Basin is ‹inconsistent,› audit finds, Los Angeles Times, Oct. 8, 2015.

Colorado The number of active oil and gas wells in Colorado almost doubled from 22,228 in 2000 to 43,354 in 2010. Analysts believe there is more oil shale and shale gas to be found in the state.[1]Pushing the lease growth is the discovery of oil in the Niobrara shale, which sits more than 6,000 feet below the Front Range of the Rocky Mountains. The oil is not uniformly distributed in the vast shale and limestone formation, which stretches from southern Colorado into Wyoming.[2]As of 2015, Colorado had 3,485 oil and gas operators.[3] According to the Bureau of Land Management (BLM), 95 percent of new wells in Colorado use fracking to access the natural gas. The BLM states that, in Colorado, the majority of fluids used in the fracturing process are recycled and no fluids are sent to wastewater treatment plants, which has caused water quality concerns in the eastern United States. For the fluids disposed of, the BLM states that 60 percent goes into “deep and closely-regulated” waste injection wells, 20 percent “evaporates from lined pits” and 20 percent is “discharged as usable surface water” under permits from the Colorado Water Quality Control Commission.[4] The Bureau of Labor Statistics and U.S. Bureau of Economic Analysis said in 2009 that the natural gas industry represented 7.3% of Colorado’s economy.

Fracking in the USA 443 [5]

 According to industry data, at least 430 million gallons of chemical-laced fluids have been injected into more than 9,000 oil and gas wells in the state, mostly along the northern Front Range and the Western Slope.[6] Colorado Governor John Hickenlooper (D) is a former petroleum geologist for Buckhorn Petroleum. Hickenlooper took $75,000 from oil and gas interests in his 2010 election, and appointed an industry campaign donor to an important regulatory position. He has appeared in industry-funded ads in newspapers and on radio stations across the state, proclaiming that no water in Colorado had been contaminated by fracking, and has said that fracking fluids are edible.[7] Drilling wells Western Voices -- North Fork Valley Gas and oil leases in six Colorado counties — Larimer, Weld, Arapahoe, Douglas, Elbert and El Paso — more than doubled between 2008 and 2011, with 8,100 leases filed from August 2010 to August 2011, according to county records. Leases were granted to 40 different companies. If Weld County, a traditional oil and gas area, is removed, leasing activity jumped to 2,700 leases in 2010-2011, from 117 in the same period in 200809. According to The Denver Post, “Propelling the rush is the discovery of oil in the Niobrara — a geological formation sitting more than 6,000 feet below the Front Range.”[2]

Proposed Projects Location of gas leases in the Niobrara formation in Wyoming and Colorado. In August 2012, about 30,000 acres will be put up for lease for oil & gas drilling near the North Fork Valley communities of Hotchkiss, Paonia, and Crawford, Colorado. The Bureau of Land Management released a March 2012 Draft Preliminary Environmental Assessment and announced a Finding of No Significant Impact. The finding was based on two old guidance documents: a 1989 Resource Management Plan and a 1987 Report on Oil & Gas. Critics say oil and gas has changed a lot over the years, particularly the growth of fracking, and more is known today about possible health risks, with BLM currently working on new guidance documents. They say a detailed Environmental Impact Statement is needed for the decision, particularly since the parcels being considered are near Paonia Reservoir, Fire Mountain Canal, Cottonwood Creek and other critical waterways.[8]

444

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The 2010 top Drillers and Number of Permits in Colorado The top drillers and number of permits in Colorado for the 12-month period ending August 30, 2011:[2]

Weld County Mineral Resources: 1,018 EOG Resources: 594 Diamond Resources: 483

Larimer County Marathon Oil: 50 Strata Oil & Gas: 45 Prospect Energy: 44

Arapahoe County GFL & Associates: 137 Chesapeake Exploration: 82 stream Innovations: 56

Douglas County Chesapeake Exploration: 103 Meredith Land & Minerals: 55 Great Western Oil & Gas: 16

Elbert County Chesapeake Exploration: 411 ConocoPhillips: 162 Continental Land Resources: 155

El Paso County Transcontinent Oil: 138 Continental Land Resources: 110 Simmons-McCartney: 94

Gothic Shale Bill Barrett Corporation has drilled and completed several gas wells in Colorado’s section of the Gothic shale. The wells are in Montezuma County, Colorado, in the southeast part of the Paradox basin. A horizontal well in the Gothic flowed 5,700 MCF per day.[9]

Niobrara Shale The  Niobrara shale  is a shale rock formation located in Northeast Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil as well as natural gas can be found deep below the earth›s surface at depths of 3,000 - 14,000 feet. Fracking is used to extract these natural resources.

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The Niobrara Shale is located in the Denver–Julesburg basin which is often referred to as the DJ Basin. This oil shale play is being compared to North Dakota’s Bakken formation. Oil & Gas companies are quickly leasing land in the core zones located in Weld County Colorado, Yuma County Colorado, and even Cheyenne, Kansas.[10]

Public Lands The Colorado Independent reported in 2015 Colorado BLM conducts oil and gas lease sales four times per year.[11] The Colorado Bureau of Land Management plans to auction off 12,000 acres of public lands for oil and gas drilling in November 2013. Most of the acres are located less than ten miles from the state park of Mesa Verde.[12] In November 2015, the Bureau of Land Management office put up for auction 90,000 acres of mineral rights for drilling. Much of the land was within the Pawnee National Grassland. Buyers had purchased 93 percent. The average bid was less than $60 per acre. The sale made $5,021,931.[13] Injection wells

Earthquakes Colorado has about 305 disposal wells and two or three sets of earthquakes in the state have been linked to injection wells, although none definitively since the early 2000s. One of the earliest known cases of “induced seismicity” from wastewater injection occurred at the Rocky Mountain Arsenal in 1966, linked to a well designed to dispose of tainted water from the chemical weapons site. More recently, a series of small earthquakes near Trinidad may have been related to drilling injection wells.[14] In 2011, the oil and gas commission began requiring a site review by the Colorado Geological Survey to look for proximity to known faults before permitting injection wells. The commission also limits the injection pressures for the wells to prevent fractures and limits the total volume of wastewater pumped down the wells.[14] The U.S. Geological Survey linked a 2011, 5.3-magnitude earthquake near New Mexico to hydraulic fracturing and wastewater disposal. The U.S. Geological Survey has warned that earthquakes are 100 times more likely to occur now than in 2008 in fracking and wastewater disposal areas.[15]

Fracking in the USA 447 In April 2013, it was reported that an ongoing earthquake swarm in New Mexico and Colorado, which includes Colorado’s largest earthquake since 1967, was due to underground wastewater injection, researchers said at the Seismological Society of America’s annual meeting in Salt Lake City. The reported earthquakes are concentrated near wastewater injection wells in the Raton Basin. Companies there have been extracting methane from underground coalbeds. The basin stretches from northeastern New Mexico to southern Colorado.[16] In Greeley, Colorado, June 2014 researchers installed several seismometers nearby a recent earthquake. Seismometers identified the injection well that caused the quake. About 300,000 barrels a month were injected into the well. The wastewater injection was still causing tremors. Colorado regulators temporarily shut down the well and lowered its rate of injection.[17] The state assembly began 2016 by discussing a proposal to hold oil and gas companies liable for earthquakes.[18]

Waste Exemptions A 2012 ProPublica  investigation  into the threat to water supplies from underground injection of waste found the EPA has granted energy and mining companies exemptions to release toxic material in more than 1,500 places in aquifers across the country. The EPA may issue exemptions if aquifers are too remote, too dirty, or too deep to supply affordable drinking water; however, EPA documents showed the agency has issued permits for portions of reservoirs that are in use, assuming contaminants will stay within the finite area exempted. More than 1,100 aquifer exemptions have been approved by the EPA’s Rocky Mountain regional office, according to a list the agency provided to ProPublica. Many of them are relatively shallow and some are in the same geologic formations containing aquifers used by Denver metro residents. More than a dozen exemptions are in waters that might not be treated before supplied as drinking water.[19] Environmental and Health Impacts

Water Use The 2013 Western Organization of Resource Councils report,  “Gone for good: Fracking and water loss in the West,” found that fracking is using 7

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billion gallons of water a year in four western states: Wyoming, Colorado, Montana, and North Dakota. State officials charged with promoting and regulating the energy industry estimated that fracking required about 13,900 acre-feet of water in 2010, about 0.08 percent of the total water consumed in Colorado. A Colorado Oil and Gas Conservation Commission report projected water needs for fracking will increase to 18,700 acre-feet a year by 2015. Environmentalists point out that the water used by fracking gets lost from the hydrological cycle forever because it is contaminated.[20] Several projects in the state have proposed draining water out of Colorado rivers and siphoning the water to towns and cities that have been selling large quantities for fracking. Environmental advocates note that fracking in Colorado could negatively impact the state’s rivers, as the process requires a significant amount of water.[21] As of 2012, water-intensive fracking projects include:[22] the Windy Gap Firming Project, which proposes to drain to an additional 10 billion gallons of water out of the per Colorado River every year and pipe and pump that water to northern Front Range Colorado cities including Loveland, Longmont and Greeley -- three cities that have recently started selling water for fracking (Greeley sold over 500 million gallons in 2011). the Northern Integrated Supply Project, which proposes to drain an additional 13 billion gallons per year out of the Cache la Poudre River northwest of Fort Collins. the Seaman Reservoir Project by the City of Greeley on the North Fork of the Cache la Poudre River, which proposes to drain several thousand acre feet of water out of the North Fork and the main stem of the Cache la Poudre. Is fracking to blame? the Flaming Gorge Pipeline, which could reportedly take a large amount of water— to 81 billion gallons—out of the Green and Colorado River systems every year and pipe and pump that water to the Front Range. the City of Denver has opened drilling and fracking on its property at Denver International Airport, while Denver is also pushing forward with the Moffat Collection System Project, a proposal to drain water out of the per Colorado River and pipe it to Denver.

Fracking in the USA 449 In March 2012, at Colorado’s auction for unallocated water, companies that provide water for hydraulic fracturing at well sites were top bidders on supplies once claimed exclusively by farmers. The Northern Water Conservancy District runs the auction, offering excess water diverted from the Colorado River Basin — 25,000 acre-feet so far this year — and conveyed through a 13-mile tunnel under the Continental Divide. The average price paid for water at the auctions has subsequently increased from around $22 an acre-foot in 2010 to $28 in 2012. [23]   In June 2012, the town of Erie doubled its commercial water rate from $5.73 per 1,000 gallons to $11.46 per 1,000 gallons -- for oil and gas developers only.[24] About 98 percent of the state is experiencing varying levels of drought in 2012, according to the Colorado State University (CSU), with the most severe in the Arkansas Basin, where drought levels range from D1, or “moderate,” to D3, or “extreme.” The Texas drought from summer 2011 is also still affecting Colorado, CSU said.[25] On July 9, 2012, the Aurora City Council in CO voted to “lease” water to Houston-based Anadarko Petroleum, which will use the water for hydraulic fracturing. Anadarko will pay the city $9.5 million over five years for access to almost 2.5 billion gallons of water.[26]

Water Contamination A 2013 study published in Endocrinology -  “Estrogen and Androgen Receptor Activities of Hydraulic Fracturing Chemicals and Surface and Ground Water in a Drilling-Dense Region”  - found water samples near Colorado gas drilling in Garfield County using hydraulic fracturing showed the presence of chemicals linked to infertility, birth defects, and cancer, at higher levels than areas where fracking was not taking place. The study also found elevated levels of the hormone-disrupting chemicals in the Colorado River, where wastewater released during accidental spills at nearby wells could occur.

Spills An analysis by Environmental Working Group and The Endocrine Disruption Exchange (TEDX) found that at least 65 chemicals used by natural gas companies in Colorado are listed as hazardous under six major federal laws designed to protect Americans from toxic substances.[6]

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In 2004, Canada-based  Encana  Corp. improperly cemented and hydraulically fractured a well in Garfield County, Colorado. The state found that the poor cementing caused natural gas and associated contaminants to travel underground more than 4,000 feet laterally. As a result, a creek became contaminated with dangerous levels of carcinogenic benzene. The state of Colorado fined Encana a then-record $371,200. After more than seven years of clean efforts, as of September 2012, three groundwater monitoring wells near the creek still showed unsafe levels of benzene.[27][28] In 2008, a drilling wastewater pit in Colorado leaked 1.6 million gallons of fluid, which migrated into the Colorado River.[29] A 2008-2011 Colorado School of Public Health hydrological study found that as the number of gas wells in Garfield County increased, methane levels in water wells also rose. State regulators later fined Encana Oil and Gas for faulty well casings that allowed methane to migrate into water supplies through natural faults.[30][31] In 2009, a wastewater spill flowed into a tributary of Dry Creek in Garfield County. It took almost a month for  Antero Resources  to notify regulators. [32] During an eight-month period in 2011, companies in the state spilled 2 million gallons of fluids. Officials say there are up to 400 oil and gas spills each year in Colorado, but that only 20 percent contaminate groundwater.[33] In 2010, a landowner observed an odor in water seeping from a gravel pit west of Silt in Garfield County. A pipeline carrying wastewater from 36 wells on five well pads in the Colorado River floodplain had leaked and contaminated groundwater. The farmer reported that he used the water for a year after the pipeline was installed. It is unknown when the leak started. Water sampling revealed high levels of benzene, toluene and total xylenes. In May 2013 the Colorado Oil and Gas Conservation Commission fined  Antero Resources $150,000 for the spill. The owner used water from the pit for crop irrigation and sometimes disposed of it in the Colorado River.[34] In March 2013, it was reported that an “underground plume of toxic hydrocarbons from an oil spill north of the Colorado River near Parachute [Colorado] has been spreading for 10 days, threatening to contaminate spring runoff. Vacuum trucks have sucked up more than 60,000 gallons, but an unknown amount remains in the ground by Parachute Creek,” which flows into the Colorado River.[35] The company responsible for the leak, Williams Energy, was put in charge of the cleanup.[36] The leak was caused by a faulty pressure gauge on a four-inch pipeline. Benzene levels in Parachute Creek rose above the safety threshold of 5 parts per billion. Following the spill, Colorado lawmakers discovered that state

Fracking in the USA 451 penalties for such accidents had been capped at $10,000 since the 1960s. In response, they passed legislation in May 2013 that increased possible state fines for such incidents. But the state had yet to fine Williams Energy.[36]

Floods of 2013 Colorado Fracking Site Flooding During the massive floods in Colorado in September 2013, sites that employed the use of fracking were flooded. It was reported that, “These floods have not only overwhelmed roads and homes, but also the oil and gas infrastructure stationed in one of the most densely drilled areas in the U.S. Although oil companies have shut down much of their operations in Weld County due to flooding, nearby locals say an unknown amount of chemicals has leaked out and possibly contaminated waters, mixing fracking fluids and oil along with sewage, gasoline, and agriculture pesticides ... No one, from oil companies to regulators, seems to know the exact extent of the damage yet as they survey the damage. But Executive Director of the Colorado Department of Natural Resources Mike King told The Denver Post that, ‘The scale is unprecedented.’ Meanwhile, the Colorado Department of Public Health has advised everyone to stay away from the water, as it is possibly contaminated by ‘raw sewage, as well as potential releases from homes, businesses, and industry.’ Two of the region’s largest oil and gas companies, Encana and Anadarko, said they responded by shutting-in or closing down several hundred of their wells, a precaution until they assess the full damage.”[37] Shortly after flooding receded there were reports of two large spills and eight minor ones.  Anadarko Petroleum  reported the two larger releases in Weld County. About 125 barrels — or 5,250gallons — spilled into the South Platte River near Milliken. A tank farm on the St. Vrain River released 323 barrels — or 13,500 gallons — near Platteville. The state oil and gas commission said it is trying to compile a comprehensive list of facilities in the flooded areas and their status, including what chemicals they had on site.[38][39]

Air Oil and gas industry sources emit at least 600 tons of contaminants in the state a day, as of 2013. They are the main source of volatile organic compounds  in Colorado and the third-largest source of  nitrogen oxides. A

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nine-county area around metro Denver does not meet federal clean-air standards, according to state data.[40]

Health Effects A study conducted over three years by the Colorado School of Public Health concluded that fracking could contribute to “acute and chronic health problems for those living near natural gas drilling sites.” The report will be published in  Science of the Total Environment. “The study found those living within a half-mile of a natural gas drilling site faced greater health risks than those who live farther away.” Researchers located “potentially toxic petroleum hydrocarbons in the air near the wells including benzene, ethylbenzene, toluene and xylene.” Benzene is classified as a known carcinogen by the EPA. Researchers collected data in Garfield County, CO from January 2008 to November 2010, using EPA air quality standards. The study reiterates earlier research that shows that prolonged exposure to airborne petroleum hydrocarbons causes “an increased risk of eye irritation and headaches, asthma symptoms, acute childhood leukemia, acute myelogenous leukemia, and multiple myeloma.”[41]

Methane A 2012 study published in the Journal of Geophysical Research and led by researchers at the National Oceanic and Atmospheric Administration (NOAA) and the University of Colorado, Boulder, estimated that naturalgas producers in an area known as the Denver-Julesburg Basin in Colorado are losing about 4% of their natural gas to the atmosphere — not including additional losses in the pipeline and distribution system. This is more than double the official inventory of methane leakage.[42]

Ozone According to the state of Colorado, natural gas and oil operations were the largest source of ozone-forming pollution, VOCs and NOx, in 2008.[43] A 2013  Environmental Science and Technology  study by scientists at the Cooperative Institute for Research in Environmental Sciences found that emissions from oil and natural gas operations account for 55% of

Fracking in the USA 453 the pollutants -- such as propane and butane -- that contribute to ozone formation in Erie, CO. Key to the findings was the recent discovery of a chemical signature that differentiates emissions by oil and gas activity from those given off by other sources.[44]

Silica In July 2012, two federal agencies released research highlighting dangerous levels of exposure to silica sand at oil and gas well sites in five states: Colorado, Texas, North Dakota, Arkansas, and Pennsylvania. Silica is a key component used in fracking. High exposure to silica can lead to silicosis, a potentially fatal lung disease linked to cancer. Nearly 80 percent of all air samples taken by the National Institute of Occupational Safety and Health showed exposure rates above federal recommendations. Nearly a third of all samples surpassed the recommended limits by 10 times or more. The results triggered a worker safety hazard alert by the Occupational Safety and Health Administration.[45]

Oil and Gas Health Information and Response Program In 2010, Colorado was the first in the nation to perform a detailed study, a “health impact assessment,” on proposed natural gas development. In October 2015, Colorado launched the “Oil and Gas Health Information and Response Program.”[1] A PhD in toxicologist is on staff. A health professional is available to talk with citizens and their primary physicians. Complaints can be lodged with the new program.ref>Dennis Webb, “State program for oil and gas complaints makes debut,” The Daily Sentinel, Nov. 1, 2015. Regulations and oversight The Colorado General Assembly created the Colorado Oil and Gas Conservation Commission to “foster the responsible development of Colorado’s oil and gas natural resources.” To do so, the COGCC developed and implemented regulations to govern the oil and gas industry. In 2010, there were more than 43,000 active wells in Colorado. That year the COGCC employed 15 inspectors, 7 who performed a total of 16,228 inspections.[46]

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According to a 2015 NRDC report, Colorado has less than 40 inspectors for 52,198 active wells.[47] In January 2013, the Colorado Oil and Gas Conservation Commission was set to begin a public debate over the future of fracking regulations in the state. One proposal from commission staff members would bump up the buffer between well sites and buildings from “150 feet in rural areas and 350 feet in urban areas to a flat 500 feet anywhere.” Additionally, “within 1,000 feet of a building, oil and gas operators would have to notify neighbors and employ ‘enhanced mitigation’ measures to cut down on dust, noise, odor and lighting.” It was also reported that under the new rules, “operators would have to have a hearing before the commission before proceeding with a well less than 1,000 feet away from a high-occupancy building, such as a school or hospital.”[48]

Air Quality Rules Colorado’s Air Quality Control Commission, part of the state health department, originally aimed to have new proposed air-quality rules by November 2013, but later said they planned on extending negotiations on the air-quality rules until February 2014. Oil and gas emissions are the main source of volatile organic compounds in Colorado and the thirdlargest source of nitrogen oxides.[49]

Injection Wells According to a 2015 NDRC report, between 2009 and 2013,  Chevron received  53 Notices of Alleged Violations due to the safety of underground injection wells.[50]

Water Testing On January 7, 2013, Colorado Oil and Gas Conservation Commission’s (COGCC) nine-member commission unanimously voted to approve the “Statewide Groundwater Baseline Sampling and Monitoring” rule that requires oil and gas operators to collect up to four water samples from aquifers, existing water wells and other “available water sources” within a half-mile of proposed wells. The sampling must be done before wells are drilled and within 72 months after the wells are placed into operation. The

Fracking in the USA 455 rules are the first to require the oil and natural gas industry to test groundwater quality both before and after drilling.[51]

Chemical Disclosure In December 2011, in accordance with new rules brokered by Colorado Gov. John Hickenlooper, energy companies in the state will have to disclose to the public the chemical family of each chemical they use in their fracking process. It has been reported that the disclosure must be made within two months on an independent internet database: FracFocus.org.[52] The new rules require drillers to file a “notice of intent to conduct a fracking treatment” of a well 48 hours prior to a frack job, and to identify the chemicals used in a frack job within 60 days after the job is finished. Chemicals can still remain protected by trade secret designation, although that designation can be challenged by the public. Even if there are complaints, however, the COGCC is not required by the new rules to investigate, although citizens can then file a legal claim.[53][54] Fracking studies In a Government Accountability Office report released in July 2014, the independent oversight agency reported the “EPA’s role in overseeing the nation’s 172,000 wells, which either dispose of oil and gas waste, use ‘enhanced’ oil and gas production techniques, store fossil fuels for later use, or use diesel fuel to frack for gas or oil. These wells are referred to as ‘class II’ underground injection wells and are regulated under the Safe Drinking Water Act. Oversight of these wells varies by state, with some coming under the regulatory authority of the EPA, including the 1,865 class II wells in Pennsylvania. The GAO faults the EPA for inconsistent on-site inspections and guidance that dates back to the 1980's. Of the more than 1800 class II wells in Pennsylvania, the GAO reports only 33 percent were inspected in 2012. Some states, including California, Colorado and North Dakota, require monthly reporting on injection pressure, volume and content of the fluid. As more oil and gas wells across the country generate more waste, the GAO highlights three new risks associated with these wells — earthquakes, high pressure in formations that may have reached their disposal limit, and fracking with diesel.”[55] Fracking accidents In November 2014, an accident occurred at a well in northern Colorado, in which one worker was killed and two others were seriously injured. Reports

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stated that the “three men were trying to heat a frozen high-pressure water line when something went wrong and the line ruptured.”[56]

Pawnee National Grassland In November 2015, the Bureau of Land Management office put up for auction 90,000 acres of mineral rights for drilling. Much of the land was within the Pawnee National Grassland, located 35 miles east of Fort Collins. Outside the action protestors from multiple environmental groups protested the sale. Ninety three percent of the land was sold within three hours. [57]

Lafayette In November 2013, Lafayette residents voted 60% to 40% for an all-out ban on new oil and gas drilling in the city.[58]

Boulder On May 13, 2013, Boulder, Colorado moms, children and activists delivered several hundred postcards Monday to the three county commissioners before holding a rally on the Boulder County Courthouse lawn, urging the commissioners to extend a fracking moratorium. The commissioners were planning to discuss imposing transportation impact fees on oil and gas companies drilling and operating wells in the county the same week.[59] In May 2013, the Boulder County commissioners voted 2-1 not to extend their moratorium on fracking, which will expire in June 2013. The commissioners cited the potential to get sued in their reasoning to let the ban expire.[60] In November 2013, nearly 80 percent of Boulder residents voted in favor of a five-year extension of the city’s fracking moratorium.[58]

Fort Collins In March 2013, the Fort Collins city council passed a ban on fracking that grandfathered in the one driller, Prospect Energy, which currently operates on eight well pads in northern Fort Collins. Three weeks later, in a quiet vote without public input, the city council passed an “agreement” with the

Fracking in the USA 457 driller allowing the company to drill and frack on two new square miles of land surrounding the Budweiser brewery in North Fort Collins.[61] In May 2013, the Fort Collins City Council overturned the fracking ban in a sharply divided 4-3 vote. The mayor pro tem cited an impending threat of a lawsuit from Prospect Energy for why he changed his vote.[62] In November 2013, over 55 percent of Fort Collins residents voted in favor of a five-year fracking moratorium in the city.[58] In August 2014, a Larimer County judge overturned Fort Collins’ fiveyear moratorium on fracking. The Ft. Collins City Council has announced they are considering whether to appeal the decision.[63] In December 2015, the Colorado Supreme Court heard arguments in two cases, Longmont’s outright ban on fracking, and the Fort Collins’ five-year moratorium. It is likely to take 3 months or longer for the court to make its ruling.[64]

Broomfield The Denver suburb of Broomfield passed a five-year fracking moratorium on the by 20 votes of 20,000 cast in November 2013. In February 2014, a judge held the results stating that while the election had flaws it was not illegal, which some pro-fracking supporters had claimed.[65]

El Paso County Moratorium In September 2011, El Paso County Commission voted to impose a fourmonth moratorium on issuing permits for activities involving oil and gas drilling, to provide time to determine whether the Colorado county needs additional regulations on drilling.[2]

Loveland Considers Water Ban for Fracking The City of Loveland’s water utility has been selling water to suppliers of the oil and natural gas industry from metered city hydrants for use in controversial hydraulic fracturing processes to recover petroleum. In April 2012, city councilors began a process to decide whether the city will join Northern Colorado neighbors Fort Collins and Boulder in barring water sales for fracking.[66]

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Longmont Voters Ban Fracking, Court Overturns, Appeal Filed In May 2012, the Longmont ballot issue committee Our Health, Our Future, Our Longmont filed a notice of intent with the Longmont City Clerk to put a charter amendment on the November 2012 ballot to ban hydraulic fracturing within Longmont city limits. According to Food & Water Watch, the Colorado Oil and Gas Association (COGA) and the Colorado Attorney General have tried to weaken Longmont’s local regulations for oil and gas drilling, such as prohibiting drilling in residential areas, spurring the amendment. If successful, Longmont would be the first city in Colorado to ban fracking.[67] In June 2012 the group Our Health, Our Future, Our Longmont,  began  a  petition drive to ban fracking within city limits. [68]   The ban — Ballot Question 300 — was passed by majority vote in the November 2012 election, and will amend Longmont›s city charter to  ban hydraulic fracturing and the storage of fracking waste in city limits. The oil and gas industry fought the ban, giving $507,500 to the opposing group Main Street Longmont. The Colorado Supreme Court has forbidden cities from banning oil and gas drilling outright, but has decided lesser measures on a case-by-case basis. Gov. John Hickenlooper said that passage of Ballot Question 300 would likely bring a second lawsuit from the state.[69] However, in late July 2014, a Colorado judge overturned the city’s ban on fracking. Boulder County District Court Judge D.D. Mallard wrote in his decision, “While the court appreciates the Longmont citizens’ sincerely held beliefs about risks to their health and safety, the court does not find this is sufficient to completely devalue the state’s interest.” Colorado Oil and Gas Association and Colorado Oil and Gas Conservation were plaintiffs in the case. Environmental groups in Colorado vowed to appeal the decision. Judge Mallard allowed the ban to remain in place while an appeal was sought.[70] In September 2014, a coalition of groups, including City of Longmont, Earthworks and Sierra Club, filed an appeal to Judge Mallard’s decision.[71] In August 2014, the Longmont City Council voted to hold the ban despite lawsuits filed against the city.[72]  The city has accumulated more than $61,000 in legal fees defending its ban on fracking.[73] In December 2015, Colorado Oil and Gas Association and the city of Longmont argued their case in front of the state Supreme Court.[74]

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Colorado Springs Group Sues to Allow Vote on Fracking Ban In May 2013, a citizens group based in Colorado Springs was reported to have “sued the city of Colorado Springs in an effort to move forward a petition to amend the City Charter to ban oil and gas drilling in the city. The Colorado Springs Citizens for Community Rights filed the lawsuit in 4th Judicial District Court in response to the city’s Initiative Title Setting Review Board’s refusal to affix a title to the petition. The title is needed before signatures can be gathered; the board rejected the petition, saying it violates the city’s single-subject rule. The proposed charter amendment, which the group wants to see on the November ballot, would prohibit any company from engaging ‘in the extraction of natural gas or oil, ‘ including the use of hydraulic fracturing, or fracking.”[75]

Residents Meet in Windsor to Discuss Fracking Impacts In October 2014, the group known as Windsor Community Rights Network organized an event in response to the increase of oil and gas activity in their town. Approximately 90 residents attended the educational event to learn more about potential impacts from fracking in their community.[76]

Citizens March to Deliver Signatures Opposing Fracking Operation In June 2012, a group of mothers and children living in Colorado marched into  Encana Corporation  headquarters in Denver to deliver a petition signed by 21,000 people demanding the company pull the plug on its project near the town of Erie, Colorado. Encana is preparing to drill a well in Canyon Creek, where a prairie rife with birds and a wetland alive with waterfowl separate it from hundreds of houses in the nearby Creekside neighborhood. An elementary school is located a few hundreds yards south of the drilling site, which is at a legal distance. Industry representatives dismissed the petition. A large rally was planned for June 9, 2012 to try to draw more attention to the drilling noise and pollution that burden affected citizens.[77]

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Public Trust Initiatives Phil Doe of Littleton and Richard Hamilton of Fairplay have introduced Public Trust Initiatives 3 and 45 to protect state waters. Initiative 3 would apply the common-law doctrine of “public trust” to water rights, and make “public ownership of such water legally superior to water rights, contracts, and property law.” It would also grant unrestricted public access to natural streams and their banks. Initiatives 45 would amend Article XVI, Section 6 of the state constitution to limit, and possibly prohibit, stream diversions that would “irreparably harm the public ownership interest in water.” In April 2012, the Colorado Supreme Court cleared the way for the initiatives to proceed. In order for them to appear on the November 2012 ballot, each initiative must get 86,000 signatures by August 6, 2012,[78] but they did not receive the required signatures to appear on the ballot.

Voters in Four Colorado Cities Call For Timeout on Fracking It was reported in October 2013 that four ballot measures put forth by residents of Boulder, Broomfield, Fort Collins and Lafayette, Colorado that will give voters the chance to declare timeout — and, in one case, ban new fracking projects and industry-waste disposal.[79] In November voters in the Colorado cities of Boulder, Fort Collins and Lafayette, approved antifracking initiatives by wide margins.[80]

Compromise Made Over Fracking Measures In August 2014, Colorado Gov. John Hickenlooper announced that a compromise with the oil and gas industry to keep measures off the 2014 election ballot was made. It was reported that, “U.S. Rep Jared Polis, D-Boulder, agreed to drop two measures he supported aimed at requiring drilling rigs to be set back 2,000 feet from homes and bolstering local control by adding an environmental bill of rights to the state constitution. Backers of two industry-supported measures — Initiative 121, which would have withheld state oil and gas revenue from communities banning drilling, and Initiative 137, which required a fiscal impact note for all initiatives — said they, too, would pull back.”[81]

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Thorton The city of Thorton came under criticism after posting a map listing the addresses of 14 fracking opponents, and homeowners, labeled “address of interest.” In November 2015, the city removed the map.[82] Citizen groups 350 Colorado Be The Change Center for Biological Diversity Citizens for a Healthy Community Citizens for Huerfano County Coloradans Against Fracking Coloradans Resisting Extreme Energy Development Earthworks Erie Rising Fracking Colorado Grand Valley Citizens Alliance The League of Oil and Gas Impacted Coloradans LOGIC Our Longmont Rainforest Action Network Routt County Frack Save Colorado from Fracking San Juan Citizens Alliance Thompson Divide Coalition Western Colorado Congress Industry groups Advancing Colorado Colorado Oil & Gas Association Common Sense Policy Roundtable Western Energy Alliance

Industry Actions It was reported in October 2013 that Colorado Oil and Gas Association gave $600,000 to fight proposed fracking bans on Colorado state ballots. The

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trade group contributed to campaigns in Broomfield, Boulder, Lafayette and Fort Collins. [83] A report by Colorado Ethics Watch in 2014 found that the oil industry spent $11.8 million on lobbying and elections.[84]

Front Group Leaders In October 2014, Greenpeace revealed that “ex-state senator and onetime Republican gubernatorial primary candidate Josh Penry and his wife, founder of Republican PR and fundraising firm Starboard Group, Kristin Strohm” were behind “at least six oil and gas industry front groups that have been fighting state regulations designed to protect the health of its citizens and the environment.” The couple also has ties to the Koch Brothers.[85] Reports

Diesel in Fracking From 2010 to July 2014, drillers in the state of Colorado had reported 9,173.06 gallons of diesel injected into 16 wells. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study  “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,”  found that  hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[86] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[87]

Air Pollution In a 2012  Science of the Total Environment  study, researchers from the Colorado School of Public Health found that air pollution caused by

Fracking in the USA 463 hydraulic fracturing or fracking may contribute to acute and chronic health problems for those living near natural gas drilling sites. The report, based on three years of monitoring, found a number of potentially toxic and carcinogenic petroleum hydrocarbons in the air near oil/gas wells, including benzene, ethylbenzene, toluene and xylene. Benzene has been identified by the Environmental Protection Agency as a known carcinogen. Other chemicals included heptane, octane and diethylbenzene but information on their toxicity is limited. The greatest health impact corresponds to the relatively short-term, but high emission, well completion period. The effects could include eye irritation, headaches, sore throat and difficulty breathing. The report, which looked at those living about a half-mile from the wells, was in response to the rapid expansion of natural gas development in rural Garfield County, in western Colorado - residents asked the School to test for health impacts. The lead researcher noted that, “there wasn’t data available on all the chemicals emitted during the well development process. If there had been, then it is entirely possible the risks would have been underestimated.”[88]

Regulatory Enforcement A 2012 report by the group Earthworks, “Inadequate enforcement means current Colorado oil and gas development is irresponsible,” found that the Colorado Oil and Gas Conservation Commission (COGCC) has not “foster[ed] the responsible development of Colorado’s oil and gas natural resources,” its stated mission, due to its inadequate enforcement of its own rules. The report found that inspection capacity is inadequate; violations are not consistently assessed, reported, and tracked; and fines are rarely issued and are inadequate to prevent repeat violations.[89] Resources

References 1. Lisa Sumi,  Inadequate enforcement means current Colorado oil and gas development is irresponsible, Earthworks Report, Mar. 2012. 2. Mark Jaffe, “Oil companies rushing to buy leases along Colorado’s Front Range,” The Denver Post, Oct. 23, 2011. 3. Amy Mall,  Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015.

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4. Fracking on BLM Colorado Well Sites, BLM, Fact Sheet, Mar. 2011. 5. Natural Gas, COGA, accessed Apr. 4, 2012. 6. Dusty Horwitt, “Colorado’s Chemical Injection,” EWG Public Lands Analyst, Jun. 2008. 7. Sam Schabacker, Hickenlooper May Be in Bed With the Oil Industry, But Coloradans Have His Wake- Call , Huffington Post, Mar. 12, 2012. 8. North Fork of the Gunnison, Western Colorado Congress Website, accessed Mar. 2012. 9. Barrett may have Paradox Basin discovery,” Rocky Mountain Oil Journal, 14 Nov. 2008, p.1. 10. What is the Niobrara Shale Formation? Oil and Shale Gas, Feb. 2010. 11. Kelsey Ray, BLM auctions drilling rights to Pawnee National Grasslands, The Colorado Independent, Nov. 15, 2015. 12. Jessica Goad, Ignoring Public Outcry, Federal Government To Offer Oil And Gas Leases Near Mesa Verde National Park, Climate Progress, Jul. 3, 2015. 13. Kelsey Ray, BLM auctions drilling rights to Pawnee National Grasslands, The Colorado Independent, Nov. 15, 2015. 14. Andrew Wineke, Drilling oil takes water and makes water, The Gazette, Apr. 28, 2012. 15. Joanna Walters, “Fracking shakes the American west: a millennium’s worth of earthquakes,” The Guardian, Jan. 10, 2016. 16. Becky Oskin, “New Mexico Earthquakes Linked to Wastewater Injection,” Livescience.com, Apr. 24, 2013. 17. Kindra McQuillan, “Where industry makes earthquakes Fracking has caused quakes in several states, but more research is needed,” High Country News, Jun. 22, 2015. 18. Joanna Walters, “Fracking shakes the American west: a millennium’s worth of earthquakes,” The Guardian, Jan. 10, 2016. 19. Abrahm Lustgarten, Poisoning the Well: How the Feds Let Industry Pollute the Nation’s Underground Water Supply, ProPublica, Dec. 11, 2012. 20. Bruce Finley, Fracking bidders top farmers at water auction, The Denver Post, Apr. 2, 2012. 21. Gary Wockner, “Will Fracking Destroy Colorado’s Rivers?” Huffington Post, Mar. 19, 2012. 22. Gary Wockner, Will Fracking Destroy Colorado’s Rivers? EcoWatch, Mar. 19, 2012. 23. Bruce Finley, Fracking bidders top farmers at water auction, The Denver Post, Apr. 2, 2012. 24. John Aguilar,  In Erie, oil and gas companies to pay twice as much for water, Daily Camera, Jun. 20, 2012. 25. Monte Whaley,  98 percent of Colorado in a drought, say CSU climatologists, The Denver Post, Apr. 3, 2012. 26. Patricia Calhoun,  Fracking: Aurora votes to ‹lease› water to Anadarko Petroleum, Denver Westword, Jul. 10, 2012.

Fracking in the USA 465 27. Dusty Horwitt, Federal Scientists Warn NY of Fracking Risks, Environmental Working Group, Feb. 22, 2012. 28. Horwitt, Dusty. Senior Counsel for the Environmental Working Group. [Public testimony]. Oversight Hearing on the Revised Environmental Impact Statement on Hydraulic Fracturing and New York City’s state Drinking Water Supply Infrastructure. Before the New York City Council Committee on Environmental Protection. Sept. 22, 2011 at 2. 29. Lustgarten, Abrahm, “How the West’s energy boom could threaten drinking water for 1 in 12 Americans,” ProPublica. Dec. 21, 2008. 30. Harman, Greg, “Fracking’s short, dirty history,” San Antonio (Texas) Current, Jan. 5, 2011-Jan. 11, 2011. 31. Smith, Jack Z., “The Barnett Shale search for facts on fracking,” Fort Worth (Texas) Star-Telegram, Sept. 5, 2010. 32. Amy Mall, Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015. 33. Colorado Public News and David O. Williams,  Cancer Concerns With Colorado›s Drilling, Fracking Boom, Colorado Public News, Jul. 21, 2013. 34. Amy Mall, Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015. 35. Parachute Creek spill continues uncontained; cause, source unknown, The Denver Post, Mar. 18, 2013. 36. John Upton, “Fracking accident leaks benzene into Colorado stream,” Grist, May 24, 2013. 37. Rebecca Leber, “Colorado Floodwaters Cover Fracking And Oil Projects: ‘We Have No Idea What Those Wells Are Leaking,’” Climate Progress, Sept. 17, 2013. 38. Mark Jaffe and Bruce Finley,  State now tracking 10 oil and gas spills in Colorado flood zones, The Denver Post, Sep 19, 2013. 39. Breaking: 5,250 Gallons of Oil Spill into Colorado’s South Platte River, EcoWatch, Sept. 19, 2013. 40. Bruce Finley, CDPHE mulls oil and gas air pollution rules as wary residents erupt, The Denver Post, Jul. 8, 2013. 41. Neela Banerjee Study: ‹Fracking› may increase air pollution health risks, Los Angeles Times, Mar. 20, 2012. 42. Jeff Tollefson, Air sampling reveals high emissions from gas field: Methane leaks during production may offset climate benefits of natural gas, Nature, Feb. 7, 2012. 43. Elena Craft,  Do Shale Gas Activities Play A Role In Rising Ozone Levels? Mom’s Clean Air Force, Jul. 13, 2012. 44. John Aguilar, “Study finds that more than half of ozone-forming pollutants in Erie come from drilling activity,” Boulder Daily Camera, Jan. 16, 2013. 45. Adam Voge, Fracking dust alert not shocking in Wyoming, Wyoming Star Tribune, Jul. 30, 2012.

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46. COGCC staff report, Jan. 13, 2011. p. 25. 47. Amy Mall,  Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015. 48. John Aguilar, “Colorado Oil And Gas Association Faces Resistance From Boulder Before Fracking Rulemaking Debate,” Boulder Daily Camera, Jan. 3, 2013. 49. Kristen Wyatt, Colorado Air Quality Rules For Oil And Gas Drillers Gets Delayed, Associated Press, Aug. 15, 2013. 50. Amy Mall, Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015. 51. Scott Streater, Colo. OKs groundwater sampling rule derided by industry, enviros, E&E News, Jan. 8, 2013. 52. Kelly David Burke, “Colorado Takes the Lead in Fracking Regulation,” Fox News, Jan. 5, 2012. 53. John Colson,  County official explains new fracking chemical rules,  Post Independent, Apr. 7, 2012. 54. Fracking Chemical Disclosure Rules,  Inside Climate News chart at ProPublica, accessed Apr. 2012. 55. Congressional Watch-Dog Warns Fracking Waste Could Threaten Drinking Water, StateImpact, Pennsylvania, Jul. 18, 2014. 56. Fracking accident kills 1, injures 2 in Colorado, Seattle PI, Nov. 13, 2014. 57. Kelsey Ray, BLM auctions drilling rights to Pawnee National Grasslands, The Colorado Independent, Nov. 15, 2015. 58. John Aguilar,  Anti-fracking measures win in Lafayette, Boulder, Fort Collins, Daily Camera, Nov. 5, 2013. 59. Amy Bounds, “Boulder County moms rally against fracking,” Daily Camera, May 13, 2013. 60. Troy Hooper, Litigation threat causes Boulder, Fort Collins to end fracking bans, The Boulder Journal, May 22, 2013. 61. All Eyes on Fort Collins Fracking Ban Vote, EcoWatch, Apr. 22, 2013. 62. Troy Hooper, Litigation threat causes Boulder, Fort Collins to end fracking bans, The Boulder Journal, May 22, 2013. 63. Erin Udell, “Council to vote on appealing fracking ruling,” Coloradoan, Sept. 23, 2014. 64. Colorado fracking battle goes to state Supreme Court, but ruling probably won›t be final word, US News and World Report, Dec. 9, 2015. 65. Judge holds Broomfield fracking ban vote,  Associated Press, Feb. 28, 2014. 66. City of Loveland ponders water sales for oil, gas drilling Tom Hacker, The Denver Post, Apr. 23, 2012. 67. Petition Drive Announced to Stop Fracking in Longmont: If Successful, Longmont Would be the First Colorado City to Ban Fracking, Food & Water Watch Press Release, May 30, 2012. 68. Scott Rochat, “Longmont activists start anti-fracking petition drive,” Longmont Times-Call, Jun. 8, 2012.

Fracking in the USA 467 69. Scott Rochat,  Ballot Question 300: Longmont fracking ban storms to victory, The Denver Post, Nov. 6, 2012. 70. Brandon Baker, “Colorado Judge Strikes Down Longmont’s Fracking Ban in Favor of ‘State’s Interest’ in Oil and Gas,” EcoWatch, Jul. 25, 2014. 71. Groups Appeal to Protect Longmont Fracking Ban, CommonDreams, Food & Water Watch, Sept. 10, 2014. 72. Jack Healy, “Heavyweight Response to Local Fracking Bans,”  New York Times, Jan. 3, 2014. 73. Chris Faulkner, “Fracking bans prove costly,” The Detroit News, Jan. 7, 2015. 74. Karen Antonacci, “Top 10 local news stories of 2015: No. 4 — Longmont’s fracking ban makes it to state Supreme Court,” Times-Call, Dec. 27, 2015. 75. Ned Hunter, “Colorado Springs group sues to allow vote on fracking ban,” The Gazette, May 10, 2013. 76. Adrian D. Garcia, “Group urges fracking moratorium in Windsor,”  The Coloradoan, Oct. 27, 2014. 77. Troy Hooper, “Fracking under way near Colorado schools,”  The Colorado Independent, Jun. 5, 2012. 78. Heather Hansen,  Will Colorado Transform its Water Law to Prioritize the Public Good? Colorado could amend its constitution to value public use over private and limit water diversions that negatively affect public uses, AlterNet, Jun. 15, 2012. 79. Voters in four Colorado cities may call timeout on fracking, The Denver Post, Oct. 13, 2013. 80. Michael Wines, “Colorado Cities’ Rejection of Fracking Poses Political Test for Natural Gas Industry,” New York Times, Nov. 7, 2013. 81. Mark Jaffe, “Hickenlooper compromise keeps oil and gas measures off Colorado ballot,” The Denver Post, Aug. 4, 2014. 82. Rita Brown, “City removes map showing addresses of fracking opponents,” Energy Voice, Nov. 1, 2015. 83. Colorado Oil and Gas Association gives $600K to fight fracking bans on Front Range ballots, Boulder Daily Camera, Oct. 16, 2013. 84. Jennifer Oldham, “Anadarko anoints ‘brand ambassadors’ to fight off drilling bans,” Bloomberg, Feb. 21, 2016. 85. Jesse Colema, “Colorado’s First Cole of Pro-Fracking Front Groups,” Huffington Post, Oct. 21, 2014. 86. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 87. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014. 88. Air emissions near natural gas drilling sites may contribute to health problems, News Med, Mar. 19, 2012. 89. Lisa Sumi,  Inadequate enforcement means current Colorado oil and gas development is irresponsible, Earthworks Report, Mar. 2012.

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Connecticut In a portion of the state of Connecticut there is a geological formation known as the Hartford Basin, which the USGS believes may have gas, but of limited and questionable quality, suggesting it would not be economic to drill or frack anytime soon. Some in the state have called for a ban on fracking as a precaution.[1] On March 27, 2013, the Connecticut legislature’s Environment Committee voted to forward legislation banning the possession or storage of fracking waste in the state to the House of Representatives.[2] Part of Connecticut is in a geological formation known as the Hartford Basin, stretching 34 miles long and varying in width from three to 15 miles. The entire basin lies under the Connecticut Valley from roughly the Vermont border to the Connecticut shoreline. Geologists say the Hartford Basin is unlikely to be replete with gas: a good portion of the basin was overheated from volcanic activity, which likely vaporized any oil or gas, while other places were not heated enough to produce gas. Geologists therefore say it is unlikely the deposits will be extracted anytime soon, because they are probably too small, scattered, and of questionable quality.[3] Texaco did exploratory geophysical work in the 1970s, and then paid for work in the 1980s to examine the hydrothermal history of the Connecticut Valley, but no further exploration took place.[3] In June 2012, a US Geological Survey  report  assessed five East Coast basins, but only mentioned the Hartford Basin. Waste Disposal Washington, Coventry and Mansfield counties have imposed laws to keep fracking waste out.[4] Citizen activism Legislative issues and regulations On March 27, 2013, the Connecticut legislature’s Environment Committee voted to forward legislation banning the possession or storage of fracking waste in the state to the House of Representatives.[5] Industry groups Connecticut Petroleum Council Resources

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References 1. Gregory B. Hladky, Environmentalists in Connecticut Look to Ban Fracking: Concerns About Hydraulic Fracturing, ct.com, Jul. 31, 2012. 2. Conn. bill advances banning fracking waste, Associated Press, Mar. 27, 2013. 3. Beth Daley,  Western Mass. viewed as territory for fracking,  Boston Globe, Dec. 13, 2012. 4. Anna Bisaro,  Connecticut towns raise concerns about fracking waste; Branford could become 4th to ban it, New Haven Register, Feb. 6, 2016. 5. Conn. bill advances banning fracking waste, Associated Press, Mar 27, 2013.

Delaware As of 2013, no shale gas reserves have been identified in Delaware. But the drinking water for most of the state’s residents comes from the Delaware River Basin – where fracking for gas and associated pipelines is being considered in Pennsylvania. In 2012, it was discovered that wastewater from fracking was entering the state›s rivers. The state is involved in issues over fracking wastewater regulation through the inter-state Delaware River Basin Commission (DRBC).[1] Water regulations The Delaware River Basin Commission (DRBC) was created by Congress in 1961 to provide shared management and oversight of water use and water quality in the watersheds intersecting Delaware, New York, New Jersey and Pennsylvania. In 2010, DRBC put a hold on new gas well projects and barred basin wastewater plants from treating castoff frack water, pending development of regulations. 2012 outlooks call for 2,200 or more drilling pads, taking up 12,000 acres of the watershed and sending out 18,000 or more horizontal wells, each needing 5 million gallons of water just to develop and producing 18 billion gallons of wastewater over a 10- to 20-year period. In November 2011, Delaware Gov. Jack Markell announced his intention to vote against draft fracking well and water-quality regulations that, if approved, would have cleared the way for drilling inside the 13,000-square-mile Delaware watershed. None of the Marcellus Shale runs under Delaware, but Markell cited concerns about protections for groundwater, surface water, drinking water and aquatic life and ecosystems. The announcement prompted the DRBC to table the fracking regulations rather than face a split vote or deadlock among the four state governors.

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That impasse has in turn left eastern Pennsylvania and New York drillers in limbo and triggered attacks on Markell and Delaware by fracking supporters.[1]

Discovery of Fracking Wastewater In 2009 and 2010, about 1.4 million gallons of partially treated wastewater collected from hydraulic fracturing wells outside the Delaware River basin were further processed and flushed into Delaware waters through the commercial side of Dont’s wastewater plant in Deepwater, New Jersey, near the foot of the Delaware Memorial Bridge. Delaware regulators only learned when contacted by The News Journal in May 2012 that the drilling wastewater passed through Dont’s plant for treatment, exiting from a discharge pipe under the river on Delaware’s side of the state line. In response, Dont official Rick Straitman said that Deepwater received gas well wastewater for treatment only after it was mixed with other, partially treated liquid wastes shipped in by a hazardous-materials handler north of Philadelphia. Straitman added that Dont discontinued its industrial treatment-for-hire business in Deepwater on March 30, 2012, and now operates the plant only for Chambers Works chemical plant wastes. He referred questions about pretreatment and mingling of gas wastes with other liquids to the Pennsylvania company, PSC Industrial Services, but also said that Dont “has made no business decisions” about future treatment of hydraulic fracturing wastewater.[1]

References 1. Jeff Montgomery,  Debate seeps into Delaware: Fracking discovery stirs concern, The News Journal, May 20, 

Florida Florida has a long history of oil drilling in parts of southwest Florida and the Panhandle. Fracking is not taking place in the state, however in October 2013, The Fort Myers News-Press reported that it had obtained emails from the Department of Environmental Protection indicating discussions had been taking place about the possibility of fracking in Florida.[1] In February 2016, the state passed a bill that would allow fracking to occur.[2]

Fracking in the USA 471 Since 1943, Florida has produced approximately 25 billion gallons. Drilling peaked in the late 1970s. The Sunniland Trend, located in Collier, Hendry, Lee and Miami-Dade counties has produced through conventional drilling. The Northwestern part of the state in Jay Field, located in Escambia and Santa Rosa Counties has also produced through conventional drilling. The Tallahassee Democrat reports that oil and gas may be located Gulf and Calhoun counties based on logs from exploratory wells drilled in the area between the 1940s and late 1980s. A basin located 15,000 feet underground appears similar to areas in Northwestern Florida Santa Rosa and Escambia counties holding significant amounts of oil from the Smackover formation.[3] In March 2013, the House Agriculture & Natural Resources Subcommittee voted unanimously toapprove a measure (HB 743) that would direct the state Department of Environmental Protection to setup a registry to collect the information about chemicals and volumes of water used in the fracking process, should fracking occur in the state. The Senate version (SB 1028) had been filed but not yet heard in a committee. The Florida Petroleum Council expressed support for the bill.[1] In 2014, Florida produced 222,700 barrels (9.4 million gallons) of crude oil.[4] In 2014, Collier County residents and county officials spoke out against a form of unconventional drilling called acidification. Of concern is Texasbased Dan A. Hughes Co acidification of the wetlands near Naples.[5] The Tallahassee Democrat reported in 2015 that Cholla Petroleum, a Dallas, Texas oil company’s plan to search for oil and gas in North Florida in Calhoun and Gulf counties near the Apalachicola and Chipola rivers. Some residents fear that the company plans to do  hydraulic fracturing. Cholla also wants to expand to the wetlands 17 miles south of Blountstown in Calhoun County and north of Wewahitchka in coastal Gulf County.[6] LNG terminal

Carib Energy In 2014, the Carib Energy plant in Martin County, Florida, was granted a license to export 40 million cubic feet a day of natural gas to nearly any country, including those without a free trade agreement with the U.S. Carib is already exporting LNG in shipping containers to Caribbean and Central American countries.[7]  Carib Energy is now a subsidiary of the Crowley Maritime Corporation.[8]

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Citizen activism There is environmentalist organizing against drilling in the Big Cypress National Preserve, where drilling is currently allowed. Big Cypress National Preserve protects over 729,000 acres of swamp containing both tropical and temperate plant communities. The land filters water into an underground aquifer that provides drinking water for the city of Naples. Of particular interest to drillers is a geological area called the Sunniland Trend beneath the preserve. [9] February 1, 2016: A group of protesters, which included elected officials and environmental activists, staged a rally outside State Sen. Thad Altman’s office in Cape Canaveral, Florida to voice their concerns of efforts to allow fracking in Tallahassee. The group demanded Sen. Altman back a fracking ban in order to protect Florida’s water quality and environment.[10] Drilling In 2014, Texas-based oil company Dan A. Hughes Co. was cited for illegal fracking in Corkscrew Swamp Sanctuary, which is nesting site for wood storks. The Florida Department of Environmental Protection sanctioned and fined the company $25,000 for fracking without a permit. However, the Florida Dept. of Environmental Protection was criticized for not immediately disclosing the sanctions and fine to the public.[11] Legislative issues and regulations In November 2014, two Florida State Senators, Sen. Dwight Bullard, D-Miami, and Sen. Darren Soto, D-Orlando, filed legislation that, if passed, would ban fracking in the state to protect the water supply, environment and robust tourism economy.[12] That bill failed to pass, but was reintroduced in 2015.[13] In June 2015, legislators passed a ruling allowing customers of Florida Power & Light, the state’s largest utility, to pay up to $500 million a year in unregulated natural gas hydraulic fracturing projects. Florida Power and & Light will be the first utility in the nation to be allowed to use ratepayer money for such an unregulated risk.[14] In December 2015, the decision Florida if FP&L can bill customers for fracking expedition was kicked to the Florida Supreme Court.[15] In November 2015, Florida county commissioners opposed a push by state lawmakers that would curtail their ability to regulate or ban fracking in their counties. As of November 2015, 20 counties in Florida had fracking bans, including Leon and Miami-Dade. The bans covered 43 percent of the state’s population, or 8 million people. However, state bills (HB 191 and SB 318) would curtail county’s ability to regulate fracking, and instead would manage

Fracking in the USA 473 this type of resource development at the state level. The proposed state bills would take away the county or city’s ability to ban fracking. Only zoning ordinances passed prior 2015 would be enforceable if these state measures pass.[16] Broward County Commission has proposed a blanket ban on fracking throughout the county after a landowner, Kanter Real Estate, request to drill an exploratory well in the Everglades. Kanter owns 20,000 undeveloped acres in the Everglades, west of the city of Miramar. A public hearing will take place January 12, 2016.[17] In February 2016, the Florida House approved a bill that would regulate fracking in the state. HB 191 will allow fracking, however this drilling will not be allowed until after a report by state environmental regulators is released in 2017. Earlier the Florida House rejected a measure that would have forced the oil and gas industry to “disclose carcinogens and monitor the effects of fracking on pregnant women and drinking water.”[2] Even so, the bill would prevent local governments from banning fracking within their jurisdiction.[18] Citizen groups The Conservancy of Southwest Florida Florida Coastal & Ocean Coalition StoneCrab Alliance South Florida Wildlands Association Industry groups Florida Petroleum Council

References 1. Jim Saunders, “Florida lawmakers lay groundwork for natural gas ‘fracking,’” News Service of Florida, Mar. 7, 2013. 2. Mary Ellen Klaus, “Florida House approves bill to authorize, regulate fracking,” Miami Herald, Jan. 27, 2016. 3. Jeff Burlew, “Fracking fears surface in North Florida,” Tallahassee Democrat, Oct. 23, 2015. 4. U.S. Energy Information Administration, Petroleum & Other Liquids, Eia. gov, Retrieved Oct. 31, 2015. 5. Greg Allen, “Florida County Goes To Court Over ‘Acid Fracking’ Near Everglades,” NPR, Jul. 2, 2014. 6. Jeff Burlew, “Fracking fears surface in North Florida,” Tallahassee Democrat, Oct. 23, 2015.

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7. Timothy Cama, DOE clears natural gas exports at two sites, The Hill, Sept. 10, 2014. 8. Carib Energy is Now a Crowley Company,  Crowley company website, accessed Sept. 14, 2015. 9. Greg Allen, “Environmentalists Sound Alarm On Proposed Drilling Near Florida Everglades,” NPR, Apr. 22, 2014. 10. Protesters raise voices against fracking, Florida Today, Feb. 1, 2016. 11. DEP Bust Everglades Oil Driller For Fracking, Clams, Slammed for Cover-up. Red Ant, New Times, Apr. 22, 2014. 12. State Senators File Anti-Fracking Bill, CBS Miami, Dec. 2, 2014. 13. Julie Dermansky, “Battle to Keep Florida Frack-Free Heats,” AlterNet, Nov. 16, 2015. 14. Mary Ellen Klas,  FPL customers will be charged for fracking activities, board says, Miami Herald, Jun. 15, 2015. 15. Troy Kinsey, “Florida Supreme Court to decide if FP&L can bill customers for fracking expedition,” Capital Reporter, Dec. 12, 2015. 16. Jeff Burlew, “Counties oppose bills to pre-empt fracking bans,” Tallahassee Democrat, Nov. 28, 2015. 17. To Protect Everglades Broward Proposes Ban On Fracking, New Times, Jan. 12, 2016. 18. Lizette Alvarez, “Unlikely Battle Over Fracking Intensifies in Florida,” Feb. 23, 2016.

Georgia Oil and gas drilling has never taken place in Georgia, and exploration for conventional fossil fuels stopped in the 1970s. In the 2000s, oil and gas companies began buying up leases to explore the state’s shale plays. Most exploration in the state remains focused on the Conasauga shale field, which contains 625 trillion cubic feet of gas underlying Alabama. It has been reported that a similar amount could be underground in Northwest Georgia, but this so far remains speculative.[1] Background North Georgia has become a wildcatting ground for natural gas. Oklahoman Jerry Spalvieri’s company, Buckeye Exploration, drilled a test well outside Dalton in Whitfield County in 2010. Spalvieri has 7,500 acres to drill. One hundred and 130 landowners leased him the mineral rights. Spalvieri offered $5 an acre for mineral leases.[2] A 110-mile gas pipeline from Dalton, Georgia through Atlanta could commence summer 2016. Two interstate pipelines are planned in eastern and southwestern Georgia.[3]

Fracking in the USA 475 Offshore Drilling In January 2014, 300 residents of Kure Beach, North Carolina protested Mayor Dean Lambeth’s decision to sign a letter, written by America’s Energy Forum part of the American Petroleum Institute, supporting seismic testing for future offshore oil and gas drilling. The seismic testing is part of a plan to open an area 50 miles off the East Coast from Virginia to Georgia to oil and gas drilling by 2022. [4] LNG Terminals

Southern LNG Southern LNG is a re-gasification facility on Elba Island, in Chatham County, Georgia, five miles (8 km) downstream from Savannah, Georgia. The initial authorization for the Elba Island facility was issued in 1972. LNG shipments ceased during the first half of 1980. On March 16, 2000, the project received Federal Energy Regulatory Commission (FERC) authorization to re-commission and renovate the LNG facilities.[5] On April 10, 2003, FERC issued an order authorizing the expansion of the facility, which included adding a second and third docking berth, a fourth cryogenic storage tank, and associated facilities. The expansion enabled an increase of working gas capacity and an increase of the firm send out rate.[6] El Paso Corporation, the owner of the Southern LNG facility, announced the start up of the expanded facility, called Elba II, on February 1, 2006. The expansion cost approximately $157 million and adds 3.3 billion cubic feet (93,000,000 m3) equivalent[7] El Paso Corporation also applied for an additional expansion, on February 1, 2006, called Elba III, to double capacity again by 2010.[7]On September 20, 2007 FERC approved El Paso’s expansion for Elba III.[8]

References 1. Dan Chapman, Georgia tees up for next shale gas boom, Associated Press, Mar. 10, 2013. 2. Dan Chapman North Georgia becomes a hunting ground for natural gas, The Atlanta Journal-Constitution, Oct. 7, 2015. 3. Dan Chapman North Georgia becomes a hunting ground for natural gas, The Atlanta Journal-Constitution, Oct. 7, 2015.

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4. NC town called ‹ground zero› in offshore drilling fight shows political cost of backing Big Oil over local jobs, Facing South, Jan. 2016. 5. Elba Island LNG Expansion. - Federal Energy Regulatory Commission (FERC) 6. Order Authorizing Expansion, Federal Energy Regulatory Commission (FERC), Apr. 10, 2003, (Adobe Acrobat *.PDF document). 7. El Paso Corporation Announces Start of Service From Elba II Expansion, El Paso Corporation, Feb. 01, 2006 8. Commission approval of New, Expanded Natural Gas Facilities includes LNG, Storage, Pipeline Projects, Federal Energy Regulatory Commission (FERC), Sept. 20, 2007 | In Adobe Acrobat *.PDF document format  |  Environmental Impact Statements (EISs) - Final Environmental Impact Statement (FEIS)

Hawaii Hawaii does not have oil or natural gas reserves, although a fracking technique has been discussed for tapping the island’s geothermal energy. On October 16, 2013, the county of Hawaii, also known as the Big Island, banned fracking.[1] Hawaii does not have oil or natural gas reserves, although Sen. Russell Ruderman has said some companies are looking to use “enhanced geothermal” to break through layers of rocks and tap reserves that cannot be accessed through conventional technology. He calls the process similar to fracking and introduced a bill in 2013 to ban fracking, but did not mention geothermal. Critics note that he is opposed to all geothermal energy.[2] According to Seattle-based AltraRock Energy, geothermal fracking involves a process called hydro-shearing, in which water is pumped down  wells into the reservoir to expand existing cracks. The company considered bidding on a project in Hawaii, but said they likely will not because the company does not own the land needed to conduct an operation.[2] Geothermal fracking does use tracer chemicals, but the BLM says the agency “will know the individual chemicals being used in the proprietary products, which are ‘like biodegradable plastic bags’ that degrade when they get near the heat deep underground.”[3] Legislative issues and regulations On October 16, 2013 the county of Hawaii banned the practice of fracking by vote of 9-0.[1]

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References 1. Council Votes to Restrict GMOs, Ban Fracking,  Big Island Now, Oct. 16, 2013. 2. 2.0 2.1 Sophie Cocke, Lawmaker Raises Alarm About Geothermal Fracking in Hawaii, Honolulu Civil Beat, Jan. 30, 2013. 3. Cassandra Profita,  Geothermal Fractures Vs. Hydraulic Fracking: What›s The Difference? Ecotrope, Jan. 24, 2012.

Idaho After the exploration company Bridge Resources said it wanted to “minifrack” some of its gas wells in 2011, the state passed drilling and fracking rules in 2012, permitting fracking in the state. The rules have been seen a controversial, as they limit local control over drilling and allow for nondisclosure of fracking chemicals as industry “trade secrets.”[1] Bridge Resources, a Colorado-based company, drilled 11 commercial natural gas wells in western Idaho’s Payette County in 2011 under temporary state drilling rules, which used existing procedures in Wyoming as a model. Of 11 exploration wells, three were deemed immediately successful, four were deemed dry, and Bridge planned to “mini-frack” the remaining four.[1] Payette County Commissioners rejected Bridge’s request for a conditional use permit in the company’s effort to build a 13-acre gas compression site to send 50 million cubic feet of gas into a commercial pipeline. Bridge said it would go to the state governor.[1] In 2012, the Idaho House and Senate committees approved new rules to allow fracking, drawn by the state Oil and Gas Conservation Commission. They took effect at the close of the legislative session in spring 2012.[2] The rules would allow the use of carcinogenic materials, and allow drillers to not publicly disclose what fracking materials they would use as “trade secrets.” The rules also prevent counties from prohibiting drilling. [1]  Companies that use fracking will be required to dispose of their excess chemicals in specially lined pits.[2] The legislation was co-authored by the Idaho Petroleum Council, a lobbyist organization representing drillers, and the Idaho Association of Counties. Kerry Ellen Elliott, lobbyist for the IAC, said while the proposed measure would still allow local governments to have a role in the permitting process, they could no longer say no to drilling.[1] Snake River Oil and Gas, a subsidiary of Arkansas-based Weiser-Brown Oil Co., has leased roughly 30,000 acres of land in the state, mostly in the southwestern corner, with the intent of drilling for natural gas.[2]

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Legislative issues and regulations List of regulations in the state HR 464 - signed into law in 2012 to provide for uniformity and consistency in the regulation of the production of oil and gas throughout the state of Idaho. Allows for fracking, the non-disclosure of chemicals used as industry trade secrets, and limit[s] local restrictions relating to oil and gas. Citizen groups Wild Idaho Rising Tide

References 1. George Prentice, Idaho›s Gasland Rules Debated: Getting testy over fracking, local control, Boise Weekly, Feb. 8, 2012.  2. Katherine Wutz,  Legislature allows ‘fracking’ in Idaho,  Idaho Mountain Express, Feb. 8, 2012.

Illinois Energy companies are leasing farmland in southern Illinois, which is situated above the New Albany Shale, a large geologic formation that contains natural gas and oil shale deposits, including byproducts like ethane (used for propane and plastics). The gas and oil in the shale would be accessed through fracking. As of April 2012, up to $100 million has been spent to secure mineral rights in nineteen counties considered favorable for gas exploration.[1] On May 29, 2013, it was reported that Illinois-based Campbell Energy had submitted a well completion report to the Department of Natural Resources, voluntarily disclosing that it had fracked a well in White County, Illinois.[2] On May 31, 2013, fracking regulations were passed in the state,[3] beating out  HB3086  /  SB 1418, which would have imposed a two-year fracking moratorium while assessing the risks. Southeastern Illinois is home to the New Albany shale formation.[4]  The Devonian-Mississippian New Albany Shale also stretches to Indiana and Kentucky.

Fracking in the USA 479 On April 5, 2012, it was reported that energy companies are moving to strike lease deals with landowners and mineral rights owners in the southeastern part of Illinois, with the first test wells in the region expected to be drilled in the next month or two. If some of the wells are successful, it is expected to lead to more leases and drilling. Energy companies in Illinois are seeking natural gas liquids like ethane, a component in making plastics and the fuel propane, which is fetching higher commodity prices than heating-quality natural gas, the price of which has plummeted as supplies have surged with fracking. Chicago Business  noted that the leases could be attractive in places like Wayne County, a mainly farming area 270 miles south of Chicago, where economic opportunities are scarce. Companies are reportedly paying more than $100 an acre for leasing deals with owners, with royalties on anything produced at up to 17.5 percent.[1]  Denver-based Strata-X Energy has spent about $2 million in Illinois leasing nearly 50,000 acres.[5] Legislation moving through Springfield would require drillers to disclose the chemicals used and establish standards for concrete well casings and wastewater storage. The bill, sponsored by Sen. Michael Frerichs, D-Champaign, and backed by the group Faith in Place, is supported by the oil and gas industry after negotiations. The Senate is set to take it up in April 2012.[1] Regulations had still not been passed in the state House nor Senate on May 29, 2013, when it was reported that Illinois-based Campbell Energy submitted a well completion report last June 2012 to the Department of Natural Resources, voluntarily disclosing that it had fracked a well in White County, Illinois. Companies currently are not required to tell the Illinois DNR what method they use to extract oil and gas, but Campbell Energy included that information anyway.[6] On May 31, 2013, fracking regulations were passed in the state,[7] beating out  HB3086  /  SB 1418, which would have imposed a two-year fracking moratorium while assessing the risks. Fracking sites The Devonian-Mississippian New Albany Shale lays in the southeast Illinois Basin, encompassing Illinois, Indiana, and Kentucky. The New Albany has been a site for gas production for more than 100 years, but activity has increased since the early 2000s with the development of horizontal wells and fracking. Wells are 250 to 2000 feet deep. The gas is described as having a mixed biogenic and thermogenic origin.

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Reserves A 2011 report by the U.S. Energy Information Administration estimated recoverable natural gas reserves in the New Albany shale at about 11 trillion cubic feet, or slightly less than half of what the entire nation consumed in 2010.[1] (A N.Y. Times analysis later questioned EIA estimates of shale gas reserves, saying they rely heavily on industry estimates and press releases.)[8] Legislative issues and regulations

2012 Regulatory Bills SB3280 and HB3897 (2012) - would require drillers to disclose the chemicals used in fracking and establish standards for concrete well casings and wastewater storage. The Senate is set to take up SB3280 in April 2012.[9] An earlier bill, SB664, originally included language to require chemical disclosure and wastewater management, and to prohibit the use of benzene and other volatile organic compounds. After lengthy negotiations, the provisions were eliminated from the legislation that passed the Senate before failing to clear the House in 2011. The bill was reintroduced as SB3280. [1]  The new disclosure bill uses language from ALEC model bills providing large loopholes for companies wanting to protect their fracking chemical “trade secrets” - the loophole legislation was sponsored by  ExxonMobil, according to the New York Times.[10] [11][12]

Royalty HB4312 (2012) - would establish a twelve percent tax on oil and gas revenues.[1]

2013 Regulatory Bills On May 21, 2013 the House Executive Committee voted 11-0 to send  SB1715, meant to regulate hydraulic fracturing, to the floor of the House.[13]  The bill passed in the waning hours of the Illinois General Assembly’s 2013 session, and signed into law by Gov. Quinn.[14] Although often referred to as the toughest fracking regulations in the U.S., critics say the bill was brokered in a backroom deal by Illinois

Fracking in the USA 481 Democrats, gas industry and labor representatives, and a small cadre of environmental groups, without independent scientists, health experts, or impacted downstate residents at the negotiating table. No public hearings or public comment periods took place. The bill requires chemical disclosure, but has loopholes for trade secrets.[15] The bill beat out HB3086 / SB 1418, which would have imposed a twoyear moratorium in the state on hydraulic fracturing while establishing a process to assess the risks and possible protections. As of October 2013, companies wishing to engage in horizontal hydraulic fracturing in Illinois must begin registering with the state, a new requirement. The companies must register 30 days before filing an application to drill, which will be posted online.[16] Citizen activism

March 2012: Illinois Residents Take on Fracking Several Illinois organizations state that fracking is not safe. One group  includes Southern Illinoisans Against Fracturing Our Environment, or S.A.F.E., which is trying to warn homeowners that it could do a lot more damage than energy companies are leading on. The groups are forming a campaign to educate the public about fracking issues in the state.[17]

March 2013: Illinois Residents Vow Civil Disobedience As Fracking Bill Goes Into Effect In March 2013, Illinois citizens opposing fracking protested at the Illinois State Capitol in Springfield, Illnois in an effort to pressure lawmakers for a two-year moratorium on fracking. Illinois Gov. Pat Quinn had previously signed new legislation that many anti-fracking advocates have vowed to resist because many of the chemicals used in the process would not be released to the public because they were deemed “trade secrets”.[18] Citizen groups Faith in Place S.A.F.E.

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References 1. Michael Piskur, Don›t Drink The Water? The Race To Keep IL Water Clean Before Fracking Begins, Progress Illinois, Apr. 4, 2012.  2. Tammy Weber, Illinois high-volume ‹fracking› underway, Associated Press, May 29, 2013. 3. Julie Wernau, Fracking regulations passed in Springfield, Chicago Tribune, May 31, 2013. 4. Steve Daniels,  Fracking comes to Illinois, for better or worse,  Chicago Business, Apr. 05, 2012. 5. Julie Wernau, Fracking: Public to soon learn who wants to extract Illinois oil: Companies seeking fracking projects must start registering this month with state, Chicago Tribune, Oct. 07, 2013. 6. Tammy Weber, Illinois high-volume ‹fracking› underway, Associated Press, May 29, 2013. 7. Julie Wernau, Fracking regulations passed in Springfield, Chicago Tribune, May 31, 2013. 8. Ian Urbina, Behind Veneer, Doubt on Future of Natural Gas, New York Times, Jun. 26, 2011. 9. What is Fracking? Faith in Place, accessed Apr. 2012. 10. Mike McIntire, Conservative Nonprofit Acts as a Stealth Business Lobbyist, New York Times, Apr. 21, 2012. 11. Ellen M. Gilmer, “New year prompts slew of fracking bills” Energywire, Feb. 20, 2013. 12. Julie Wernau, “For Illinois counties, fracking taxes could be too little, too late,” Chicago Tribune, Mar. 31, 2013. 13. “House panel gives OK to ‘fracking’; could mean 47,000 jobs for Southern Illinois,” BND.com, May 21, 2013. 14. Julie Wernau, Fracking regulations passed in Springfield, Chicago Tribune, May 31, 2013. 15. Jeff Biggers and Ben Evans,  Illinois’ Flawed Fracking Law Is Everyone’s Problem, Ecologist Says, Yes!, Jun. 4, 2013. 16. Julie Wernau, Fracking: Public to soon learn who wants to extract Illinois oil: Companies seeking fracking projects must start registering this month with state, Chicago Tribune, Oct. 07, 2013. 17. Residents Take On Fracking Companies, WSILTV.com, Mar. 25, 2012. 18. Illinois Residents Vow Civil Disobedience As Fracking Bill Goes Into Effect, Trisha Marczak, MintPress News, Jun. 19, 2013.

Indiana Between 2005 and 2010, as many as 23 percent of the new oil and gas wells drilled in Indiana used hydraulic fracturing.[1]

Fracking in the USA 483 In 2015, the state had 77,000 active, and inactive, wells.[2] The Associated Press reported in 2015 approximately a quarter of Indiana’s oil and gas wells have used hydraulic fracturing.[3] In 2014, Indiana produced 250,700 barrels (10.5 million gallons) of crude oil.[4] Hydraulic fracturing was first introduced in the Illinois Basin in the early to mid-1950’s to increase production from oil wells in Illinois, Indiana, and western Kentucky. According to the state’s Division of Oil and Gas, the practice has been widely used here ever since.[5] The Devonian-Mississippian New Albany Shale contains gas in the southeast Illinois Basin, encompassing Illinois, Indiana, and Kentucky. The New Albany has been a site of gas production for more than 100 years, but activity increased in the early 2000s with hydraulic fracturing. Wells are 250 to 2000 feet deep. The gas is described as having a mixed biogenic and thermogenic origin. The Associated Press reported that area of Gibson County where there is an increase in oil hydraulic fracturing is home to the Wabash Valley Fault System. This fault system may be associated with Missouri’s New Madrid fault zone responsible for the large earthquakes in 1811 and 1812.[6] Water Issues Between 2011 and 2014, hydraulic fracturing several vertical oil wells in southwestern Gibson County used 250,000, or more, gallons of water and chemicals.[7] Citizen activism In June 2013, the Terre Haute City Council voted to ban “fracking” within the city limits until further notice. The council said the vote would ensure that “fracking” is not used in any operations within the city until dates can be made to city law on oil and gas drilling.[8] Legislative issues and regulations List of regulations in the state New rules  that temporarily add noncode provisions to govern hydraulic  fracturing became effective on July 1, 2012, requiring companies to report the materials and the volume of chemicals used in the fracturing fluid. Companies, however, may withhold information they deem confidential without justification or oversight. The rules require partial pre-fracturing disclosure or notice of all the chemicals that may be used.[9]

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References 1. Amanda Solliday, Indiana DNR Mandates Companies To Report Fracking Chemicals, Indiana Public Media, Sept. 14, 2012. 2. Lauren Slavin, Drilling down on fracking in Indiana, Herald-Times, Mar. 13, 2015. 3. Rick Callahan, Indiana studying whether hydraulic fracking by oil and gas operations can cause earthquakes, Associated Press, Sept. 28, 2015. 4. U.S. Energy Information Administration, Petroleum & Other Liquids, Eia. gov, Retrieved Oct. 31, 2015. 5. Facts About Hydraulic Fracturing in Indiana, Indiana DNR, accessed Apr 2013. 6. Rick Callahan, Indiana studying whether hydraulic fracking by oil and gas operations can cause earthquakes, Associated Press, Sept. 28, 2015. 7. Rick Callahan, Indiana studying whether hydraulic fracking by oil and gas operations can cause earthquakes, Associated Press, Sept. 28, 2015. 8. Arthur Foulkes, Council bans ‹fracking› in city, The Tribune Star, Jun. 14, 2013. 9. New NRDC analysis: State fracking disclosure laws fall painfully short, NRDC, Jul. 26, 2012.

Iowa On April 1, 2012, it was reported that Timothy Berge of  Pangean Resources LLC of Denver, Colorado is hoping to persuade companies to drill some new test wells in Iowa in the next few years. The wells would involve fracking. Berge has sent out lease offers for hundreds of thousands of acres to various Iowa counties. Iowa has no fracking regulations.[1] Iowa has no fracking regulations.[1] In February 2016, Iowa will decide whether to grant Energy Transfer Partners (ETP) a permit for its Dakota Access pipeline. The pipeline carrying Bakken Shale would cut across the state. The Iowa Utilities Board will conduct deliberations on Dakota Access from February 8 through February 11, after which the Board will vote on the pipeline proposal.[2]

References 1. Jane Yoder-Short, Time for Iowa to think about fracking regulations, Press Citizen, Apr. 1, 2012. 2. Steve Horn, “As Iowa Caucuses Loom, Hawkeye State Is Last Hope To Block Fracked Bakken Oil Pipeline,” DeSmogBlog, Jan. 30, 2016.

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Kansas According to the Kansas Corporation Commission, which regulates oil and gas in the state, fracking takes place in Kansas on vertical wells, on coalbed methane wells in southeast Kansas, on Niobrara Chalk Wells in northwest Kansas, and on horizontal wells.[1] Most of the new fracking takes place on the horizontal wells in the Mississippian Lime Play (MLP), a porous limestone formation found under parts of southern and western Kansas.[2] In 2012, total crude output in the state stood at 43.6 million barrels, and official estimates project that Kansas oil production will grow by about 5 percent annually. In October 2013, E&E News reported that “Kansas has seen more than $1 billion in oil and gas investment over the past several years” in fracking for  tight oil, but “initial production in the state’s Mississippi Lime formation has fallen short of expectations, and companies such as Shell Oil Co. and Tug Hill Operating have stopped drilling or ditched assets in Kansas.”[3] Kansas was the site of the country’s first vertical fracking in 1947. According to president of the Kansas Independent Oil & Gas Association Ed Cross, more than 57,000 vertical wells have been fracked in Kansas from 1947 to mid-2012.[4] The first horizontal drills were installed in Kansas in 2009. Interest centers on the Mississippian Lime Play (MLP), a porous limestone formation found under parts of southern and western Kansas as well as across the boundary in northern Oklahoma. The Mississippian Lime has already been the site of more than 1 billion barrels of oil in the state since 1915 from conventional wells, but was considered largely tapped out. Horizontal drilling and hydraulic fracturing have kindled industry hopes of a new oil rush.[2] In 2012, over 140 horizontal wells were drilled in the state, up from 50 in 2011 and 10 in 2010. Unconventional oil and gas production amounted to only 10,000 barrels of oil-equivalent at the end of 2012, or 3.8 percent of the state total, but exploration companies say they are still trying to scope out the play and identify “sweet spots.” Early exploration was directed towards natural gas, but steadily decreasing gas prices has switched the focus to finding oil.[2] Drilling wells Over 140 horizontal wells were drilled in the state in 2012, up from 50 in 2011 and 10 in 2010. Most wells have been drilled in three counties along the Oklahoma border (Harper, Barber and Comanche) though wildcats have been sunk in another nine and the Play underlies parts of 34 counties in total.[2]

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Water Water permits have soared to the highest level in 30 years in Kansas, due to increased demand from fracking operations. Many of the Kansas oil boomtown counties are under “drought watch”; water levels in the High Plains aquifer system, which supplies water for about 86% of the state’s irrigation permits, have been declining for 14 straight years. The water used for fracking amounts to less than 1% of the state’s overall use (as of 2012), but environmentalists point out that that water is lost to the hydrologic cycle forever because it is too dirty to be reused for anything but disposal or recycling for further drilling.[5] Every barrel of oil from southern Kansas requires 16 barrels of water.[6] Earthquakes Southern Kansas has had an increase in the number of small earthquakes: since 2011, 13 earthquakes had been recorded across three counties by December 2013, according to the Kansas Geological Survey. The tick has coincided with more oil and gas activity in the area. KGS geologist Lynn Watney told E&E that a connection is not yet clear, and there needs to be more monitoring of seismic activity near drilling sites.[7] A magnitude-3.8 earthquake hit Caldwell, Kansas, on December 18, 2013.[7] The Wichita Eagle reported that scientists have identified underground disposal of drilling wastewater as likely responsible for earthquakes that have in Harper and Sumner counties south of Wichita since 2013.[8] Legislative issues and regulations In March 2016, state regulators at Kansas Corporation Commission ordered a six-month slowdown in wastewater injection disposal to enable further monitoring.[9] On March 6, 2012, the Senate Utilities Committee (SUC) debated a bill that would give the Kansas Corporation Commission explicit authority to regulate hydraulic fracturing of natural gas. Tom Day, the KCC’s legislative liaison, said the KCC has long had the authority to regulate the state’s oil and gas industry in a broad sense, but a succession of attorneys general have determined that the agency oversteps its bounds when it attempts to write rules specific to fracking, making the creation of rules through the Legislature specifically regarding fracking necessary to clarify KCC’s authority and adequately oversee the process. Sen. Pat Apple (R) and chairman of the SUC suggested that fracking is too unwieldy to keep up with changes in technology, and therefore the KCC would be better suited to regulate it than the Legislature.

Fracking in the USA 487 Kansas Independent Oil and Gas Association president Edward Cross testified in favor of the bill, saying he would prefer state regulation rather than the federal Environmental Protection Agency, which he described as “overly political”: “From the industry standpoint we like this because it pushes back against the EPA to say we don’t think we need federal regulation because we have something in Kansas.” Cross provided written testimony saying that fracking poses no threat to drinking water. Citizens have argued for state and federal regulation, citing personal evidence of contamination and a study by Duke University, which found methane contamination of drinking water associated with shale gas extraction, and Cornell University, which estimated that as much as 8 percent of the methane in shale gas leaks out into the air during the lifetime of a hydraulic shale gas well, making it a higher greenhouse gas emitter than conventional gas, oil, or even coal.[10]

Diesel in Fracking From 2010 to July 2014 drillers in the state of Kansas reported using 153.71 gallons of diesel injected into four wells. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[11] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[12]

References 1. Hydraulic Fracturing: Joint Committee on Energy and Environmental Policy, Kansas Corporation Commission, Sept. 9, 2011. 2. John Kemp, Dreaming of Bakken, Kansas welcomes oil drillers, Reuters, Jan. 08, 2013. 3. Low output stifles drillers› hopes in Kan. play, E&E News, Oct. 24, 2013. 4. Blake Ellis, “Water grab in Kansas oil boom,” CNNMoney, Jun. 12, 2012.

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5. Blake Ellis, “Water grab in Kansas oil boom,” CNNMoney, Jun. 12, 2012. 6. For earthquake study, Kansas extends limits on wastewater from drilling, The Wichita Eagle, Oct. 29, 2015. 7. Temblors rack small town near Kan. drilling sites,  E&E News, Dec. 18, 2013 8. For earthquake study, Kansas extends limits on wastewater from drilling, The Wichita Eagle, Oct. 29, 2015. 9. For earthquake study, Kansas extends limits on wastewater from drilling, The Wichita Eagle, Oct. 29, 2015. 10. Andy Marso,  Broad support for KCC to regulate fracking,  The Topeka Capital-Journal, Mar. 6, 2012. 11. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 12. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014.

Kentucky According to the Kentucky Waterways Alliance, there are an estimated 6,000 shale gas wells producing between 50 and 70 billion cubic feet of gas annually in Kentucky. Many of the wells are located in the Big Sandy gas field of Floyd, Knott, Letcher, Martin, and Pike Counties.[1] According to state regulators, the shales in Kentucky have more clay than most U.S. shales, discouraging hydrofracking in the state because water makes clay formations swell, inhibiting the release of gas. Therefore, most Kentucky gas wells are drilled using pressurized air circulated through the drill pipe and hydraulic fracture stimulation of natural gas wells using liquid nitrogen as the main ingredient.[2] Kentucky drillers use high-volume fracking, but more common are methods injecting nitrogen gas underground.[3] By 2012, the state had produced 6 trillion cubic feet of natural gas.[2] Shale gas production began in Kentucky in 1892 with the drilling of wells along Beaver Creek in Floyd county.[4] The Devonian Big Sandy shale gas play extends through Kentucky, Virginia and West Virginia, and ranges from 1,600 to 6,000 feet deep, with a thickness of 50 to 300 feet. Nitrogen fracturing has been the most commonly used well stimulation method there since 1978. [4] The Devonian-Mississippian New Albany Shale lays in the southeast Illinois Basin, encompassing  Illinois,  Indiana, and Kentucky. The New

Fracking in the USA 489 Albany has been a site for gas production for more than 100 years, but activity has increased with the development of new technologies for drilling. Wells are 250 to 2000 feet deep. Water contamination In May and July 2013, a worker for natural gas company Eagle Well Service in Eastern Kentucky claimed he dumped fracking wastewater into the Big Sandy River, under the orders of his bosses. The Big Sandy snakes through eastern Kentucky, acting as the natural divide between the state and West Virginia. When the state went out to investigate the claims they said they smelled strong petroleum and chloride odors in the area, and saw a sheen in the water. Kentucky regulators say the case is under investigation.[5]

2007 Spill A 2013 joint study from the U.S. Geological Survey and the U.S. Fish and Wildlife Service released found that a fracking fluid spill in Kentucky in 2007 likely caused the widespread death of several types of fish. Kentucky-based oil and gas exploration company Nami Resources Company spilled fracking fluid from four well sites into the Acorn Fork Creek in southeastern Kentucky in May and June 2007. Not long after, nearly all the aquatic life in the area died, including at least two fish from a threatened species. Chemicals released during the spill included hydrochloric acid. After studying samples of the water and bodies of green sunfish and creek chub, government researchers concluded the spill acidified the stream and increased concentrations of heavy metals including aluminum and iron. Fish exposed to the water developed gill lesions and showed signs of liver and spleen damage.[6][7] Pipelines The Bluegrass Pipeline—put forward as a joint venture by Williams Companies Inc. and Boardwalk Pipeline Partners, LP—would carry an estimated 200,000 to 400,000 barrels a day of natural gas liquids from western Pennsylvania to Texas, running through 18 Kentucky counties. NGLSs (“wet” natural gas) include ethane, butane, propane, methane, and various solid chemicals, which would likely be shipped to overseas markets. Unless maintained under high pressure, the substances are highly flammable and explosive. Construction is expected to be completed by late 2015.[8]

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2015 Fracking May Lead Decline Visitation in Public Parks According to a study by researchers from the University of Florida, North Carolina State University, and Florida State University in August 2015,  hydraulic fracturing  in, or near, public park lands could prompt tourists to stay away. The study of 225 park users in Pennsylvania, Ohio, West Virginia, Kentucky, and  Tennessee  found more than a third say they would be unwilling to participate in recreational activities near hydraulic fracturing. Fifty-eight percent of the study’s participants claim they would support legislation prohibiting fracking near their favorite park.[9]

References 1. Is there fracking in Kentucky? Kentucky Waterways Alliance, accessed Jul. 2013. 2. Kristin Tracz,  Hydraulic fracturing rare in Ky., but Appalachian Forum poses questions about regulation and pollution of gas drilling, Appalachian Transition, Feb 24, 2012. 3. Zahra Hirji and Lisa Song, “Map: The Fracking Boom, State by State,” Inside Climate News, Jan 20, 2015. 4. Is there fracking in Kentucky? Kentucky Waterways Alliance, accessed Jul. 2013. 5. Kristen Kennedy, WKYT Investigates: Polluting the Big Sandy, WKYT, Jul. 8, 2013. 6. James Gerken, Study Finds Fracking Fluid From 2007 Kentucky Spill May Have Killed Threatened Fish Species, Huffington Post, Aug. 28, 2013. 7. Hydraulic Fracturing Fluids Likely Harmed Threatened Kentucky Fish Species, USGS, Aug. 28, 2013. 8. Andrew Morris,  Fracked Gas Pipelines Planned for Ohio and Kentucky, EcoWatch, Jun. 3, 2013. 9. Fracking may lead to decline in visitation in public parks, Tim Kellison, UF News, Aug. 27, 2015.

Louisiana In Louisiana, fracking is being used to access natural gas in the Haynesville Shale area in northwestern Louisiana, and to a lesser extent for oil in the Tuscaloosa Marine Shale that stretches across the middle part of the state.[1]

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Shale plays in Louisiana

In Louisiana, fracking is being used for the natural gas producing Haynesville Shale area in northwestern Louisiana and the Tuscaloosa Marine Shale that stretches across the middle part of the state and contains what is called Louisiana Light Sweet crude oil.[2] The Brown Dense shale area underlying Arkansas and northern Louisiana (ranging in vertical depths from 8,000 to 11,000 feet) is projected to be able to produce both oil and gas, the industry say it is too early to tell how much of the hard-toreach oil is recoverable.[3] Fracking in the 11,000-feet-deep Haynesville Shale in Louisiana started in northwest Louisiana in 2008.[4] Since then, over 2,200 wells have been

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drilled and are producing natural gas in the Haynesville Shale formation, with another 232 wells there awaiting completion, in the process of being drilled, or permitted (as of May 2013).[5] Another 16 producing wells have been drilled in the Tuscaloosa Marine Shale formation, which cuts across the center of the state. The formation underlies St. Tammany, Washington, and Tangipahoa parishes, as well as the parishes surrounding Baton Rouge.[5] Baton Rouge is home to the fourth largest refinery in the U.S. This ExxonMobil refinery processes more than 500,000 barrels of crude oil a day and sits on 2,100 acres.[6] By the late 1980s, major oil firms had largely sold their onshore assets to small independents, and moved their non-refinery operations offshore.[7] The Jurassic Haynesville Shale of northwest Louisiana has been a site for gas production since 1905, but has become a site for fracking since Cubic Energy drilled a well there in November 2007, followed by a March 2008 announcement by Chesapeake Energy that it had completed a Haynesville Shale gas well.[8] Geology.Com:  Haynesville Shale: news, map, videos, lease and royalty information OilShaleGas.com  - Latest News and Drilling dates on the Haynesville Shale Go Haynesville Shale, a forum for petroleum professionals and landowners to discuss the Haynesville shale. LNG terminals

Cameron LNG Cameron LNG is a wholly owned subsidiary of  Sempra Energy  (SRE), a California-based natural gas distribution and marketing company. It is a liquefied natural gas (LNG) receipt terminal situated on a 260-acre industrial-zoned site along the Calcasieu Channel in Hackberry, Louisiana. It is located 18 miles from the Gulf of Mexico and within 35 miles of five major interstate pipelines that serve nearly two-thirds of all U.S. natural gas markets. Construction at Cameron LNG started in August 2005 and commercial operations began in July 2008.[9] On January 17, 2012, the U.S. Department of Energy authorized Cameron LNG to export liquefied natural gas. The permit allows Cameron to ship up to 1.7 billion cubic feet a day of LNG to countries possessing

Fracking in the USA 493 free-trade agreements with the U.S. The permit is valid for 20 years after the first export shipment.[10] In February 2014, the DOE allowed Cameron LNG to export gas to countries that do not have a free-trade agreement with the United States.[11] In June 2014, the U.S. House of Representatives passed a bill 266 to 150 that will speed up the process of liquefied natural gas exports. The bill, sponsored by Rep. Cory Gardner (R-CO), allows the Department of Energy a mere “30 days to approve LNG exports to non-Free Trade Agreement countries after an environmental review of the LNG facilities”.[12] On April 16, 2012, the Federal Energy Regulatory Commission granted approval for Houston-based Cheniere Energy Partners to build the first liquefied natural gas (LNG) export terminal in the lower 48 United States. The $5 billion Sabine Pass LNG project to be located at an existing import terminal in Cameron Parish, Louisiana, along the Gulf Coast.[1] Construction is expected to begin in 2012, with LNG exports to begin in 2015. Cheniere has signed a contract with Bechtel Oil, Gas and Chemicals Inc. to build the facilities. Cheniere said it has signed LNG supply contracts with utilities in the United Kingdom, Spain, South Korea, and India -- Cheniere has Energy Department license to ship domestic gas to nations that are not U.S. free-trade partners. U.S. gas producers will have the capacity to export up to 18 million tons of LNG annually, worth about $1.7 billion at current prices.[13] It was FERC’s first authorization of a project of this kind, FERC said in an accompanying statement: “Today’s order finds that the project can be constructed and operated safely and with minimal environmental impacts.”[13] In its Sabine Pass order, FERC settled on the DOE’s earlier findings that increased LNG exports “will result in increased production that could be used for domestic requirements if market conditions warrant such use, and this will tend to enhance U.S. domestic energy security.” FERC also dismissed charges by the Sierra Club and the Gulf Coast Environmental Labor Coalition that the commission shortchanged its environmental and safety reviews, citing conditions that Cheniere comply with the federal Clean Air Act, including rules governing  greenhouse gas  emissions and the use of best available pollution control technology.[1] After securing a $2 billion investment in a February 2012 deal with private equity firm Blackstone Group, Cheniere is searching for an additional $3 billion to $4 billion to start construction. Cheniere is working with eight financial institutions to secure the additional financing: Bank of TokyoMitsubishi UFJ Ltd., Credit Agricole Corporate and Investment Bank, Credit Suisse Securities LLC, HSBC, J.P. Morgan Securities LLC, Morgan Stanley, RBC Capital Markets and SG Americas Securities LLC.[13]

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Trunkline LNG is a liquefied natural gas plant in Lake Charles, Louisiana. Trunkline LNG provides terminal service for shippers by receiving LNG at the facility for storage and delivering such LNG to shippers, either in liquid state or gaseous state after regasification.[14] The Phase I expansion, which included a second ship berth and a new LNG storage tank that increased terminal storage capacity to 9 billion cubic feet (250,000,000 m3), was placed in service on April 5, 2006. Trunkline LNG completed the Phase II terminal expansion in early July 2006, increasing sustained sendout capacity to 1.8 billion cubic feet per day (51,000,000 m3/d) and peak sendout capacity to 2.1 BCF/d. The Phase II expansion also included the construction of unloading capabilities at the terminal’s second dock.[15] Environmental and health effects A confidential industry study from 1990 conducted for the  American Petroleum Institute, concluded that “using conservative assumptions,” radium in drilling wastewater dumped off the Louisiana coast posed “potentially significant risks” of cancer for people who eat fish from those waters regularly.[16] Pipelines The Bluegrass Pipeline—put forward as a joint venture by Williams Companies Inc. and Boardwalk Pipeline Partners, LP—would carry an estimated 200,000 to 400,000 barrels a day of natural gas liquids (NGL) from western Pennsylvania to Texas, and would convert a portion of Texas Gas in Eunice, LA (the TGT Loop Line) to NGL service. NGLSs (“wet” natural gas) include ethane, butane, propane, methane, and various solid chemicals, which would likely be shipped to overseas markets. Unless maintained under high pressure, the substances are highly flammable and explosive, necessitating construction of additional facilities throughout the South—including a facility in Louisiana. Construction is expected to be completed by late 2015.[17] Water Issues A 2015 Stanford study found that Louisiana, Arkansas, West Virginia, and Pennsylvania had the highest average water use per each hydraulic fracturing job.[18] Brine Drilling and brine mining is often considered the cause of the salt dome collapse that caused the Bayou Corne sinkhole 40 miles south of Baton

Fracking in the USA 495 Rouge. The sinkhole swallowed 15 acres. By 2014, it grew to 32 acres. Most of the residents living in the area have relocated.[19] On October 20, 2011, the Louisiana Department of Natural Resources adopted new rules for the oil and gas industry (fracking regulation are on page 3064). The new rules require an operator to obtain a work permit before engaging in hydraulic fracturing, and to publicly disclose the content of the fluids they use in the fracking process, although it allows exemptions for chemicals deemed trade secrets.[20] Citizen groups Go Haynesville Shale Green Army Industry groups Louisiana Mid-Continent Oil and Gas Association Louisiana Oil & Gas Association

References 1. Joel Kirkland,  NATURAL GAS: U.S. throws open doors to LNG exports with Cheniere approval, E&E News, Apr. 17, 2012. 2. Jordan Blum, Congressional hearings look at fracking, The Advocate, May 24, 2013. 3. Richard Thompson, New shale play in north Louisiana may hold oil, gas, The Times-Picayune, Sept. 11, 2011. 4. Map of high-profile fracking incidents in Louisiana, Earthjustice, accessed Jul. 2013. 5. Mark Schleifstein,  Shale fracking proves $30 billion-a-year boon to waste disposal industry, The Times-Picayune, May 20, 2013. 6. Ken Silverstein, Dirty South: The foul legacy of Louisiana oil, Harper’s, Nov. 2013. 7. Ken Silverstein, “Dirty South: The foul legacy of Louisiana oil,” Harper’s, Nov. 2013. 8. Louise S. Durham, Louisiana play a ‹company maker›, AAPG Explorer, Jul. 2008, p.18-36. 9. One of the First New Liquefied Natural Gas Receipt Terminals in North America, Cameron LNG: About Us, accessed Apr. 2012. 10. Ben Lefebvre,  Cameron LNG Receives Liquefied-Natural-Gas Export Permit, Dow Jones Newswires, Jan. 20, 2012. 11. Hannah Northey, DOE approves 6th export application, E&E News, Feb. 11, 2014.

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12. U.S. House Approves Faster LNG Exports, Brandon Baker, EcoWatch, Jun. 26, 2014. 13. Luke Johnson,  The Federal Energy Regulatory Commission (FERC) approved on Monday Cheniere Energy’s plans to liquefy and export natural gas, clearing the way for the Houston-based company to be first US LNG exporter in decades, stream, Apr. 16, 2012. 14. infopost.panhandleenergy.com 15. panhandleenergy.com 16. Ian Urbina, Regulation Lax as Gas Wells’ Tainted Water Hits Rivers, New York Times, Feb. 26, 2011. 17. Andrew Morris,  Fracked Gas Pipelines Planned for Ohio and Kentucky, EcoWatch, Jun. 3, 2013. 18. Evan Hansen, Dustin Mulvaney, and Meghan Betcher,  The Depths of Hydraulic Fracturing and Accompanying Water Use Across the United States, Environmental Science & Technology, Jul. 2015. 19. Emily Lane, Bayou Corne sinkhole: Texas Brine seeks permit to discharge wastewater at site, residents speak out, NOLA.COM, Sept. 12, 2014. 20. Department of Natural Resources adopts new rules requiring companies that engage in fracking to disclose the chemicals used, and to obtain a work permit, jonesswanson.com, Dec. 2, 2011.

Maine Before U.S. and Canadian moratoriums were put in place to protect the fishing grounds, five oil wells were drilled offshore on the U.S. side of Georges Bank in 1981 and 1982.[1] In May 2015, Rockland residents raised environmental concerns at natural gas forum about Rockland Energy Center, a subsidiary of Energy Management’s proposed natural gas fired power plant. Community members expressed their concerns about the plant would be powered by gas that would come from fracking.[2] The Associated Press reports that fracking is a cause of the high price of firewood in the Northeast. Well pads construct mats made of hardwood logs.[3] Offshore In November 2015, Shell Canada began drilling two wells an off coast of Maine and Nova Scotia in Canadian waters. Statoil and Canada-Nova Scotia Offshore Petroleum planning oil drilling off the coast of Maine, near Shell’s lease also in Canadian waters.[4] The Portland Press Herald reported that Colorado-based Summit Natural Gas of Maine spending millions on advertising on web, print, radio, TV

Fracking in the USA 497 to assuage fears among Main homeowners of hydraulic fracturing and to forward the idea natural gas it is safe, reliable, and priced fairly. It wanted customers to foot the cost of that campaign. The company has told the Public Utilities Commission that advertising aimed at buyers is in their “best interest.” Bill Black, general counsel at the Maine Office of Public Advocate, challenged is seeking justifications to why Summit Natural Gas can recover their advertising costs by natural gas customers.[5]

References 1. Colin Woodard, “Nova Scotia approves oil exploration lease next to Georges Bank, entrance to Gulf of Maine,” Portland Press Herald, Dec. 1, 2015. 2. Stephen Betts, “Fracking contributes to firewood costs,” Bangor Daily News, May 26, 2015. 3. Fracking contributes to firewood costs, Associated Press, Oct. 31, 2015. 4. Colin Woodard, “Nova Scotia approves oil exploration lease next to Georges Bank, entrance to Gulf of Maine,” Portland Press Herald, Dec. 1, 2015. 5. Tux Turkel, “Summit Natural Gas wants customers to foot bill for ad campaign,” Portland Press Herald, May 14, 2015.

Maryland Maryland Gov. Martin O’Malley has called for a detailed study of potential drilling impacts on the state, to be finished by 2014. Until then, O’Malley has said he will not allow gas drilling companies to deploy fracking in the state, putting on hold permits to drill for natural gas in Marcellus Shale formations in Garrett and Allegany counties in western Maryland.[1][2] Marcellus Drilling News has said there are only two counties in Maryland where fracking would occur: Allegany and Garrett, located at the interior of Maryland and thus not including areas within the Maryland portion of the Chesapeake Bay Watershed. However, a 2012 assessment published by the U.S. Geological Survey of shale basins along the East Coast stated there are several other shale basins, notably the Taylorsville and Delmarva basins, where there is “likely recoverable shale gas in quantity.” Basins identified by the USGS include the Gettysburg, which stretches south from the Pennsylvania border, passing beneath Frederick; the Taylorsville, which stretches south from beneath Annapolis to the lower Potomac; the Del Marva, which consists of several separate rock formations beneath much of the Bay and the Eastern Shore; and the Culpeper, which stretches north

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from Virginia under western Montgomery County near Gaithersburg and north to Frederick.[3] Maryland Gov. Martin O’Malley has called for a detailed study of potential drilling impacts on the state, to be finished by 2014. Until then, O’Malley has said he will not allow gas drilling companies to deploy fracking in the state.[4][5] “Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland” was released in March 2013; the authors say that until fracking can be done safely near drinking water sources, drilling shouldn’t be allowed within 2,000 feet of the surface. They also say wells should be closed-loop systems so that any spills can be contained, and that there should be no net loss of forestland. No drilling permits can be issued until the panel issues its final report in August 2014. In June 2013, the Maryland Department of the Environment (MDE) and the Department of Natural Resources (DNR) released a draft report (dated August 2013) of  “Best practices for drilling and production”  that they say should be required if horizontal drilling and hydraulic fracturing for natural gas is permitted in the Marcellus shale in Maryland. In November 2014, the O’Malley administration released its report on fracking impacts in the state, which declared that hydraulic fracturing in Western Maryland could be done safely. The report stated that fracking could support nearly 3,400 jobs and generate millions in tax revenues. O’Malley also stated that he plans to enact the strictest fracking regulations of any state in the country. The administration admitted that fracking “no doubt” has environmental and health impacts, but noted that proper safeguards can protect the public.[6] Dominion Cove Point received authorization on October 7, 2011, from the Department of Energy to enter into contracts to export liquefied natural gas to countries that have free trade agreements with the United States. Under the authorization, Dominion is permitted to enter into multi-year contracts up to 25 years long with companies wishing to export natural gas to countries with free trade agreements. The authorization is for up to 1 billion cubic feet per day, using liquefaction equipment at the Cove Point facility to convert natural gas into liquefied natural gas. On October 3, 2011, Dominion filed a second application with the Department of Energy, requesting authorization to export to additional countries not included in the first application. In this application, Dominion said exports would be in the public’s interest because studies show they could provide an “enormous economic stimulus, provide energy price stability, promote the continued development of domestic natural gas

Fracking in the USA 499 and natural gas liquids, create thousands of new jobs in the oil and gas industry, increase tax revenues and improve the balance of trade.”[7] On February 6, 2012, the Sierra Club filed a motion to intervene with the Department of Energy, protesting the export of  Marcellus Shale gas (among other sources) from the Cove Point facility, saying it would raise gas and electricity prices nationally and expand damaging extraction practices in the shale plays. The group also called for a full environmental impact study (EIS) on the effects of (and alternatives to) the increased Marcellus extraction embodied in the export proposal - such an EIS would be the first full EIS on Marcellus shale fracking. Legislative issues

State HB 1204, the Marcellus Shale Safe Drilling Fee - passed by the House of Delegates on March 20, 2012, the bill would require energy companies to fund studies related to drilling best practices and environmental protection in western Maryland before gas extraction can start. Hydraulic fracturing for natural gas is not yet permitted in Maryland. An executive order from Gov. Martin O’Malley in June 2011 created a 14-member commission to study various safeguards – including the impact of fracking on the environment and climate change. However, that commission has no funding to conduct necessary studies. HB 1204 would create a oneyear fee of $15 per acre on land already leased in western Maryland for potential fracking activity, which would generate at least $1.8 million.[8] On March 26, 2012, the House voted 82-51 to pass a 7.5 percent state severance tax, cutting the initially proposed tax in half.[9] The gas industry opposed the bill, and it failed to pass the 2012 legislative session ending in April. The O’Malley administration said it would seek to pursue the study with available funds, and suggested it may therefore take longer to finish -- meaning the de-facto drilling ban may be extended as well. Del. Heather Mizeur (D-Montgomery) chief sponsor of the fee bill and other ‘fracking’ measures, said she may push for a permanent ban on fracturing in the face of the industry’s opposition to the fee bill.[10]

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Federal The Fracturing Responsibility and Awareness of Chemicals Act (H.R. 2766), (S. 1215)--was introduced to both houses of the United States Congress on June 9, 2009, and aims to repeal the exemption for hydraulic fracturing in the Safe Drinking Water Act.[11] The Marcellus Shale Safe Drilling Act of 2011 (HB852/SB634) requires the Maryland Department of the Environment to conduct a study to assess impacts of drilling on the environment and local communities before drilling permits are issued.[12] Citizen groups Chesapeake Climate Action Network CitizenShale In a draft report released in October 2014, Maryland environmental regulators wrote that there was little risk of water contamination from hydraulic fracturing for natural gas in western Maryland.[13]

References 1. Dusty Horwitt, Federal Scientists Warn NY of Fracking Risks, Environmental Working Group, Feb. 22, 2012. 2. Martin O›Malley, Governor of Maryland, Executive Order 01.01.2011.11, The Marcellus Shale Safe Drilling Initiative, Jun. 6, 2011. 3. Wenonah Hauter and Shane Robinson, Got Shale? What Marylanders Should Expect Without a Permanent Ban on Fracking for Shale Gas, Huffington Post, Jul. 29, 2012. 4. Dusty Horwitt, Federal Scientists Warn NY of Fracking Risks, Environmental Working Group, Feb. 22, 2012. 5. Martin O›Malley, Governor of Maryland, Executive Order 01.01.2011.11, The Marcellus Shale Safe Drilling Initiative, Jun. 6, 2011. 6. Timothy B. Wheeler, “O’Malley administration sets out path to fracking in Md.,” The Baltimore Sun, Nov. 25, 2014. 7. Dominion Receives DOE Authorization to Export LNG, Dominion: LNG Exports, accessed Feb. 2012. 8. Maryland House Votes to Require Energy Companies to Fund Safety Studies on Natural Gas Fracking, Chesapeake Climate Action Network and CitizenShale, Mar. 20, 2012.

Fracking in the USA 501 9. Md. House passes tax for Marcellus Shale, Boston.com, Mar. 27, 2012. 10. Tim Wheeler,  Mixed green bag: Bay bills advance, energy measures stumble, The Baltimore Sun, Apr. 10, 2012. 11. The ‹Fracking› Of Ohio State Parks, Progress Ohio, Mar. 16, 2011. 12. Hydrofracking: Is it Safe? Sierra Club, accessed Feb. 2012. 13. David Dishneau, “Maryland sees little risk to water from fracking,” Seattle Post-Intelligencer, Oct. 3, 2014.

Massachusetts Western Massachusetts might have the right geology to host small shale gas deposits, according to the USGS. In 2012, the group American Ground Water Trust said small-scale gas development could begin in several years. However, as of 2012, no companies have expressed interest in exploring for shale gas, state officials say, and the type of wells needed to get to the gas, if any is found, are prohibited by the state’s underground injection control regulations (although the rules do not specifically mention fracking).[1][2] Part of Massachusetts is underlain by a geological feature known as the Hartford Basin, stretching 34 miles long in Massachusetts and varying in width from three to 15 miles. The entire basin lies under the Connecticut Valley from roughly the Vermont border to the Connecticut shoreline. Geologists say that extractable shale gas deposits in the Hartford Basin are highly unlikely: a good portion of the basin was overheated from volcanic activity, which likely vaporized any oil or gas, while other places were not heated enough to produce gas. Geologists therefore say it is highly unlikely that exploration would occur for shale gas in the valley because current data strongly suggest that the source rocks for any deposits, if present, are too small, scattered, and of questionable quality.[1][2] Texaco did exploratory geophysical work in the 1970s, and then paid for work in the 1980s to examine the hydrothermal history of the Connecticut Valley, but no further exploration took place.[1][2] In June 2012, a US Geological Survey  report  assessed five East Coast basins, but noted the Hartford Basin as among a number they did not examine due to insufficient data.[2] Many media outlets claim this report as documenting the discovery of shale gas in the Hartford basin. The report does not. Urban Methane Leakage Boston area infrastructure loses two to three times more gas than state authorities say, adding to evidence of downstream operations’ (including

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pipelines, storage terminals and power plants) role in greenhouse emissions according to a study published in January 2015 Proceedings of the National Academy of Sciences.[3] This is the first peer reviewed study that quantifies emissions of methane, a gas is roughly 86 times as potent as carbon dioxide as a driver of climate change over a period of 20 years, from natural gas operations in urban centers.[4] Many previous studies focused on methane leaks from the drilling and  hydraulic fracturing  wells. Less attention was given to natural gas storage and pipelines that deliver gas to homes. The university researchers estimate the amount of Boston area methane lost over a year in the study area to be worth $90 million.[5] LNG terminals

Everett Marine Terminal Everett Marine Terminal is located on the Mystic River in Boston Harbor, Massachusetts and has been operating continuously since 1971. Everett Marine is the longest operating import terminal in the U.S. The terminal is owned and operated by Distrigas of Massachusetts (DOMAC), a subsidiary of GDF Suez North America. It is reported that as of 2013 the terminal currently supplies about 20% of New England’s natural gas demand every year.[6]

Northeast Gateway Deepwater Port The Northeast Gateway Deepwater Port is located 13 miles from shore in Massachusetts Bay. The terminal is connected to the Northeastern natural gas grid through a pipeline lateral built by Algonquin Gas Transmission.[7] Legislative issues and regulations As of 2013, three bills have been filed in the Legislature to pre-emptively ban hydraulic fracturing, and one would require disclosures about what chemicals are being used in the fracking process. Although fracking would be prohibited by the state’s underground injection control regulations, legislators say the rules do not specifically mention fracking, requiring clarification.[8] In November 2013, the Massachusetts State Legislature’s Joint Committee on Environment and Natural Resources approved a bill that would place a 10-year moratorium on fracking in the Bay State — through December 31, 2024. In addition, the bill would keep fracking wastewater produced

Fracking in the USA 503 by operations in other states from being treated, stored, or disposed in Massachusetts. The bill would still need to have the full House and Senate pass it and Governor Deval Patrick sign it to become law.[9] The city of Amherst banned the use of  hydraulic fracturing  waste to thaw ice on roads in November 2015. The ban will eliminate crews using wastewater from the treatment plan on local roads. Reports Nathan G. Phillips, Robert Ackley, Eric R. Crosson, Adrian Down, Lucy R. Hutyra, Max Brondfield, Jonathan D. Karr, Kaiguang Zhao, and Robert B. Jackson,  “Mapping urban pipeline leaks: Methane leaks across Boston,” Environmental Pollution, Volume 173, Feb. 2013, Pages 1–4.

References 1. Beth Daley,  Western Mass. viewed as territory for fracking,  Boston Globe, Dec. 13, 2012. 2. Massachusetts Geological Survey, Frequently Asked Questions About Shale Gas and Hydraulic Fracturing in Massachusetts, Massachusetts Geological Survey FAQ, last dated 12/11/2012. 3. Lisa Song, “Methane Leaks From Gas Pipelines Far Exceed Official Estimates, Harvard Study Finds,” Inside Climate News, Jan. 28, 2015. 4. Bobby Magill, US ‹likely culprit› of global spike in methane emissions over last decade, The Guardian, Feb. 17, 2017. 5. Lisa Song, “Methane Leaks From Gas Pipelines Far Exceed Official Estimates, Harvard Study Finds,” Inside Climate News, Jan. 28, 2015. 6. Thomas Overton, “Everett LNG Terminal at the Crossroads,” Power, Jul. 2, 2013. 7. Northeast Gateway Deepwater Port,  Excelerate Energy, accessed Sept. 28, 2015. 8. Cole Chapman, Three bills aim to bar ‹fracking,› Daily News, Feb. 18, 2013. 9. Why Massachusetts Might Ban Fracking Even Though There’s No Fracking In Massachusetts, Climate Progress, Dec. 2, 2013.

Michigan As of September 2012, the Michigan Department of Environmental Quality (DEQ) listed 40 permits and 15 applications for high volume hydraulic fracturing operations in the state. The main operating companies are Devon Energy and Encana Oil and Gas.[1]

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Antrim Shale, Michigan The Antrim Shale of per Devonian age contains oil and gas along a belt across the northern part of the Michigan Basin.[2]  Although the Antrim Shale has produced gas since the 1940s, the play was not active until the late 1980s. Unlike other shale gas plays such as the Barnett Shale, the natural gas from the Antrim appears to be biogenic gas generated by the action of bacteria on the organic-rich rock.[3] In 2007, the Antrim gas field produced 136 cubic feet of gas, making it the 13th largest source of natural gas in the United States. The Collingwood and Utica formations extend across much of the northern Lower Peninsula of the state, at depths ranging from 10,000 to 12,000 feet.[3] Fracking operations By April 2012, oil companies signed 167 leases with people in Michigan’s Barry County, compared to 81 signed in 2011. The leases give the oil companies permission to frack the land looking for oil. In Barry County, leases typically range from $10 to $80 per acre per month.[4] Encana Oil & Gas intends to frack 13 new wells in Kalkaska County, Michigan in search of natural gas. The operation will require more than 300 million gallons of groundwater for production. Critics contend that Michigan Department of Environmental Quality officials do not adequately regulate drilling wells, and that Encana’s wells fail a water withdrawal assessment measurement, designed to protect the state’s water resources.[5] On September 3, 2013, Texas-based GeoSouthern Energy received state approval to inject 3 million gallons of fracking fluid for oil and gas into a 1-mile geological formation in Conway Township.[6] There are also high-volume fracturing projects in Ionia County, Hillsdale County, and Sanilac County. The majority of high-volume fracturing permits is in central and northern Michigan.[6] Waste Disposal In 2014, U.S. Ecology came under fire for its expansion plans and handling of hydraulic fracturing’s radioactive sludge from out of state at its Wayne Disposal, Inc. facility in Belleville, MI. Wayne Disposal is one of only 17 sites in the U.S. qualified to handle such wastes, also called technologically enhanced naturally occurring radioactive material (TENORM). U.S. Ecology agreed to halt a shipment of  hydraulic fracturing  waste from Pennsylvania until a panel appointed by Michigan Governor Rick

Fracking in the USA 505 Snyder had reviewed the waste transaction. After four months of review, the panel decided in February 2015 that U.S. Ecology could accept the shipment. In fall 2015, controversy ensued over the expansion of operations at a hazardous waste plant called U.S. Ecology in Detroit near Hamtramck, MI, which has raised concerns among neighbors that Detroit is being used as a dumping ground for out of state fracturing operations.[7] Lobbying and donations The 2011 Common Cause report,  “Deep drilling, deep pockets, in Washington and Michigan,” found that from 2001 through June 2011, the fracking industry gave $20.5 million to current members of Congress and spent $726 million on lobbying.” For Michigan, Rep. John Dingell was the top recipient with $203,453, followed by Rep. Dave Camp with $154,627, and Rep. Fred Upton with $153,917. Rep. Upton chairs the House Energy and Commerce Committee, where the FRAC Act, which would require drillers to disclose the chemicals used in fracking, has been stalled. The report also tracked $2.2 million in campaign contributions to Michigan’s state elected officials, and $2.8 million spent on lobbying in Michigan. State Treasurer and former House Speaker Andy Dillon was the leading recipient with $128,500, followed by former Gov. Jennifer Granholm with $98,800, former Attorney General Mike Cox with $76,250, and Gov. Rick Snyder with $61,900.[8]

Price Fixing Allegations In June 2012, Reuters reported that, under the direction of CEO Aubrey McClendon,  Chesapeake Energy  plotted with top executives of competitor Encana to suppress land prices in the Collingwood Shale formation in Northern Michigan. In emails between Chesapeake and Encana Corp, the rivals discussed dividing Michigan counties and private landowners to avoid bidding against each other in a 2010 public land auction and in at least nine prospective private deals. Price-fixing between competitors is illegal under the Sherman Antitrust Act. In Michigan alone, the two companies combined now hold more than 975,000 acres of land - an area about the size of Rhode Island.[9] Citizen activism In February 15, 2013, it was reported that Michigan’s Board of State Canvassers approved a ballot initiative petition on fracking by Committee

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to Ban Fracking in Michigan, a ballot question committee. A second approval was given on April 17, 2013 for a revised ballot wording. The Committee’s ballot initiative is a “legislative proposal,” a process spelled out in the Michigan state constitution, that allows citizens to write their own law, collect signatures from Michigan voters and put the proposal before voters at the next statewide election in November 2014. Reuters reported that, “The Committee to Ban Fracking in Michigan is proposing a voter initiative to amend state law and ban fracking, a form of natural gas extraction.” The ballot initiative language is available on the Michigan Secretary of State’s website.[10] Committee to Ban Fracking in Michigan is a citizenled ballot initiative.[11] The proposal would prohibit horizontal hydraulic fracturing and horizontal hydraulic fracturing wastes, and eliminate the state›s policy of fostering the natural gas industry along the most favorable conditions to maximize production of natural gas and oil. Legislative issues and regulations The Michigan DEQ defines high-volume hydraulic fracturing as fracturing that injects 100,000 gallons or more of fluid into the ground. As of 2011, the DEQ has put stricter provisions on high-volume projects, including some disclosure of the chemicals used and injection-pressure monitoring, according to the DEQ. (Smaller-volume hydraulic fracturing, considered projects using less than 100,000 gallons of fluid, dates back to the 1960s in Michigan.)[6] Democrats in the state House have introduced bills to regulate fracking, while some concerned citizens have collected signatures for a ballot initiative to ban it.[12] In September 2013, the University of Michigan released a study on fracking in the state “to provide information to guide legislators and other policymakers.” The study included seven technical reports on topics ranging from production technology to Michigan’s geological features and environmental and public health issues. The study found that the state had plenty of water for fracking but also so many interconnected waterways it would make it difficult to contain chemical spills and leaks. The report concluded that low prices for gas and high costs of retrieving it from deep rock offer little incentive for major development in the state in the near future. A 2014 report will offer policy options.[12] Two of the steering members on the University of Michigan study personally contributed to the Michigan Chamber of Commerce’s ballot question committee, which ran a campaign against the ballot initiative for a fracking moratorium with a campaign of their own called “Protect Michigan’s Energy Future.”[13]

Fracking in the USA 507 Citizen groups The Committee to Ban Fracking in Michigan Ban Michigan Fracking Michigan Land Air Water Defense

References 1. DEQ Well completing active permits and applications, DEQ list, accessed Sept. 2013. 2. Michigan DEQ map: Antrim, PDF file, downloaded 12 Feb. 2009. 3. John Flesher,  Study: New gas development boom unlikely in Michigan, Associated Press, Sept. 5, 2013. 4. Dave Spencer, Oil Companies Flocking to Frack in Barry County: Some are calling it a win-win others raise health concerns over fracking, Fox, Apr. 30, 2012. 5. Glenn Puit, “More fracking wells planned,” Record-Eagle, Mar. 24, 2013. 6. Christopher Behnan,  ›Fracking› debate erupts: Landowners and environmentalists worry about effects, Livingston Daily.com, Sept. 12, 2013. 7. Jim Lynch, Hazardous waste facility’s expansion prompts worries, The Detroit News, Sept. 24, 2015. 8. James Browning & Alex Kaplan, Deep drilling, deep pockets, in Washington and Michigan, Common Cause, 2011. 9. Brian Grow, Joshua Schneyer, and Janet Roberts, Special Report: Chesapeake and rival Encana plotted to suppress land prices, Reuters, Jun. 25, 2012. 10. Michigan Secretary of State, [1].” 11. Committee to Ban Fracking in Michigan, [2].” 12. John Flesher,  Study: New gas development boom unlikely in Michigan, Associated Press, Sep. 5, 2013. 13. UM Graham Researchers In Financial Conflict Re Fracking, Ban Michigan Fracking, Sept. 12, 2013.

Minnesota Fracking for oil has grown in neighboring North Dakota, and much of the sand used in the fracking process is coming from Minnesota. A fracked well can use approximately 10,000 tons of industrial silica sand to prop open fissures and increase the flow of fluids and gas within a well. As of February 2013, there are eight silica sand mines in Minnesota.[1] In response to the increased demand for sand from fracking, companies are seeking permits from local governments for new silica sand mines and

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to expand existing mines in the state, as it is up to counties and townships to regulate silica mining in their area. Opponents have called for a statewide moratorium until permitting is established, and some cities are banning mining expansion until regulations are put into place.[1] Four counties, Goodhue, Wabasha, Houston, and Fillmore, have moratoria on new permits for industrial silica sand mining.[2] Pipelines In November 2013, Enbridge filed an application to build a $2.5 billion oil pipeline called Sandpiper across northern Minnesota. The 610-mile line would carry more than 200,000 barrels of tight oil per day from western North Dakota›s Bakken shalefields to the company’s terminal in Superior, Wisconsin. Enbridge has proposed two routes for the new line. One would follow its existing pipeline corridor. However, the company’s preferred Minnesota route cuts a new path south to Park Rapids before turning east toward Superior, through Carlton County. The Minnesota Public Utilities Commission will weigh landowner and farmowner concerns against the need for Sandpiper - one of three proposed new pipelines from North Dakota that could cut across the state in coming years. If the PUC approves, Enbridge plans to begin building by late 2014, and landowners would not be able to say no to the pipeline running on their property.[3] Frac sand operations Sand has been mined in Minnesota for more than a century. Round silica sand beneath the bluffs near the Mississippi River in southeastern Minnesota and western Wisconsin has been mined to make window glass, water filtration products, and abrasives. Recently, several Minnesota communities have passed moratoriums on mining so they can study the practice, which has already impacted parts of Wisconsin. Currently, the Minnesota Pollution Control Agency along with other state agencies are in the process of writing new rules for frac sand mining as part of a plan ordered by the State Legislature.[4] Goodhue County in Minnesota has enacted frac sand moratoriums, citing a lack of studies on impacts on such mining, such as pollution and road safety.[5]

References 1. Tim Blotz, Frac sand concerns heard at Minnesota Capitol, KMSP TV, Feb. 19, 2013.

Fracking in the USA 509 2. Industrial Silica Sand: Frequently Asked Questions and Answers, MN DNR, dated Oct. 31, 2012. 3. Dan Kraker,  Enbridge files application to run pipeline across northern Minnesota; opponents gird for fight, Minnesota Public Radio, Oct. 28, 2013. 4. Frac Sand Mining Frac Sand Mining, MPR News, May 2013. 5. Goodhue Co. extends frac sand moratorium, Elizabeth Dunbar, MPR News, Aug. 6, 2013.

Mississippi In 2011,  Devon Energy  and  Encana  began drilling in the Tuscaloosa Marine Shale (TMS) play, an “unproven unconventional 7 billion barrel oil resource” spanning the central Louisiana and southwestern Mississippi counties of Amite, Wilkinson, Adams, Franklin, Pike, and Walthall, for a total of 2.7 million acres (the term “play” refers to a geographic area targeted for exploration).[1] In February 2012, Amite County said it would study oil shale and shale gas  development in southwest Mississippi. It will focus on Tuscaloosa Shale production in Amite, Pike and Wilkinson counties - a large formation covering central Louisiana and parts of southwest Mississippi that oil companies have been working at for months. Pike County Economic Development District executive director Britt Herrin says there are hundreds of wells that could be drilled.[2] On March 21, 2012, Mississippi Governor Phil Bryant unveiled plans to incorporate natural gas as a “priority” in a new statewide energy policy that he is developing along with local business leaders, including Clean Energy Fuels’ T. Boone Pickens. Clean Energy Fuels plans to build a station in Pearl before 2014, absorbing the $2 million start- cost while promoting state and commercial vehicles run on natural gas - which the company would supply. Bryant said other businesses have shown interest in building stations in Harrison and Jackson counties.[3] The Clarion Ledger reported that two dozen wells had been fracked between 2007 and 2014.[4] In 2014, Mississippi produced 2,416,400 barrels (101.5 million gallons) of crude oil.[5] In December 2014, CBS News reported that high oil prices threatened Mississippi’s fracking industry.[6] Water Issues The Associated Press reported in 2014 that the Tuscaloosa Marine shale formation takes six to eleven million gallons water for hydraulic fracturing one oil well.[7]

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LNG terminal Gulf LNG is an LNG unloading, storage and regasification facility located near the City of Pascagoula in Jackson County, Mississippi. Gulf LNG is owned by Gulf LNG Energy, LLC (GLE). The terminal includes a 5-mile sendout pipeline.[8] The terminal became operable in 2011.[9] Citizen groups Go Haynesville Shale Gulf Restoration Network

References 1. Amy McCullough,  Companies exploring for oil in Southwest Mississippi, Business Blog, Aug. 19, 2011. 2. Amite County, Mississippi, OKs fracking study, Associated Press, Feb. 8, 2012. 3. Mississippi governor unveils plans for natural gas use, Clarion Ledger, Mar. 21, 2012. 4. Ernest Herndon, “Where will water come from for fracking?,”  Clarion Ledger, Jun. 14, 2014. 5. U.S. Energy Information Administration, Petroleum & Other Liquids, Eia. gov, Retrieved Oct. 31, 2015. 6. Manuel Bojorquez, “Low oil prices threatening fracking industry,” CBS, Dec. 19, 2014. 7. Where will water come from -- and where will it go -- in Mississippi oil fracking boom? Associated Press, Jun. 15, 2014. 8. Gulf LNG, Kinder Morgan, accessed Sept. 25, 2015. 9. Cherle Ward, “Gulf LNG Energy terminal officially opens,”  GulfLive.com, Oct. 28, 2011.

Missouri Although the U.S. shale oil and gas drilling boom has largely bypassed Missouri, the energy industry is reportedly considering the state to mine for silica sand, used to prop open shale rock cracks during hydraulic fracturing.[1] Silica for fracking Energy companies say Missouri’s sand is nearly pure silica, or quartz, which allows the grains to maintain their shape under the pressure thousands of

Fracking in the USA 511 feet below ground. The sand grains are also nearly spherical, allowing them to flow more easily through fractures. And the silica could be stored and transported along the Mississippi River. According to E&E News: “Missouri’s sand comes from the St. Peter Sandstone, a layer of crumbly rock that extends from Minnesota to Arkansas. That same formation has helped drive a major frac sand boom in Wisconsin. At least 100 Midwestern sand mines rely on the sandstone. “The major player in Missouri is Mississippi Sand LLC, a venture formed in 2008. The company has seen tremendous success with its quarry near Festus, Mo., and is looking to develop a new mine near Starved Rock State Park in Ottawa, Illinois. “But that plan is facing a level of environmental opposition the company has not seen in Missouri. Environmental groups say such mines pose health risks, particularly for workers who might inhale silica. If inhaled, the material can lead to silicosis, an irreversible lung disease that has been linked to lung cancer.” Besides Mississippi Sand, other Missouri operators include Marylandbased U.S. Silica and Texas-based FTS International LLC.[2]

References 1. Mo. jumps into shale boom with frac sand mining, E&E News, Nov. 6, 2012. 2. Mo. jumps into shale boom with frac sand mining, E&E News, Nov. 6, 2012.

Montana Shale oil and gas drilling is increasing across Montana in the Bakken formation, in Sweet Grass and Park counties, the Heath shale below Garfield, Fergus, Petroleum and Rosebud counties, and under the Blackfeet reservation.[1] Montana has been increasing permits to explore state and private land along the Rocky Mountain Front. Companies are hoping to find that oil in the Bakken shale formation, in North Dakota and eastern Montana, extends westward to the eastern flank of the Rocky Mountains.[2] In 2010, total natural gas production in the state was 70,175,944 MCF (thousand cubic feet), 10.74 percent less than the previous year, while oil was 25,323,108 barrels.[3] Fracking in Montana is currently taking place in Sweet Grass and Park counties.[4]

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Citizen activism In January 2014,  Montana Environmental Information Center  (MEIC) sued Montana Attorney General Tim Fox in order to gain access to certain documents related to the public position he took on hydraulic fracturing.  [5]  In April 2014, just a day before a judge was to hear oral arguments in the case, Attorney General Tim Fox turned over the records MEIC demanded access to. It was not known at the time exactly what information the documents contained.[6] Legislative issues and regulations The Montana Board of Oil and Gas Conservation (MBOGC) adopted new rules governing fracking that became effective on August 26, 2011. Operators of fracking sites must now obtain approval from MBOGC prior to drilling. In addition, natural gas operators must now disclose the composition of the fracking fluids used (if a trade secret exemption is not applicable). The MBOGC also mandates specific construction and testing requirements for wells that will be fracked.[7] Water Pollution The rules have exemptions on chemical disclosure: Operators must disclose the chemical family, but not the exact chemical name, and well operators can decide whether products or chemicals are proprietary.[8] Environmental groups have challenged the nondisclosure of fracking fluids as proprietary “trade secrets”, which they say has too broad of a definition: “We are not satisfied. We’re definitely happy that the state is finally getting around to doing this, but the current regulations are fairly deficient,” Derf Johnson, program assistant at the Montana Environmental Information Center.[9] In September 2013, it was reported that Montana’s Attorney General would join Alabama, Alaska and Oklahoma in protesting Bureau of Land Management plans to regulate hydraulic fracturing on federal land.[10] Bakken Formation Wells have been drilled along the  Bakken formation  in Montana, with active wells also in North Dakota. Industry experts say oil appears to extend from the Bakken formation of eastern Montana into Alberta, Canada, and south to the foot of the Rocky Mountains. Hydraulic fracking will likely be used to extract the oil, if found. Land leases for fracking in the region have increased dramatically in recent years. The first commercial Bakken well at Elm Coulee, located in Richland County, Montana, was completed in 1981 by  Coastal Oil and Gas. As

Fracking in the USA 513 of 2007 the total number of horizontal Bakken wells drilled in the Elm Coulee area was more than 500 and included more than 800 lateral drill locations.[11]

Oil Production Estimates The largest Bakken oil production comes from Elm Coulee Oil Field, in Richland County, Montana, where extraction began in 2000 and is expected to ultimately total 270 million barrels (43,000,000 m3). In 2007,  shale oil from Elm Coulee averaged 53,000 barrels per day (8,400 m3/d) — more than the entire state of Montana a few years earlier.[12] Interest in North Dakota over Montana developed in 2007 when EOG Resources of Houston, Texas reported that a single well it had drilled into an oil-rich layer of shale below Parshall, North Dakota was anticipated to produce 700,000 barrels (110,000 m3) of oil.[13]  This, combined with other factors, including an oil-drilling tax break enacted by the state of North Dakota in 2007,[14] shifted attention in the Bakken from Montana to the North Dakota side. The number of wells drilled in the North Dakota Bakken jumped from 300 in 2006, with oil production in the North Dakota Bakken increasing 229%, from 2.2 million barrels (350,000 m3) in 2006 to 7.4 million barrels (1,180,000 m3) in 2007.[15]to 457 in 2007.[16] The bakken formation was deposited in the more central and deeper portion of the williston basin. Saskatchewan Manitoba

Bakken formation Minnosota North dakota n

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In April 2013, a government study doubled its estimates for the Bakken’s recoverable crude supplies. The U.S. Geological Survey estimated 7.4 billion barrels of undiscovered, technically recoverable oil in its study.[17]

Bakken Land Leases Small and independent oil companies that made their start developing natural gas resources moved into the Bakken and accumulated acreage before the oil boom in the area. As such, the most sought after lands have already been leased for development. New Entrants into the Bakken must participate in joint ventures or buy out another company. This has not discouraged investment as several billion dollars were exchanged in mergers and acquisitions in the Bakken in the fourth quarter of 2010 alone.[18]

Labor Issues According to the investigative journalism organization, Reveal, from 2006 to 2015 there have been at least 74 workplace deaths in the Bakken formation.[19]

Keystone XL Pipeline In 2012,  TransCanada  included an “on-ramp” in its  Keystone XL Pipeline proposal that would transport Bakken oil to the Gulf Coast. The oil is currently moved on rail cars, trucks, and smaller pipelines. The move is seen as a way for TransCanada to build support for the pipeline, which would primarily be used to transport Alberta’s tar sands from Canada to the U.S. Gulf Coast.[20] Fracking the Beartooth Front In October 2013, the Denver, Colorado based Energy Corporation of America’s (ECA) CEO John Mork announced that he’d like to “bring something like the Bakken” to Eastern Montana, near the town of Red Lodge. Mork also stated that if a fracking boom in the area would “fundamentally change these areas the way it has changed other areas of the United States.” ECA plans on developing up to 50 wells in two zones in the region. [21]   Despite the objection of 10 local landowners and local conservation

Fracking in the USA 515 organizations, ECA began its first drilling operation outside Belfry, Montana known as the Hunt Creek 1-H in May 2014.[22][23] Shortly after ECA began operating its Hunt Creek 1-H well, it was reported that “local farmers and members of Carbon County Resource Council filed a complaint to the Department of Natural Resources and Conservation (DNRC) to report the illegal use of water.” [22] On August 18, a group of Clarks Fork Valley landowners appealed to the Carbon County Commission in hopes of “creating a special zoning district that would protect them from the impacts of oil and gas development.” The group said they hoped to protect their land and the beauty of Montana while minimizing impacts from fracking.[24] Fracking Badger-Two Medicine The Badger-Two Medicine region at the nexus of the Blackfeet Indian Reservation, Bob Marshall Wilderson Complex, and Glacier National Park has been an attractive region for drilling and in recent years a hotbed of anti-drilling activism. Certain parts of the Blackfeet Indian Reservation have been opened to drilling. An Anschutz Exploration Corporation began drilling on the Blackfeet Indian Reservation near Browning in July 2012.[25] In the 1980s, Louisiana based Solenex LLC leased 6,200 acres in BadgerTwo Medicine in the Lewis and Clark National Forest. In 1985, most of the leases in the Badger-Two Medicine have been suspended when tribes and environmental activists raised concerns that they were granted illegally, without tribal consultation, and that their development would harm water quality and wildlife habitat, and disrupt the tribes’ hunting, fishing, timbering, and cultural and religious uses. Solenex’s leases remained. On June 2013, Solenex sued the federal government, alleging that it had unreasonably delayed the drillers right to develop its lease at Badger-Two Medicine.[26] All four bands of the Blackfoot Confederacy, tribal leaders in Montana and Wyoming, the National Congress of American Indians, rock band Pearl Jam, former Secretary of the Interior Bruce Babbitt, Sen. Jon Tester, D-Montana, several retired federal agency officials. The U.S. Department of Interior decided November 2015 to cancel leases that might have allowed a New Orleans based Solenex company to drill for oil on in the Badger-Two Medicine. Water

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Usage The 2013 Western Organization of Resource Councils report,  “Gone for good: Fracking and water loss in the West,” found that fracking is using 7 billion gallons of water a year in four western states: Wyoming, Colorado, Montana, and North Dakota.

Contamination Wastewater from oil drilling was injected into the Fort Peck Indian Reservation near Poplar, Montana, after oil drilling began at the nearby East Poplar oil field in 1952. When oil is produced, brine or produced water rich in salts and toxic metals also comes out of the ground. The oil companies injected the wastes back underground to a depth of between 800 and 1,000 feet, where it was assumed the material would stay put. But when scientists came back to the area and drilled 40 boreholes, they found the water was significantly contaminated. In 2010, they tested three public wells Poplar draws its water from and found that all were contaminated with brine. The pollution was due to a well casing failure of an injection well.[27] Forty million gallons of briny wastewater leaked on the Fort Peck Indian Reservation polluted a river, the municipal water system and private water wells in Poplar in Roosevelt County. The Associated Press reported that the residents thought the water unfit for human consumption. In 2012, oil companies settled to agreed to monitor the municipal water.[28] Citizen groups Big Blackfoot Riverkeeper Inc., Badger-Two Medicine Glacier – Two Medicine Alliance Northern Plains Resource Council Montana Board of Oil and Gas Conservation

References 1. Hydraulic fracturing and deep shale gas, Northern Plains Resource Council, accessed Mar. 30, 2012. 2. Nick Engelfried, “Fracking on the Front,” Explore Big Sky, Dec. 5, 2011. 3. Annual Review 2010, Volume 54,  Department of Natural Resources and Conservation, Oil and Gas Division, 2010.

Fracking in the USA 517 4. Hydraulic fracturing and deep shale gas, Northern Plains Resource Council, accessed Mar. 30, 2012. 5. Charles S. Johnson, “Environmental group sues Montana AG over ‘fracking’ documents,” Missoulian, Feb. 1, 2014. 6. Attorney general turns over fracking letter info,  Billings Gazette, Apr. 24, 2014. 7. Hydraulic Fracturing,  Intermountain Oil and Gas BMP Project, accessed Feb. 1, 2012. 8. Fracking Chemical Disclosure Rules,  Inside Climate News chart at ProPublica, accessed Apr. 2012. 9. Scott Detrow, “Montana Joins Pennsylvania In Requiring Fracking Disclosure — But Environmental Groups Aren’t Happy,” NPR, Sept. 14, 2011. 10. Montana joins 3 other states in protesting fracking rules, Associated Press, Aug. 29, 2013. 11. Brian Wright, “Analysis optimizes well results,” E&P, Jan. 3, 2008. 12. Bill Walker et al, Elm Coulee Field,  AAPG Rocky Mountain Section Presentation, Nov. 12, 2006. 13. 2009 Magnolia Petroleum Current activities. 14. Measure offers oil tax rate cut. 15. 2006 North Dakota Oil Production by Formation. 16. 2007 North Dakota Oil Production by Formation. 17. Patrick Rucker and Valerie Volcovici, “US doubles oil reserve estimates at Bakken, Three Forks shale,” Reuters, Apr. 30, 2013. 18. The Bakken Boom, An Introduction to North Dakota›s Shale Oil,  Energy Policy Research Foundation Inc., Aug. 3, 2011. 19. Jennifer Gollan, “OSHA to take hard look at ‘big oil’ in the Bakken,” Reveal, Jul. 3, 2015. 20. Philip Bump, How the oil boom in Montana has turned railroads into a pipeline, Grist, Jul. 11, 2012. 21. Pete Donkers, “Fracking Montana and Wyoming’s Beartooth Front,” Earthworks, Dec. 20, 2013. 22. 22.0  22.1  Defend the Beartooth Front  Northern Plains Resource Council, accessed Aug. 13, 2014. 23. Jan Falstad, “Denver energy company opens Billings office, plans to drill near Beartooth,” Billings Gazette, Oct. 24, 2014. 24. Ed Kemmick, “Landowners go local to head off oil-well impacts,” Last Best News, Aug. 18, 2014. 25. Chris Jordan-Bloch and Jessica A. Knoblauch, “Too Sacred To Drill,” EarthJustice, Oct. 22, 2015. 26. Chris Jordan-Bloch and Jessica A. Knoblauch, “Too Sacred To Drill,” EarthJustice, Oct. 22, 2015. 27. Gayathri Vaidyanathan, As oil production sets in, pollution starts to migrate -- scientists, Energywire, Nov. 22, 2013. 28. John Flesher, “Oil drilling boom brings trouble to farm, ranch lands,” Associated Press, Sept. 13, 2015.

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Nebraska In July 2012, it was reported that gas exploration in Nebraska was booming. In southern Sioux County in northwest Nebraska, drilling rigs have entered the area in growing numbers. The area is just east of Wyoming’s Goshen County. There has been a spike of oil and gas leases in southern and central Sioux County over the past couple of years, said William Sydow, the director of the Nebraska Oil and Gas Conservation Commission. As of July 2012, Fidelity Exploration and Production drilled one oil well in the far south end of the county, and said it has plans for developing two more wells before the end of 2012.[1] The rise of hydraulic fracturing to enhance oil and natural gas production also boosted the demand for sand to act as a proppant to prop open shale formations. The city of Genoa in Nance County is home to a plant that ships sand for hydraulic fracturing. From 2011 to 2014 sand production was at one million tons. The fall of oil prices in 2015 has prompted layoffs in several Nebraska frack sand companies.[2] Waste Disposal A waste disposal project outside Mitchell in Sioux County could receive up to 80 trucks of waste daily.  [3] Terex Energy Corporation will inject waste underground from fracking operations from nearby states. Citizen groups Nebraska Sierra Club

References 1. Across Nebraska border, oil hunt begins, Tribe.com, Jul. 15, 2012. 2. Cole Epley, “Sand industry — including Nebraska plant — feels the pain as oil prices drop,”  World-Herald, Oct. 23, 2015. 3. Fracking wastewater well application approved Oil and Gas Conservation Commission gives green light to project, KOTA News, Apr. 22, 2015.

Nevada The resource potential of Nevada oil shale has been reported as being comparatively minor. However, relatively little detailed geologic study has

Fracking in the USA 519 previously been devoted to Nevada’s oil shale. To date, the only appreciable amounts of gas found have been at the Kate Spring Field in Nevada›s Nye County. The field is presently annually producing less than 8,000 thousand cubic feet of gas, which is being used to operate equipment in the field.[1] In September 2014 Nevada state officials approved regulations that would allow fracking to take place in the state.[2] Oil shale in Nevada is primarily associated with rocks now designated as the Elko Formation. Other rock units in Nevada also contain organicrich deposits that have some minor potential for oil-shale resources; however, they have been discussed in this report mostly because of their significance as conventional oil and gas source rocks for petroleum reservoirs in Nevada. Of these rocks with minor interest for oil shale, the most promising formations include the  Vinini Formation  and the  Woodruff Formation. In 1875, oil shale was first recognized in Nevada in the Elko area in 1875 and has since been recognized in other areas. The Catlin Shale Products Company at Elko in 1917-1924 produced about 12,000 barrels shale oil, but the enterprise was a commercial failure. The products were of low quality. The Vinini and Woodruff Formations contain kerogen-rich, marine deposited shales that have high concentrations of heavy metals such as vanadium, selenium, and zinc. Although the Vinini and Woodruff Formations have shales that yield from a few gallons to as much as 15 to 30 gallons of oil per ton, oil yields are lower on average. A minimum geologic age determined for the Elko Formation is latest Eocene or earliest Oligocene, or about 37 million years old. Oil shale in the Elko Formation was derived from the accumulation and preservation of mineral sediments and organic materials deposited in an ancient lake or lakes. Subsequent erosion and faulting have disrupted the original lateral continuity of these oil-shale bearing deposits and left only scattered remnants exposed in mountain ranges, or deeply buried in sedimentary basins in northeastern Nevada. Scattered remnants of the Elko Formation occur over a north-south elongated area about 100 miles in length and 30 miles in width, confined to Elko County. [1] Citizen activism On December 9, 2014 environmentalists, tribal members and other fracking critics gathered outside Bureau of Land Management offices in Reno to oppose the controversial activity. The protest was not the first. The protesters want the “BLM to halt the proposed lease sale of more than 189,000 acres of public land in Lincoln and Nye counties for oil and gas development. They are concerned hydraulic fracturing ... would be used in the

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area to tap hydrocarbon deposits at significant cost to water resources, the environment and rural quality of life.”[3] Citizen groups Frack Free Nevada Sierra Nevada’s Water: Ban Fracking in Nevada

References 1. Oil & Gas Resources University of Nevada Reno, accessed Apr. 9, 2012. 2. Jeff DeLong, “State regulators allow fracking to start in Nevada,”  Reno Gazette-Journal, Sept. 1, 2014. 3. Jeff DeLong, “’Fracking’ protest planned in Reno,”  Reno-Gazette Journal, Dec. 8, 2014.

New Hampshire As of 2014, there is no hydraulic fracturing occurring in the state of New Hampshire.

New Jersey As of 2013, there is no drilling for natural gas in New Jersey. The state legislature has said there is the “potential for massive natural gas deposits in beds of Utica shale – a ridge of which lies beneath Sussex and Warren counties,” and potentially the Newark Basin underlying Middlesex County. Larry Ragonese, a spokesman for the DEP, said some “minute areas” of the state have potential for hydraulic fracturing, mostly near the Delaware Water Gap in the northern reaches of the state.[1] He previously said there is no frackable shale in New Jersey that can produce energy.[2] At issue is not just if there is technically recoverable gas underlying the state, but also if it is economically feasible to recover it. Data from the Pennsylvania Department of Environmental Protection showed fracking waste from Pennsylvania had gone to NJ facilities,[3] and there are current and proposed natural gas pipelines beneath the state.[4] The state Legislature passed bills in 2011 and 2012 calling for a ban on fracking, citing unknown environmental and health effects. Gov. Chris Christie conditionally vetoed the 2011 bill, changing the all-out ban to a one-year moratorium.[5] The moratorium expired in January 2013.[6]

Fracking in the USA 521 In May 2012, environmental groups called on the New Jersey Legislature to ban the treatment, disposal, and storage of any hydraulic fracturing waste in the state.[7] Data from the Pennsylvania Department of Environmental Protection showed waste from Pennsylvania had gone to NJ facilities in Elizabeth, South Kearny, and Carteret.[8]  In September 2012 Christie vetoed a bill that would have banned New Jersey treatment plants from accepting fracking wastewater.[9] Fracking wastewater In May 2012, environmental, religious, and other groups called on the New Jersey Legislature to ban the treatment, disposal, and storage of any hydraulic fracturing waste. The groups say they are concerned that waste will be shipped in from Pennsylvania, which they say has already produced more than 1.3 billion gallons of contaminated wastewater. Assemblywoman Connie Wagner (D) introduced a bill to ban fracking waste in the state, with Sen. Robert Gordon (D) introducing a companion bill in his chamber. The New Jersey Department of Environmental Protection does have interim restrictions in place for companies that import waste from fracturing operations, but not a full ban.[10] In a November 2011 advisory to the industry, the NJ DEP said the waste “may contain petroleum hydrocarbons from drilling fluids and elevated concentrations of heavy metals and radionuclides.” Fracturing waste has not come into New Jersey so far this year, according to the NJ DEP in May 2012,[11]  but on June 15, 2012, Reuters reported that data from the Pennsylvania Department of Environmental Protection showed waste from Pennsylvania had gone to facilities in Elizabeth, South Kearny, and Carteret.[12] The AP later reported the waste was drill cuttings (PA residual waste code 810) and drilling fluid (PA residual waste code 803).[13] In September 2012 Christie vetoed a bill that would have banned New Jersey treatment plants from accepting fracking wastewater.[14]Again in August 2014, Christie vetoed legislation that would have banned the state from treating or storing fracking wastewater and fluids.[15] In 2009 and 2010, about 1.4 million gallons of partially treated wastewater collected from hydraulic fracturing wells outside the Delaware River basin were processed and flushed into Delaware waters through the commercial side of Dont’s wastewater plant in Deepwater, New Jersey, near the foot of the Delaware Memorial Bridge. Delaware regulators only learned when contacted by The News Journal in May 2012 that the drilling wastewater passed through Dont’s plant for treatment, exiting from a discharge pipe under the river on Delaware’s side of the state line.

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In response, Dont official Rick Straitman said that Deepwater received gas well wastewater for treatment only after it was mixed with other, partially treated liquid wastes shipped in by a hazardous-materials handler north of Philadelphia, Pennsylvania. Straitman said Dont “has made no business decisions” about future treatment of hydraulic fracturing wastewater.[16] Proposed projects

Offshore LNG Facility As of 2013, Liberty Natural Gas LLC is asking the federal government for permission to build a facility off the coast of New Jersey - Port Ambrose - where ships carrying liquefied natural gas would dock, vaporize the gas, and transport it through underwater pipes to New York. If approved, Port Ambrose would accept about 400 million cubic feet per day of natural gas from the Caribbean nation of Trinidad and Tobago. Opponents say its approval could lead to fracking in New York, as well as the potential for spills and explosions.[17]

Pipeline In March 2012, a proposed $850 million natural gas pipeline through New York and New Jersey won the endorsement of the  Federal Energy Regulatory Commission  (FERC), which found that any environmental effects from the pipeline could be reduced to “less than significant” levels. The project now awaits a vote by the five-member commission. The project is planned by Spectra Energy of Houston, and consists of 15 miles of new pipeline that would run from Staten Island through Bayonne, N.J., and Jersey City to the West Village in Manhattan, where it would connect to Consolidated Edison’s distribution system beneath West Street. It would lie 200 feet under both industrial lands and highly populated areas, including homes, and cross more than 30 bodies of water, including the Hudson River. The project also involves replacing another five miles of existing pipeline between Staten Island and Linden, N.J., and installing associated equipment and facilities to be built in both states and Connecticut. Opponents on both sides of the Hudson have cited safety concerns, including the possibility of accidental explosions in the densely populated path of the pipeline, and the increase of unconventional drilling in the area that the project could bring.[18]

Fracking in the USA 523 Bayonne city officials agreed to the pipeline after Spectra altered the conduit’s route to avoid some residential neighborhoods. In June 2012, Jersey City - among the areas through which the pipeline is slated to run published a scathing rebuttal to FERC’s approval of the project, saying the agency harbors corporate biases and ignored public safety concerns. Jersey City officials said the city would continue to “litigate this as long as we can.” Work in Bayonne on the pipeline began in July 2012, and Spectra said the entire 20-mile pipeline would be finished by November 2013.[19] Legislative issues and regulations

Fracking The state Legislature passed bills in 2011 and 2012 calling for a ban on fracking, citing unknown environmental and health effects. Gov. Chris Christie conditionally vetoed the 2011 bill, changing the all-out ban to a one-year moratorium.[20] The moratorium expired in January 2013.[21]

Fracking Wastewater Legislation from New Jersey Sen. Robert Gordon (D), paired with a bill from state Rep. Connie Wagner (D), would ban the shipping of fracking wastewater to New Jersey and treatment of the fluid in the state.[22]  The New Jersey Assembly approved Wagner›s bill (A575) on June 21, 2012, by a veto-proof majority of 56-19,[23] and the Senate approved Gordon›s bill 30-5 on June 21, 2012. Governor Christie has 45 days to consider the legislation before a decision is required.[24] The governor vetoed the bill in September 2012, saying such a ban is premature since the EPA is studying fracking and is not expected to issue any guidance before 2014.[25] Again in August 2014, Christie vetoed legislation that would have banned the state from treating or storing fracking wastewater and fluids.[15] City bans On September 17, 2013, Highland Park Borough Council passed an ordinance to explicitly ban fracking, becoming the first city in the New Jersey to do so. Other towns in New Jersey have passed resolutions opposing hydraulic fracturing symbolically, but according to figures in the environmental movement and the energy industry, Highland Park’s ordinance is the first to have the force of law.[26]

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Citizen groups Garden State Earth Institute New Jersey Highlands Coalition New Jersey Public Policy Network

References 1. Brian Amaral, Highland Park becomes first town in N.J. to ban fracking, NJ. com, Sept. 18, 2013. 2. Matt Friedman, N.J. Senate panel approves bill to ban fracking, NJ.com, Feb. 9, 2012. 3. N.J. panel OKs fracking waste bill, Reuters, Jun. 15, 2012. 4. Mireya Navarro, Regulatory Staff Endorses Gas Pipeline for New York City and New Jersey, New York Times, Mar. 17, 2012. 5. Matt Friedman, N.J. Senate panel approves bill to ban fracking, NJ.com, Feb. 9, 2012. 6. Ellen M. Gilmer, Fracking moratorium expires, E&E News, Jan. 18, 2013. 7. Coalition wants to keep frack waste out of state, E&E News, May 17, 2012. 8. N.J. panel OKs fracking waste bill, Reuters, Jun. 15, 2012. 9. Ellen M. Gilmer, Fracking moratorium expires, E&E News, Jan. 18, 2013. 10. Coalition wants to keep frack waste out of state, E&E News, May 17, 2012. 11. Coalition wants to keep frack waste out of state, E&E News, May 17, 2012. 12. N.J. panel OKs fracking waste bill, Reuters, Jun. 15, 2012. 13. Associated Press, Clarification:  Gas Drilling story, northjersey.com, Jul. 5, 2012 14. Ellen M. Gilmer, Fracking moratorium expires, E&E News, Jan. 18, 2013. 15. Christie vetoes bill banning fracking waste, Asbury Park Press, Aug. 8, 2014. 16. Jeff Montgomery, Debate seeps into Delaware: Fracking discovery stirs concern, The News Journal, May 20, 2012. 17. Will James, Plan for Offshore Gas Facility Spurs Fracking Debate, Wall Street Journal, Jul. 21, 2013. 18. Mireya Navarro, Regulatory Staff Endorses Gas Pipeline for New York City and New Jersey, New York Times, Mar. 17, 2012. 19. Rafal Rogoza,  Controversial natural-gas pipeline project breaks ground in Bayonne, The Jersey Journal, Jul. 26, 2012. 20. Matt Friedman, N.J. Senate panel approves bill to ban fracking, NJ.com, Feb. 9, 2012. 21. Ellen M. Gilmer, Fracking moratorium expires, E&E News, Jan. 18, 2013. 22. Ellen M. Gilmer, Enviros push for ban on fracking waste disposal, E&E News, Jun. 6, 2012. 23. Assembly Approves Bill Protecting NJ from Contaminated Fracking Wastewater, New Jersey News, Jun. 22, 2012.

Fracking in the USA 525 24. NJ Legislature Bans Fracking Waste, Environment America, Jun. 25, 2012. 25. Christie vetoes fracking wastewater ban, Associated Press, Sep. 21, 2012. 26. Brian Amaral, Highland Park becomes first town in N.J. to ban fracking, NJ. com, Sept. 18, 2013.

New Mexico New Mexico is the site of about six percent of U.S. total gas production, as of mid-2012, and is home to the world’s largest coalbed methane field: the San Juan Basin. Another significant area of gas production is the Permian Basin.[1] Through the end of 2010, the San Juan Basin has produced approximately 16 TCF of CBM, accounting for 66% of all CBM ever produced in the U.S. CBM production in New Mexico peaked in 1999, and has been slowly declining since, at around 900 BCF/year (as of 2012). The Basin contains over 39,000 wells.[1] Gas production in the Permian Basin from 2002 to 2011 went from 587 BCF/year to 411 BCF/year. Gas production has been on the decline in New Mexico since 2000, from 1.6 TCF/year in 2000 to 1.2 TCF/year in 2011.[1] In 2012, the drillers drilled new wells in Chaco Canyon on the southern San Juan Basin, and the prominently Navajo communities of Lybrook and Counselor. Chaco Canyon, and surrounding lands, are rich with ancient Pueblo artifacts and tribal ruins[2] In March 2015 Environmentalist groups sued the federal Bureau of Land Management (BLM) in March 2015, pushing the agency to stop allowing  hydraulic fracturing  near sensitive areas. The judge denied the plaintiffs› and leasing in the region has continued.[3] New Mexico has a history of conservation groups, environmental groups, concerned citizens, state agencies and officials joining together to fight hydrofracking. Two major coalitions have successfully fought to ban drilling on two different sites in New Mexico: the Otero Mesa, a 1.2 million acre desert grassland, and Valle Vidal, a 102,000 acre section of the Carson National Forest. Much of New Mexico operates under split estate laws, which means the landowner does not necessarily own the mineral rights to the land. This can create controversy between gas drilling companies and landowners.[4] Photo courtesy of  Experts Review of Shale FormationsIn 1921, the Aztec Oil Syndicate drilled the first producing well in the natural gas rich, San Juan Basin, laying the groundwork for the first boom in the state. Oil companies then entered into financially successful oil leases with a newly

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fayetteville & Caney frns

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Bernatt shale & equivalents “Mississippian carbonate” Section missing

formed Navajo government. Hydraulic fracturing was done by exploding nitroglycerin into wells.[5] El Paso Natural Gas built a pipeline in 1951 from the San Juan Basin to California. Spills and Leaks An Associated Press investigation found that between 2009 and 2014 New Mexico spilled 13.3 million gallons of wastewater. The state ranked third-highest of the states for amount of wastewater spilled during that time period.[6]

Bans On April 29, 2013, Mora County commissioners voted 2-1 to ban all oil and gas extraction in their county, near Santa Fe and home to 5,000 people. A temporary drilling moratorium is already in place in neighboring San Miguel County, but Mora County is credited as the first in the nation

Fracking in the USA 527 to impose an outright ban on all oil and gas drilling.[7] The ordinance also established that citizens have a right to a safe and clean environment.[8] John Olivas, chairman of the Mora County Commission, said the ban in his county stemmed from fear that fracking might harm water wells.[9] In January 2015, U.S. District Court for New Mexico struck down the ban on drilling in Mora County. District Judge James Browning found that the ban violated both the “U.S. Constitution’s supremacy clause and state laws that allow drilling generally and fracking specifically.” It was reported that the Community Environmental Legal Defense Center or Mora County could appeal the ruling to the 10th U.S. Circuit Court of Appeals. It was the first time a federal judge had made a ruling on a local fracking ban.[10]

The Battle for Otero Mesa Otero Mesa is a 1.2 million acre desert grassland in southern New Mexico. Located below the Otero Mesa is the Salt Basin Aquifer, which is contains an estimated 57 million acre feet (unit of volume commonly in the US in reference to large-scale water resources[11]) of groundwater. According to experts, the fractured nature of its geology makes the aquifer vulnerable to the rapid spread of contamination. It is also federal land. Following a 1997 natural gas discovery, the BLM sought to lease the land for hydrofracturing for two dollars per acre. The BLM, under the Bush Administration, gave the rights to “a company whose White House connections were key to reversing earlier plans to protect much of the area from drilling.” The only bid came from Harvey E. Yates Company, or HEYCO, of Roswell, N.M.  [12]  Some are calling foul play. HEYCO contributed more than $200,000 in GOP donations. Yates also hosted a GOP fundraiser attended by VP Dick Cheney in 2002.[13] New Mexico conservation and wilderness groups coalesced to form The Coalition for Otero Mesa in 2002. Many state officials and departments were involved with the coalition, including Gov. Bill Richardson. State officials reviewed the proposed plans for drilling by BLM, and proposed an alternative plan that “would allow some drilling while placing about 75% of the mesa off-limits to energy exploration and creating a 640,000-acre national conservation area.” Richardson claims that “The BLM totally disregarded my proposal. There is no balance and no regard for ranchers or hunters.” According to the Los Angeles Times, BLM’s final drilling plan issued in Jan. of 2005 “[was] smaller in scope than originally

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contemplated but much larger than what Richardson indicated he would support. It allows drilling up to 141 exploratory wells across 95% of Otero Mesa.”[14]  Read NM Gov. Bill Richardson›s letter to the BLM  here. On Earth Day 2005 the state of New Mexico sued the federal government. The lawsuit included arguments that BLM did not conduct a complete environmental review of the land and water resources. The lawsuit, which took place in 2007, was successful in creating a drilling moratorium until an environmental assessment could be completed on the aquifer underneath Otero Mesa. Several environmental groups appealed parts of the 2007 decision. On April 27, 2009, the 10th Circuit Federal Court of Appeals ruled on an additional suit brought by the state of New Mexico, environmental and conservation groups, and state agencies. The Court ruled “the BLM violated the National Environmental Policy Act when it failed to adequately study the impacts of drilling on an aquifer underneath Otero Mesa and then declared the impact to be minimal.” It also ruled that the BLM has a duty to also consider other possible uses of the land, “including conservation to protect environmental values.”[15][16][17][18]

The Battle for Valle Vidal In 2002, El Paso Corporation publically announced its desire to explore hydrofracturing in Valle Vidal, “the Valley of Life”, a 102,000-acre section of the Carson National Forest in northern New Mexico. The area first became popular with actors and actresses, wealthy businessmen, and oil company executives as a “sporting playground.” Elk were hunted to extinction in the park. However, Pennzoil Corporation donated the land to the government in 1982 and the elk have since been reintroduced.[19]  Many refer to it as the “Yellowstone of New Mexico” in reference to its unique and pristine beauty. This is the location of the headwaters of both The Rio Grande and the Canadian River. Expert testimony stated that it “is an important… [in] protect[ing] the habitats of over fifty mammal species, more than two hundred bird species, and sixteen reptiles and amphibians.” It is also essential to water quality along the Rio Grande and Canadian River.[20] The area also holds an estimated 150 billion cubic feet of natural gas worth about 900 million dollars. This is enough natural gas to meet U.S. needs for about two days. Up to 500 wells with associated roads could have been built. The surrounding 1.5 million acres of Carson Forest had already been opened for gas drilling.[21]

Fracking in the USA 529 In response, local parties organized The Coalition for the Valle Vidal, made up of over 400 governments, organizations, businesses, and individuals. They sought a drilling ban on the 102,000 acres of Carson National Forest in addition to legal protections to protect the area’s future. Diversity among coalition members shocked many. Chris Wood, vice president for conservation at Trout Unlimited commented, “Something is happening here… what we’re seeing is the emergence of a powerful new voice in conservation. It’s not your garden-variety environmental groups. It’s hunters and anglers and outfitters and guides that are helping convince Democrats and Republicans alike of the need to protect these last places.” [19] The coalition brought Gov. Bill Richardson to nominate the area for the highest level of protection under the Clean water Act as well as requesting it be designated a roadless area, which would ban construction of new roads. US Representative Tom Udall sponsored legislation to ban both oil and gas drilling in Valle Vidal. The US House unanimously approved the Valle Vidal Protection Act on July 24, 2006.[19][22] The Senate passed the Act November 17, 2006, and was signed by President Bush on December 12, 2006.[23][24]

Public Disclosure In November 2011, the New Mexico Oil and Gas Association announced that it would now require New Mexico oil and natural gas producers to disclose some of the fluids used in hydraulic fracturing operations. The Commission’s rule requires companies to report only what they already report on Material Safety Data Sheets (MSDS). MSDS cover some chemicals specific to workers and are federally required by the Occupational Safety and Health Administration to protect workers. The restriction to MSDS data means that a large universe of chemicals frequently used in hydraulic fracturing treatments will go unreported, leading some to call New Mexico’s fracking disclosure law the worst in the country.[25] Gwen Lachelt with Earthworks› Oil and Gas Accountability Project was disappointed with the commission›s decision: “They went through all the motions to put in place a rule that requires nothing more than what’s already required on material safety data sheets.”[26]

The Pit Rule New Mexico’s pit rule, established in 2008, requires operators in the San Juan Basin to use a lined pit to dump the wastewater churned up by drilling.

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If the drilling site is near a water well, the wastewater must be contained in a closed-loop system for reuse, or be trucked offsite. In May 2012, the Oil Conservation Commission began reviewing amendments that would soften the requirements, spurred by energy companies. The industry-supported amendments would roll back the closed-loop containment requirement and make it easier for companies to establish one large waste pit for multiple wells, among other adjustments. According to state data, almost 400 pits in New Mexico had contributed to groundwater contamination as of 2008. In testimony in 2010, former Oil Conservation Division Director Mark Fesmire said there had been no cases of contamination documented since the pit rule was established, but data to verify the statement was not available before deadline. Supporters of the pit rule say they are already planning an appeal of what will likely be a “pro-industry” ruling.[27] Tremors and injection wells In April 2013, researchers at the Seismological Society of America’s annual meeting presented findings that an ongoing earthquake swarm in New Mexico and Colorado was due to underground wastewater injection, including Colorado’s largest earthquake since 1967. The reported earthquakes are concentrated near wastewater injection wells in the Raton Basin. Companies there have been extracting methane from underground coalbeds. The basin stretches from northeastern New Mexico to southern Colorado.[28] Reports The Environmental Integrity Project report on diesel and hydraulic fracturing found from 2010 to July 2014 drillers in the state of New Mexico reported using 12,808.25 gallons of diesel injected into 40 wells. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[29] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[30]

Fracking in the USA 531 The 2012 Earthworks’ Oil & Gas Accountability Project report,  “New Mexico Oil Conservation Division: Inadequate enforcement guarantees irresponsible oil and gas development,” assessed state oil and gas regulatory enforcement and found: More than 60% of active oil & gas wells go uninspected each year. Where violations are found, individual inspectors have complete discretion as to whether and how violations are recorded. Few violators are penalized, and penalties are often low, undermining their efficacy for deterring future violations. The public is prohibited access to data that would reveal how responsibly industry is operated, and how well New Mexico Oil Conservation Division is enforcing the law. Citizen groups Earthworks Coalition for Otero Mesa Drilling Mora County Drilling Santa Fe Resources Jay Lillywhite and C. Meghan Starbuck,  The Economic Impact of New Mexico’s Oil and Gas Industry,  Energy Advance New Mexico, 2008.

References 1. Bill Powers, Cold Hungry and in the Dark, NSP, 2013. 2. Johnathan Thompson, “Lessons from boom and bust in New Mexico What we can learn from the oil and gas roller coaster ride in Farmington and beyond,” High Country News, Mar. 16, 2015. 3. Ellen M. Gilmer, “Federal challenges, local control dominate year in litigation,” E&E News, Dec. 22, 2015. 4. Staci Matlock,  “Benefits, concerns surround ‘fracking,’”  Sante Fe New Mexican, Dec. 03, 2011.

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5. Johnathan Thompson, “Lessons from boom and bust in New Mexico What we can learn from the oil and gas roller coaster ride in Farmington and beyond,” High Country News, Mar. 16, 2015. 6. John Flesher, “Oil drilling boom brings trouble to farm, ranch lands,” Associated Press, Sept. 13, 2015. 7. John Upton, “New Mexico county is first in the nation to ban all drilling and fracking,” Grist, May 1, 2013. 8. Julie Cart, New Mexico county first in nation to ban fracking to safeguard water, Los Angeles Times, May 28, 2013. 9. Joe Eaton, “Battles Escalate Over Community Efforts to Ban Fracking,” National Geographic, Aug. 22, 2013. 10. Richard Nemac, “Federal Court Rejects New Mexico County Fracking Ban,” NGI›s Shale Daily, Jan. 21, 2015. 11. Acre-foot, Wikipedia, accessed Apr. 2012. 12. White House Ties Secure Yates› Drilling Rights to Sensitive N.M. Grasslands Environmental Working Group, Jul. 21, 2004. 13. Chris Roberts,  “New Mexico grasslands reflect energy debate,”  MSNBC Online, Mar. 22, 2004. 14. Julie Cart, “New Mexico Won’t Go Down Without a Fight Over Drilling,” Los Angeles Times, Apr. 23, 2005. 15. “Court’s rejection of drilling in New Mexico’s Otero Mesa may be heard across the West,” The Wilderness Society, Apr. 30, 2009. 16. Abrahm Lustgarten, “New Mexico Battles Feds to Stop Gas Drilling Near an Aquifer,” ProPublica, Nov. 20, 2008. 17. History of the campaign, Coalition for Otero Mesa, accessed Apr. 2012. 18. Joanna Prukop,  “Commentary: Otero Mesa Ruling Requires Drilling Review,” Red Orbit, Oct. 29, 2006. 19. Juliet Eilperin, “Growing Coalition Opposes Drilling,” The Washington Post, Jul. 25, 2006. 20. NMENV Statement of Reason,  New Mexico Water Quality Control Commission, Dec. 12-14, 2006. 21. Rebecca Clarren, “The Coalition That Could,” Orion Magazine Online, Nov./ Dec. Issue 2006. 22. Jennifer Talhelm, “House Votes Against Valle Vidal Drilling,” Albuquerque Journal, Jul. 25, 2006. 23. John Arnold, “Senate Oks Drilling Ban,” Albuquerque Journal, Nov. 17, 2006. 24. John Arnold, “Valle Vidal Now Protected,” Red Orbit, Dec. 14, 2006. 25. New Mexico fracking disclosure rule worst in nation, BlueDaze, Nov. 18, 2011. 26. Susan Montoya Bryan, “NM regulators approve fracking disclosure rule,” Associated Press, Nov. 18, 2011. 27. Ellen Gilmer, NATURAL GAS: N.M. commission set to roll back tough ‹pit rule,› E&E News, May 18, 2012. 28. New Mexico Earthquakes Linked to Wastewater Injection,  Becky Oskin, Livescience.com, Apr. 24, 2013.

Fracking in the USA 533 29. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 30. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014.

New York On December 17, 2014 Gov. Andrew Cuomo’s administration announced they would permanently ban hydraulic fracturing in New York State. Cuomo cited the dangers fracking posed to air and water and public health.[1] In 2010, the New York State legislature passed a temporary moratorium on fracking. In 2011, the New York State Department of Environmental Conservation (DEC) released a revised draft  Supplemental Generic Environmental Impact Statement (SGEIS) to addresses permit conditions required for gas drilling in Marcellus Shale and other areas of the State. The draft study recommends restricting fracking within New York City’s watershed while opening up large parts of the rest of the state to drilling and fracking. Fracking could commence when the final DEC environmental impact study is issued, likely in 2012, if approved by NY Gov. Cuomo.[2] In June 2012 the  New York Times  reported that, according to senior officials at the State Department of Environmental Conservation, Gov. Cuomo would likely limit drilling to the deepest areas of the Marcellus Shale rock formation — primarily Broome, Chemung, Chenango, Steuben and Tioga Counties. Drilling would be permitted only in towns that agree to it, and would be banned in Catskill Park, aquifers, and nationally designated historic districts. The strategy has not been made final and details could change, contingent on hydraulic fracturing receiving final approval from state regulators.[3] The plan is part of a demonstration project in which the DEC would issue permits for a limited number of wells in certain areas and then monitor the fracking to see if the process could be done safely. Critics say drilling would primarily take place in economically distressed areas in need of the funds, raising issues of environmental justice.[4] In 2012, the Medical Society of the State of New York called for a moratorium on natural gas extraction using hydraulic fracturing until scientific information on health impacts is available.[5] After widespread opposition, NY state environmental officials said on September 28, 2012 that they would restart the regulatory rule-making

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process, requiring them to repeat a number of formal steps, including holding a public hearing, likely pushing a decision until 2013.[6] In February 2013, Environmental Conservation Commissioner Joseph Martens said the state would begin issuing fracking permits before creating regulations if the Health Department concludes that natural-gas drilling is safe.[7] In June 2015, New York state officials banned fracking when the Department of Environmental Conservation issued the final document needed to ban fracking. However, the fracking ban could be rescinded, and both sides say lawsuits will likely be filed.[8] According to a report by Common Cause on fracking and New York:[9] In New York State, over thirty bills were proposed in the 2010 legislative session to create various panels, commissions and task forces to investigate fracking and consider moratorium bills. Numerous bills on regulating hydrofracking were also been introduced. On August 3, 2010, the New York State Senate passed S8129B, by a vote of 48-9, which prohibited drilling permits from being issued by the state Department of Environmental Conservation (DEC) before an ongoing state environmental review of fracking had been finalized. The bill passed the Assembly by a vote of 93-43 on November 30, 2010. On December 13, 2010, NY Governor Paterson vetoed S8129B while issuing an Executive Order prohibiting hydraulic fracturing of horizontally drilled wells until July 1, 2011. Since that prohibition deadline has passed, Governor Andrew Cuomo is now considering fracking. While the moratorium bill was pending in the Assembly, DEC Commissioner Pete Grannis, New York’s top environmental official, was dismissed by Governor Paterson because of a memo reflecting the growing frustration of DEC officials with the understaffing and underfunding of their agency that was leaked to the press. The memo, a response to a request from the Governor’s budget division to cut 209 staffers from the DEC, described the agency as weak and in many ways ineffective: “The risks to human health … have already increased with respect to enforcement activities related to pollution sources,” wrote Grannis. In 2011, Governor Cuomo appointed Joseph Martens as the new Commissioner of the Department of Environmental Conservation. Martens has stated that he believes the State should wait until an EPA study on fracking was completed before making any decisions regarding drilling in the state. Then, on March 31, 2011, the natural gas company Norse Energy Corp issued a press release discussing their meeting with Commissioner Martens, shortly before Martens appeared on NPR’s the Capitol Pressroom stating his confidence in gas drilling starting soon.

Fracking in the USA 535 In response, an editorial in the New York Times called for a more deliberative approach to the issue, calling the newly rushed process for state review of fracking a “ridiculously short timeframe.”[10] In February 2015, some state New York residents, that lived in jobdeprived areas, talked about seceding to Pennsylvania. Redrawing state lines would allow fracking to take place, say the supporters, which would be a boon for their communities they claim. The odds of seceding are long.[11]

Utica Shale, New York The Utica Shale lies beneath the Marcellus Shale.[12] In October 2009, the Canadian company Gastem, which has been drilling gas wells into the Ordivician Utica Shale in Quebec, drilled the first of its three state-permitted Utica Shale wells in New York. The first well drilled was in Otsego County, New York.[13] Lobbying and donations The 2011 Common Cause report,  “Expenditures of the Natural Gas Industry in New York to Influence Public Policy: Parts 1 and 2,”(2010 and 2011) found that “from 2001 through June 2011, the fracking industry gave $20.5 million to current members of Congress and spent $726 million on lobbying.” For New York: “Natural gas industry lobbying expenditures total more than $2 million from the beginning of 2005 through the first 4 months of 2010, with the lion’s share spent in the past 2 years. Industry expenditures have increased more than six-fold since 2007, landing natural gas giant  Chesapeake Energy  among New York State’s top 50 lobbying spenders for 2009, the only energy company on the list. Gas companies lobbied for access to the Marcellus Shale and against the 2010 state moratorium on permits.[14] Ten companies or trade groups that lobbied on fracking and other issues of concern to the natural gas industry spent $4.5 million lobbying in Albany from 2010 to 2012, according to an analysis prepared by the New York Public Interest Research Group.[15] Resource estimates In 2009, Penn State geologist Terry Engelder calculated that there is a 50 percent chance the Marcellus Shale holds 489 trillion cubic feet (TCF) of technically recoverable natural gas, including 71.9 TCF in New York. The

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odds that New York holds at least 30 TCF are 90 percent, he wrote in the same 2009 report.[16] In 2011, the U.S. Geological Survey (USGS) estimated that the entire five-state Marcellus formation held 84 TCF, about one-sixth of Engelder’s estimate.[16] In 2013, a four-person team of former gas executives and geologists calculated that, taking into account existing state and local restrictions on drilling, there is 4.2 TCF of recoverable Marcellus gas in New York. Restrictions include setbacks from rivers, lakes, aquifers and buildings, as well as total bans in watersheds and some municipalities. To get at their estimate, they attributed the performance of Pennsylvania wells at a given thickness and depth to New York areas with comparable characteristics. The group said that Marcellus is less than 5,000 feet deep in most of New York’s border counties, making it shallower than the layer in Pennsylvania’s three lowest performing border counties.[16] The EIA lists known dry natural gas reserves in the state at 253 billion cubic feet, as of 2013.[17] Environmental and health impacts

Compression Station Compression stations, also known as pumping stations, are facilities that help to transport natural gas through pipelines. They pose some health effects. A study published in a 2014 Reviews of Environmental Health found that spikes in air toxins around the Minisink, New York compressor coincided with residents’ adverse health symptoms. Toxins included volatile organic compounds  (VOCs) as ethyl  benzene, n-butane, n-hexane, as well as formaldehyde and particulate matter. Thirty-five subjects from eight families living within one mile from the compressor were surveyed. A physician also conducted interviews. Asthma, nosebleeds, headaches, and rashes were common among the 35. The researchers also provided five monitors to measure fine particulate matter in air near residences for the two months. Participants additionally used special canisters to capture air samples when the compressor emitted strong odors.[18] In 2012, a blow out and a ten-story fire and explosion at Springville Township when it was struck by lightening while gas was venting. Five compressor stations that push gas stream to the Millennium Pipeline in Windsor Dunbar compression station from natural gas fields in Susquehanna County over the Pennsylvania border. Several accidents have

Fracking in the USA 537 occurred at the compression station in Windsor, a small town in Broome County.[19] In January 2014, a fuel line failed at Windsor’s Dunbar compression station and gas sprayed over hot turbo-chargers and exhaust manifolds. The fire caused $3 million in damage. In Windsor compression station annually discharges up to 9.5 tons of  benzene, 49 tons of volatile organic compounds (VOCs), 95 tons of nitrogen oxides and 99 tons of carbon dioxide.

Drilling Waste Out-of-State Shale gas 101-Utica In New York, fracking wastewater from Marcellus Shale operations, such as in Pennsylvania, has been sent to at least five state New York landfills, even though none has a license to handle radioactive materials. Most shale formations contain naturally occurring radioactive material, or NORM. Although contamination levels vary widely from well to well, the Marcellus formation is suspected to be the most radioactive of all the nation’s shales.[16] Officially, the NY Department of Environmental Conservation (DEC) allows Pennsylvania drilling waste at Hyland in Angelica, the Hakes Landfill in Painted Post, the Chemung Landfill near Elmira, Seneca Meadows Landfill in Waterloo and the Allied/BFI Waste Systems landfill in Niagara Falls. The agency argues that it is not authorized to regulate NORM unless it has been “processed and concentrated,” a phrase the DC Bureau says the agency interprets narrowly.[16] A never-released study by the EPA and a confidential study by the drilling industry concluded that radioactivity in drilling waste cannot be fully diluted in rivers and other waterways, according to a February 2011 New York Times report. In December 2009, EPA scientists had advised New York that sewage treatment plants not accept drilling waste with radium levels 12 or more times as high as the drinking-water standard.[20] In July 2013 a Syracuse laboratory pled guilty to one felony count of mail fraud in a case said to involve 3,300 falsified water tests. Some of the fracking wastewater was sent to Hyland Landfill in Angelica, about 80 miles south of Rochester.[16]

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According to the environmental group Riverkeeper, fracking waste has been used to de-ice some of New York’s roads, as shown by state records obtained through a Freedom of Information Act request.[21]

In-State Most of the state’s conventional drilling waste stays in New York and is sent to sewage-treatment plants such as Auburn, N.Y., near Syracuse, or is used to de-ice roads or tamp down dust on them, according to state regulators. The state also sends waste to privately owned treatment plants in Pennsylvania and Ohio. In written comments on New York’s proposed fracking rules, the federal Environmental Protection Agency has said that the state should ban the use of fracking brine on roads because pollutants could make their way into aquifers and waterways through infiltration and storm runoff. The agency also warned that there was probably not enough capacity at out-of-state treatment plants to handle polluted water from New York, while many in-state water treatment plants are not properly equipped to treat fracking wastewater. The EPA has said that specific disposal plans must be in place before any unconventional drilling permits for the state will be issued — and that finding sites will be up to the gas industry.[22]

Methane Leakage The gas industry and ConEdison estimate 2.2% leakage in its Manhattan distribution systems, but a 2013 study by Gas Safety, Inc. found an average cumulative leakage of over 5% in natural gas production and delivery. At leakage above 3.2% natural gas ceases to have a climate advantage over other fossil fuels, according to the Environmental Defense Fund.[23] A paper published in October 2015 in Water Resources Research examined an area in New York above the Marcellus Shale formation. More than 30,000 wells burrow into the shale. The authors, Dr. James A. Montague and George F. Pinder, used a mathematical model to map the probability that new hydraulic fracturing would connect to previously used oil and gas wells, create damage, and let methane seep. The probability was found to be 10% or more. The horizontal drilling process of forming fissures in the shale can create vulnerabilities and allow methane to seep.[24] Climate Central reports that methane has about 35 times the power to warm the atmosphere as carbon dioxide.[25]

Fracking in the USA 539 The EPA asserts that  methane  accounts for 10% of climate change in 2013.[26]

Barium and Wastewater Hydraulic fracturing’s production of hazardous wastewater is assumed to be partly due to chemicals introduced into freshwater injected into a well when it mixes with salty brine naturally present in the shale rock. Dartmouth University researchers studied samples from three drill sites from the Marcellus Shale in Pennsylvania and New York to determine the possible reactions between the rock and water that release  barium, and other toxic metals, during fracking. Dartmouth College’s 2015 study, published in Applied Geochemistry, found  barium  in fracking wastewater finds chemically reacts between injected freshwater and the fractured shale. This could play a role in generating barium in hydraulic fracturing wastewater. Fracking takes place a mile below the surface. This is where chemical reactions occur between water and fractured rock at high temperature and pressure. Dartmouth team found that a large amount of barium in the shale is tied to clay minerals. This barium is readily released into the injected water as the water becomes more saline over time.[27] Proposed projects

Pipeline In March 2012, a proposed $850 million natural gas pipeline through New York and New Jersey won the endorsement of the Federal Energy Regulatory Commission, which found that any environmental effects from the pipeline could be reduced to “less than significant” levels. The project was approved in May 2012, and will begin in Fall 2013. The $1.2 billion project is planned by Spectra Energy of Houston and will pipe 800 million barrels of natural gas a day. It consists of 15 miles of new pipeline that will run from Staten Island through Bayonne, N.J., and Jersey City to the West Village in Manhattan, where it would connect to Consolidated Edison’s distribution system beneath West Street. It would lie 200 feet under both industrial lands and highly populated areas, including homes, and cross more than 30 bodies of water, including the Hudson River. The project also involves replacing an additional five miles of existing

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pipeline between Staten Island and Linden, N.J., and installing associated equipment and facilities to be built in both states and Connecticut. Opponents have cited safety concerns, including the possibility of accidental explosions in the densely populated path of the pipeline, and the increase of unconventional drilling in the area that the project could bring.[28]

Propane Fracking Propane  hydraulic fracturing  eliminates high volumes of chemicals and water. Instead it uses explosive propane injected under pressure into the  ground producing brine, heavy metals, and naturally occurring radioactive.[29] In March 2012, eCorp, GasFrac Energy Services, and the Tioga County Landowners Association reached an agreement to begin drilling the  Marcellus Shale  using liquid propane as a fracking agent. They believe that fracking with propane is not included under a New York state moratorium that prevents drillers from using high volume hydraulic fracturing. Chevron has used GasFrac’s proprietary process of fracking with liquefied petroleum gas (LPG) in its $7.3B Piceance basins natural gas project. The deal had been accepted in concept by the leaders of the Landowners Association and had to be brought to the membership base of about 2,000 families.[30] A majority of the landowners rejected the plan, and eCorp announced in May 2012 that it would try to work out another deal.[31] In 2015 a landowners leased 53 acres to Tioga Energy to drill a well using propane gel for fracking. Whether propane fracking is covered by the state’s fracking ban is under debate. The Press Sun Bulletin reported in August 2015 that Tiaoga Energy still needs drillers, financial backers, and a proven track record to complete applications for state permits.[32] Chip Northr, a retired Dallas oil investor living in Cooperstown, New York told the Press Sun Bulletin, that no drillers currently have the technical knowledge to do the kind of propane frack Tiaogo Energy is proposing. Chris Denton, a lawyer and major figure in the GasFrac’s 2012 propane frack deal, also represents landowners in the Tiago deal. Citizen activism This map displays local anti-hydrofracturing movements in Southwestern New York.

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Map courtesy of FracTracker

Fracking Bans More than 100 communities in New York have passed moratoriums or bans on fracking, as of 2012.[33] On June 30, 2014 New York’s highest court ruled that towns in the state could ban fracking through zoning laws. According to the New York Times, “two towns — Dryden, in Tompkins County, and Middlefield, in Otsego County — amended their zoning laws in 2011 to prohibit fracking, on the basis that it would threaten the health, environment and character of the communities. Subsequently, an energy company that had acquired oil and gas leases in Dryden before the 2011 zoning amendment, and a dairy farm in Middlefield that had leased land to a gas drilling company, filed legal complaints, arguing that state oil and gas law pre-empted the town ordinances ... in a 5-to-2 decision, the State Court of Appeals affirmed a lower-court ruling rejecting that argument, and found that the towns did indeed have the authority to ban fracking through land use regulations.”[34]

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2012: County Government Bans Fracking De-Icer On April 12, 2012, Ulster County executive Mike Hein issued an executive order preventing the spreading of brine from hydraulic fracturing on any county-maintained roads. The ban does not apply to town or state roads in the county. On April 17, 2012, the Ulster County Legislature is slated to hold a hearing on a proposed law banning the use of fracking brine on any roads in the county. The wastewater brine from hydraulic fracturing wells (and conventional gas wells) has been used as a cheap replacement for road salt, allowing gas companies a way to dispose of frac fluid without trucking it long distances to wastewater treatment plants. Although the New York State Department of Environmental Conservation currently does not allow brine from hydraulic fracturing operations to be spread on roads in the state, the DEC does permit the spreading of brine from conventionally-drilled wells and other activities. A similar county proposed ban was defeated in Otsego County in February 2012, when it failed to pass the county’s Natural Gas Advisory Committee, who said they weren’t convinced there was a scientific justification for banning brine spreading.[35]

Clean Energy Report Funded by Activists In early March 2013,  Mark Ruffalo  spearheaded the effort to create a plan for a renewable energy future for the state of New York. Along with filmmaker  Josh Fox  the two put together a team of researchers headed by Stanford University Professor Mark Z. Jacobson. Their report, titled Examining the Feasibility of Converting New York State›s All-Purpose Energy Infrastructure to One Using Wind, Water and Sunlight, was published in the journal Energy Policy. According to the study, if New York switched to wind, water and sunlight, deaths from air pollution–related deaths would decline by about 4,000 annually. Additionally the report states that the state would save about $33 billion – 3 percent of the state’s groups domestic product – in related health costs every year. The report goes on to say that these savings alone would pay for the new power infrastructure needed within about 17 years, or about 10 years if annual electricity sales are accounted for.[36]

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19 Arrested, in Seneca Lake Fracking-Gas Protest Houston based, Crestwood Equity Partners, project to store liquid propane in abandoned salt mines on the southwest shore of Seneca Lake has approved by the federal government now await state permits.[37] On August 18, 2015, 19 people were charged with trespassing while protesting a methane storage facility under the shores of New York’s Seneca Lake. The company Crestwood Midstream was given the go-ahead for the facility in October of 2014.[38] Legislative issues

Bills S4220A-2011  - Would prohibit the use of hydraulic fracturing in the extraction of oil and gas. S6261-2011  - Suspends hydraulic fracturing for the extraction of natural gas or oil. S1230-2011  - Establishes a moratorium on the issuance of permits for the drilling of wells and prohibits drilling within two miles of the New York City water supply infrastructure. S1234-2011  - Relates to the regulation of the drilling of natural gas resources, including provisions to prohibit drilling within the NYC and Delaware River watersheds. S2697A-2011  - Amends the environmental conservation law to provide for greater regulation of oil and natural gas operations. S5592-2011  - Suspends hydraulic fracturing for the extraction of natural gas or oil until June 1, 2012. On March 6, 2013, the New York State Assembly passed legislation on that extended the state’s moratorium on fracking in the state until May 2015 and requires further studies on the environmental impacts of the practice.[39] In May 2013, Sen. Tom Libous blocked a similar bill in the Senate. Bloomberg reported that passage of the measure would harm the prospects of a real-estate company founded by Libous’s wife and run by his campaign

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donor Luciano Piccirilli, operator of Da Vinci II LLC, which has leases to underground natural gas in Albany.[40] Judicial issues

February 2012: Judge Holds Drilling Ban In February 2012, state Supreme Court Justice Phillip Rumsey held that the Ithaca suburb of Dryden’s ban on gas drilling fell within the authority of local governments to regulate local land use, affirming the authority of towns to ban drilling - including fracking - within their borders. Anschutz Exploration Corporation, which owns more than 22,000 acres of leases in the town and has invested $5.1 million in drilling operations there, argued the ban violated a state law designed to create uniform regulations for oil and gas drilling. Rumsey disagreed, holding the law was not written to favor the industry, but to regulate it in such a way that “prevents waste ... and protects the rights of all persons,” as “nowhere in the legislative history (of the state oil and gas law) is there any suggestion that the legislature intended - as argued by Anschutz - to encourage the maximum ultimate recovery of oil and gas ... or to preempt local zoning authority.”[41]

July 2012: Driller Threatens to Sue Over Drilling Ban In late July 2012, John Holko, president of Lenape Resources, a natural gas drilling company, in a letter threatened to sue if New York regulators did not extinguish fracking prohibitions in the town of Avon. In his letter to Department of Environmental Conservation Commissioner Joe Martens, Holko wrote that a moratorium prohibiting natural gas development in the Livingston County town of Avon forced his company to shut down its wells there. Holko said that Avon’s moratorium violated a 1981 law that says state rules supersede local ordinances in the regulation of gas development.[42]

March 2013: Bans on Fracking Argued Before N.Y. State Appeals Court On March 21, 2013 natural gas proposing and environmental advocates debated whether New York’s towns have the legal right to ban oil and gas

Fracking in the USA 545 development in a fight that could ultimately be decided by New York’s highest court. It was reported: “A four-judge appellate panel heard arguments over the local bans in Dryden and Middlefield, two central New York towns among dozens in the state that have passed zoning laws prohibiting drilling. Opponents argue state rules supersede such local restrictions. The Dryden law is being challenged by drilling company Norse Energy and the Middlefield ban by a dairy farmer who said the town’s action prevents her from making money from gas wells that had been planned for her land.”[43] A Supplemental Generic Environmental Impact Statement (SGEIS) on the Oil, Gas and Solution Mining Regulatory Program Well Permit Issuance for Horizontal Drilling And High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low-Permeability Gas Reservoirs in New York was issued for public comment on September 30, 2009 to address the range of potential impacts of shale gas development using horizontal drilling and high-volume hydraulic fracturing. The permit outlines safety measures, protection standards and mitigation strategies that operators would have to follow to obtain permits. DEC received more than 13,000 public comments on the SGEIS and issued a Revised Draft SGEIS in September 2011.[44] In 2011, the New York State Department of Environmental Conservation (NYSDEC) proposed a ban of natural gas drilling within the New York City water supply watershed and a 4,000- foot wide zone around the watershed boundary. However, the Revised Draft Splemental Generic Impact Statement (RDSGEIS) (September 7, 2011) did not contain similar protections for the water supply infrastructure located at the edge of or outside of the watershed boundary. The DEP determined that additional analysis focused on the water supply infrastructure was warranted, and hired Hager-Richter Geoscience, Inc. to provide a geophysical perspective, who concluded that the protections in the RDSGEIS are not adequate to protect the NYC West of Hudson water supply tunnels.[45]

Internal E-mails E-mails between the federal EPA and NY state DEP show that the EPA offered extensive, specific criticisms of the DEC’s draft review on fracking, which the DEP found excessive and out of line with the fracking activities allowed in other states. In another set of e-mails, the EPA gave a presentation on its intentions to sample the water of private water wells in areas of New York where drilling and hydrofracking are eventually expected to occur, planned for the end of 2011 (the tests never occurred). The EPA also

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recommended that state, city, and federal agencies should have joint oversight of drilling in the New York City watershed.[46]

Industry Representatives Get Exclusive Access to Proposed Regulations In June 2012, the New York Times reported that, according to senior officials at the State Department of Environmental Conservation, Gov. Cuomo would likely limit drilling to the deepest areas of the Marcellus Shale rock formation — primarily Broome, Chemung, Chenango, Steuben and Tioga Counties. Drilling would be permitted only in towns that agree to it, and would be banned in Catskill Park, aquifers, and nationally designated historic districts. The strategy has not been made final and details could change, contingent on hydraulic fracturing receiving final approval from state regulators.[47] The plan is part of a demonstration project in which the DEC would issue permits for a limited number of wells in certain areas and then monitor the fracking to see if the process could be done safely. Critics say drilling would primarily take place in economically distressed areas in need of the funds, raising issues of environmental justice.[48] On June 28, 2012, the Environmental Working Group reported that New York regulators granted natural gas industry representatives exclusive access to shale gas drilling regulations as early as six weeks before they were made public, according to documents obtained by EWG through requests filed under the New York state Freedom of Information Law. In one instance, a representative of  Chesapeake Energy  used the exclusive access to try to weaken rules restricting discharges of radioactive wastewater, according to EWG.[49] On July 10, 2012, seven New York lawmakers publicly accused Gov. Cuomo’s administration of conspiring with industry to permit hydraulic fracturing with a minimum of regulatory oversight, and called for a new assessment on whether fracking is safe.[50]

State report: Fracking can be Done Safely In a report released in January 2013 a New York State health department report was released that stated fracking would not be a danger to public health in New York state so long as proper safeguards were put into place. Environmentalists feared the study could help lift a moratorium on the

Fracking in the USA 547 process. The Department of Environmental Conservation was granted a 90-day extension to its original deadline for completing a draft of fracking regulations in order for its environmental impact study to be reviewed by the state health commissioner and outside health experts.[51]

Cuomo Administration Edited and Delayed Key Fracking Study It was reported in October 2014 that a federal water study commissioned by Gov. Cuomo’s administration as it weighed a key decision on fracking was edited and delayed by state officials before it was published: The study, originally commissioned by the state in 2011, when the administration was reportedly considering approving fracking on a limited basis, was going to result in a number of politically inconvenient conclusions for Governor Andrew Cuomo, according to an early draft of the report by the U.S. Geological Survey obtained by Capital through a Freedom of Information Act request. A comparison of the original draft of the study on naturally occurring methane in water wells across the gas-rich Southern Tier with the final version of the report, which came out after extensive communications between the federal agency and Cuomo administration officials, reveals that some of the authors’ original descriptions of environmental and health risks associated with fracking were played down or removed.[52] Citizen groups Binghamton Regional Sustainability Coalition Capital District Against Fracking Catskill Citizens Catskill Mountainkeeper The Committee to Preserve the Finger Lakes Catskill Watershed Corporation Chenango Delaware Otsego Gas Drilling Opposition Group Chefs for the Marcellus Coalition to Protect New York Concerned Residents of Windsor Damascus Citizens for Sustainability Dryden Resource Awareness Coalition (DRAC) Environmental Advocates of New York

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Fracking 2nd Edition Frack Action Gas Drilling Awareness for Cortland County The Meredith Landowners Coalition Neighbors of the Onondaga Nation New Yorkers Against Fracking NYH2O NYRAD Otsego 2000 Oxford Visionaries Riverkeeper Shaleshock Action Alliance Stop the Algonquin Pipeline Expansion (SAPE) Sierra Club Atlantic Chapter Sustainable Otsego United for Action Un-NaturalGas.org Water Defense We Are Seneca Lake

Industry groups Unshackle state Reports

Campaign Contributions The January 2014 Common Cause report “Deep Drilling, Deep Pockets in New York State,” found pro-fracking interests contributed a total of $15.4 million from 2007 to July 2013, with nearly $48.9 million of that lobbying in New York State.

2012 USGS EIS In February 2012, the U.S. Geological Survey released a draft environmental impact statement  advising New York state regulators that their plan to allow drilling and hydraulic fracturing for natural gas in the Marcellus Shale could endanger private water wells, municipal aquifers, and New York City’s drinking water supply, particularly:

Fracking in the USA 549 The state’s proposal to allow for drilling at 500 feet from aquifers that supply major municipal water systems “is onesize-fits-all and may provide only partial protection to these aquifers.” The USGS said that, in some cases, it might be necessary to prohibit drilling within five square miles of aquifers to avoid polluting them. A similar 500-foot buffer for private water wells and springs “affords limited protection” and “does not take local geohydrologic conditions and topographic setting into account.” Pressurized fracturing fluids could migrate through underground faults and impact an underground aqueduct that carries drinking water to New York City, making it “an issue of concern” that deserves more study. A map displayed in the state’s draft plan “grossly under-represents the number and extent of [natural] faults in the Appalachian Basin of New York” where shale gas drilling would occur. The USGS argues there are many underground faults that could channel pollution from drilling into underground aquifers. “Only scattered and incomplete information is available” on underground freshwater sources that could be polluted by shale gas drilling. The USGS suggested the state plan should require drilling companies to maintain detailed logs that would identify and protect these aquifers.

2012 EWG Report The 2012 Environmental Working Group and Physicians, Scientists and Engineers for Healthy Energy report, “Serious Flaws Plague NY Drilling Plan,” challenges state officials› claims that they can prevent pollution by limiting drilling to areas in the Marcellus Shale near the Pennsylvania border where the shale is at least 2,000 feet deep and there is at least 1,000 feet of separation between the top of the shale and water supplies.” The report states that there is no empirical scientific data on drilling and fracking risks and no plan for disposing of the wastewater, among other risks.

References 1. Jesse McKinley, “Cuomo to Ban Fracking in New York State, Citing Health Risks,” New York Times, Dec. 17, 2014.

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2. Dusty Horwitt, Federal Scientists Warn NY of Fracking Risks, Environmental Working Group, Feb. 22, 2012. 3. Danny Hakim, Cuomo Plan Would Limit Gas Drilling to a Few Counties in New York, New York Times, Jun. 13, 2012. 4. Alyssa Figueroa, Revealed: NY Governor Plans to Experiment with Fracking in Economically Struggling Areas, AlterNet, Jun. 16, 2012. 5. Fracking health impact studies taking hold, with challenges, Associated Press, Apr. 2, 2012. 6. Shift by Cuomo on Gas Drilling Prompts Both Anger and Praise, New York Times, Sept. 30, 2012. 7. Freeman Klopott, New York Assembly Approves Two-Year Moratorium on Fracking, Bloomberg, Mar 6, 2013. 8. New York state officially bans fracking, Glenn Coin, Syracuse.com, Jun. 29, 2015. 9. Susan Lerner, Chris Keeley, and Deanna Bitetti, Expenditures of the Natural Gas Industry in New York to Influence Public Policy: Parts 1 and 2, Common Cause, 2011. 10. Susan Lerner, Chris Keeley, and Deanna Bitetti, Expenditures of the Natural Gas Industry in New York to Influence Public Policy: Parts 1 and 2, Common Cause, 2011. 11. Fracking ban forcing some New York towns to consider redrawing state lines, The Guardian, Feb. 28, 2015. 12. The Promise of Fracking, Tom Wilber, Press Sun Bulletin, Nov. 22, 2015. 13. Tom Grace, Officials positive following gas-well tour, Oneonta Daily Star, 7 Oct. 2009. 14. Susan Lerner, Chris Keeley, and Deanna Bitetti, Expenditures of the Natural Gas Industry in New York to Influence Public Policy: Parts 1 and 2, Common Cause, 2010 and 2011. 15. Danny Hakim, Cuomo Plan Would Limit Gas Drilling to a Few Counties in New York, New York Times, Jun. 13, 2012. 16. 16.0  16.1  16.2  16.3  16.4  16.5 Peter Mantius, http://www.dcbureau.org/201310289248/ natural-resources-news-service/new-york-shale-play-gets-major-downgrade.html#more-9248 New York Shale Play Gets Major Downgrade,  DC Bureau, Oct. 28th, 2013.  17. NY Natural Gas Reserves, EIA, Aug. 1, 2013. 18. David Brown, Weinberger B, Lewis C, Bonaparte H.,  Understanding exposure from natural gas drilling puts current air standards to the test, Mar. 2014. 19. FRACKED GAS HIGHWAYS: Pipelines feed demand, rattle neighbors, Tom Wilber, Press & Sun Bulletin, Feb. 5, 2016. 20. Ian Urbina, Regulation Lax as Gas Wells’ Tainted Water Hits Rivers, New York Times, Feb. 26, 2011. 21. Allison Dunne,  Riverkeeper Raises Concern Over Fracking Waste As De-Icer For NY Roads, WAMC, Dec. 10, 2013.

Fracking in the USA 551 22. Mireya Navarro, Wastewater Becomes Issue in Debate on Gas Drilling, New York Times, May 3, 2012. 23. Manhattan Natural Gas Pipeline Emissions, DCS, 2013. 24. James A. Montague and George F. Pinder, “Potential of hydraulically induced fractures to communicate with existing wellbores,” Water Resources Research, Retrieved Oct. 2015. 25. Study Targets Methane Leaks Between Underground Wells, Climate Central, Oct. 21, 2015. 26. Overview of Greenhouse Gases, EPA.gov, Retrieved Nov. 13, 2015. 27. Fracking plays active role in generating toxic metal wastewater, study finds, Science Daily, Dec. 15, 2015. 28. Mireya Navarro, Regulatory Staff Endorses Gas Pipeline for New York City and New Jersey, New York Times, Mar. 17, 2012. 29. Tom Wilber, Propane fracking faces long odds, Press & Sun-Bulletin, Aug. 7, 2015. 30. Propane fracking deal reached in NY; Plan would open 130,000 acres in Tioga County for drilling, Ithaca Journal, Mar. 29, 2012. 31. Tioga County, NY Lease Deal with eCorp Falls Apart, Marcellus Drilling News, May 2, 2012. 32. Tom Wilber, Propane fracking faces long odds, Press Sun Bulletin, Aug. 7, 2015. 33. Danny Hakim, Cuomo Plan Would Limit Gas Drilling to a Few Counties in New York, New York Times, Jun. 13, 2012. 34. Kate Taylor and Thomas Kaplan, “New York Towns Can Prohibit Fracking, State’s Top Court Rules,” Jun. 30, 2014. 35. Lissa Harris,  Ulster County executive bans spread of frac fluid on county roads, Watershed Post, Apr. 12, 2012. 36. Mark Z. Jacobson, Anthony Ingraffea, et al., “Examining the Feasibility of Converting New York State’s All-Purpose Energy Infrastructure to One Using Wind, Water and Sunlight.”  37. FRACKED GAS HIGHWAYS: Pipelines feed demand, rattle neighbors, Tom Wilber, Press & Sun-Bulletin, Feb. 5, 2016. 38. 19 Arrested, Including Grandparents, in Seneca Lake Fracking-Gas Protest, Earth First! Newswire, Aug. 20, 2015. 39. New York State Assembly votes to block fracking until 2015, Reuters, Mar. 6, 2013. 40. Freeman Klopott,  N.Y. Senate Fracking Backer Tied to Firm With Gas Lease, Bloomberg, May 9, 2013. 41. Dan Wiessner, New York Fracking Ban: Judge Rules Towns Can Prohibit Drilling, Reuters, Feb. 21, 2012. 42. Driller to NY: Stop the local fracking bans or we›ll sue, Associated Press, Jul. 31, 2012. 43. Mary Esch, “Bans on fracking argued before N.Y. state appeals court,” Globe and Mail, Mar. 21, 2013.

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44. Regulations, GroundWork, accessed Apr. 24, 2012. 45. Hager-Richter Geoscience, Inc.,  Technical Memorandum: Geophysical Evaluation of Infrastructure Risks of Natural Gas Production On New York City West of Hudson (WOH) Water Supply Infrastructure, Dec. 21, 2011. 46. Jon Campbell,  DEC, EPA e-mails provide clues to future of drilling in N.Y., Press Connects, Jun. 8, 2012. 47. Danny Hakim, Cuomo Plan Would Limit Gas Drilling to a Few Counties in New York, New York Times, Jun. 13, 2012. 48. Alyssa Figueroa, Revealed: NY Governor Plans to Experiment with Fracking in Economically Struggling Areas, AlterNet, Jun. 16, 2012. 49. Drillers Got Inside Track on N.Y. Fracking Rules, EWG, Jun. 28, 2012. 50. Colin Sullivan,  N.Y. officials accuse Cuomo admin of industry ‹collusion,› E&E News, Jul. 11, 2012. 51. Fracking can be done safely in New York state: dept report, Reuters, Jan. 3, 2012. 52. Scott Waldeman, “Cuomo administration edited and delayed key fracking study,” Capital New York, Oct. 6, 2014.

North Carolina In June 2012, the state Senate and House approved the legalization of fracking in North Carolina,[1] and overrode a veto by Gov. Bev Perdue.[2,3] However, in June 2014 Gov. Pat McCrory (R) legalized fracking in the state. In August 2014, the state’s Mining and Energy Commission began holding hearings that would determine. If the Commission approves the practice, fracking in North Carolina could begin as early as May 2015.[4] The legalization of fracking would roll back state laws dating back to 1945 that prohibit horizontal drilling and hydraulic fracturing, the two main components of producing natural gas from prehistoric shale rock formations.[5] Geologists have estimated a 40-year supply concentrated around Lee, Chatham, and Moore counties in the state, but the actual reserve could be smaller; some say test wells would help assess.[6] On March 16, 2012, state environmental regulators released a study concluding that fracking could be used safely in North Carolina if lawmakers adopt the right precautions. It listed a little over a dozen recommendations before authorizing the drilling method, including full disclosure of chemicals used to regulators; banning the use of diesel fuel; collecting data on groundwater, surface water and air quality before wells in an area are drilled; and limiting how much local water oil and gas companies can

Fracking in the USA 553 use. Release of the study coincided with a trip by NC Gov. Bev Perdue to Pennsylvania to meet with energy companies and fracking-friendly local officials. Perde said that she believes natural gas drilling could be done safely, but has not made up her mind on whether she’ll support efforts to make fracking legal in the state.[7] On May 1, 2012, the state Department of Environment and Natural Resources issued its final report incorporating public comment, but did not change the agency’s overall conclusions that could fracking could be done safely in the state.[8] On June 6, 2012, the state Senate approved the legalization of fracking in the state. The bill is widely expected to be approved by the Republicanled House.[9] The vote came just hours after a 2012 U.S. Geological Survey estimated that the state has 1.7 trillion cubic feet of natural gas in the Deep River Basin -- much less optimistic than earlier estimates by state geologists.[10] On July 1, 2012, Governor Perdue (D) vetoed the legislation, saying that the measure approved by the Republican-led legislature would not ensure adequate environmental protections.[11] Republicans successfully overrode Gov. Bev Perdue’s veto on July 2, 2012.[12][13] However, a moratorium was put on hydraulic fracturing to provide time for fracking-specific regulations to be drafted. The North Carolina Mining and Energy Commission expects to finalize fracking regulations by January 1, 2015. They would go into effect in March 2015, with the first drilling permits becoming available on July 1, 2015.[14] As noted, Gov. Pat McCrory approved fracking in North Carolina in June 2014.[4] In May 2015, a judge halted the approval of gas drilling operations in North Carolina until a “higher court weighs in on the legality of the appointment of several boards that manage state resources and the environment.”[15] Reserves and resources In June 2012, an assessment was released by the U.S. Geological Survey estimating that North Carolina’s Deep River Basin potentially holds 1.7 trillion cubic feet of gas and 83 million barrels of natural gas liquids.[16] The Deep River Basin spans 150 miles from Durham to the South Carolina border. The USGS estimate for the Basin is equivalent to about 5.6 years of NC usage based on 2010 state consumption; state geologists had originally estimated 5 years of gas in an area 13 times smaller.[17] Legislative issues and regulations

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2011 Veto In 2011, NC Gov. Perdue (D) vetoed legislation that would have put shale gas exploration on a fast track in the state, calling it unconstitutional.[18] In early May 2012, Perdue created a work group to develop guidelines that would allow fracking. North Carolina state regulators concluded fracking could be done safely in the state.[19]

SB 820 On May 16, 2012,  SB 820 Clean Energy and Economic Security Act advanced, which would legalize fracking within two years in this state, giving agency officials until 2014 to come up with provisions to protect the public health and the environment. The bill was sponsored by Republican Sen. Bob Rucho, and would create a new agency, the N.C. Oil and Gas Board, to oversee fracking and write regulations, and would prohibit local city or county governments from passing ordinances that would ban fracking. The bill would also protect natural gas drilling companies with a 2-year ban on public disclosure of all records, with data classified as a trade secret shielded forever. The bill will compete for votes against a more moderate approach expected from Sen. Mitch Gillespie, a McDowell County Republican who favors greater public safeguards.[20] On June 5, 2012, SB 820 was approved by the Senate Commerce Committee, and was later approved by the full Senate and the House of Representatives.[21][16] On July 1, 2012, Governor Perdue (D) vetoed the legislation, saying that the measure approved by the Republican-led legislature would not ensure adequate environmental protections.[22] Republicans successfully overrode Gov. Bev Perdue’s veto on July 2, 2012, after rallying some Democrats to vote with them. The key vote was Rep. Becky Carney, a Democrat from Mecklenburg County who opposes fracking but pushed the wrong button and accidentally voted with profracking Republicans. A maneuver by Wake County Republican Paul “Skip” Stam prevented her from changing her vote, giving Republicans the final vote needed to override the Governor’s veto.[23][24] Senate Bill 820 prohibits the state from issuing permits for hydraulic fracturing “until the General Assembly takes legislative action to allow the issuance of such permits,” and approves of regulations being considered by the Mining and Energy Commission (MEC).[25]

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SB 76 On February 11, 2013, the NC Senate introduced SB 76, which would allows permits to be issued on or after March 1, 2015, regardless of the MEC’s findings. On June 7, 2013, the state House approved a fracking policy that keeps the moratorium on shale gas exploration in place until at least March 2015 and includes a number of public protections and environmental safeguards, rebuffing the Senate bill.[25]

Chemical Disclosure In 2012, a panel was created by the state legislature to craft safety rules for shale gas exploration. The panel - the N.C. Mining & Energy Commission - approved its first rule in March 2013, exempting certain chemicals from public disclosure as “trade secrets,” but requiring fracking operators to submit trade secrets under seal to the state in case the data is needed to treat emergency injuries. According to the Charlotte Observer, fracking giant Halliburton told the state’s environmental regulators the rule goes too far, and the N.C. Department of Environment and Natural Resources is therefore working to get the rule changed.[26] Fracking waste In 2013, NC state lawmakers introduced a bill to allow for injecting brines and toxins deep underground. The bill would undo 40 years of state law, as underwater leakage in the 1960s and 70s led to the state’s ban on deep injection wells. The state’s environmental agency, in a 484page report published in 2012, urged against legalizing deep disposal of fracking wastes; state geologists say the underground geology west of Raleigh is not porous enough to absorb fluids, forcing the pressurized injections to seek fissures and faults, potentially contaminating freshwater supplies. The bill would also lift the state’s fracking moratorium in March 2015. The bill has passed the state Senate and will go to the House, where it is likely to be assigned to the Public Utilities Committee.[27] Eastern Cherokee Band Forbids Fracking on Its Sovereign Lands In October 2014 the Eastern Band of Cherokee Indians declared a ban on fracking on its sovereign land in what is today North Carolina. The reasons noted for the ban were adverse health and environmental impacts.[28]

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Offshore Drilling In January 2014, 300 residents of Kure Beach, North Carolina protested Mayor Dean Lambeth’s decision to sign a letter, written by America’s Energy Forum part of the American Petroleum Institute, supporting seismic testing for future offshore oil and gas drilling. The seismic testing is part of a plan to open an area 50 miles off the East Coast from Virginia to Georgia to oil and gas drilling by 2022. [29] Citizen activism On July 8, 2013 it was reported that over one hundred activists in North Carolina associated with Earth First! shut down an oil & gas chemical supplier to protest fracking. “We are here to send a message to the oil and gas industries: we will not stand idly by as you destroy this land, or any other, for your personal profit. Respect existence, or expect resistance,” said an Earth First! activist.[30] In June 2015, the National Association of Colored People (NCAAP) began fighting fracking in North Carolina. The NCAAP contemplated a lawsuit in Stokes County. This came a few weeks after the N.C. Department of Environment and Natural Resources got permission from the town of Walnut Cove commissioners to use land in the predominately black community of Walnut Tree to assess shale gas prospects in the Dan River basin.[31] Citizen groups Don’t Frack NC Frack Free NC National Association for the Advancement of Colored People NC Citizens Against Fracking Industry groups America’s Energy Forum Americas For Prosperity

Groups Accused Of Paying Supporters of Fracking In September 2014, N.C. Energy Coalition and Energy Creates Jobs were accused of hiring homeless individuals unfamiliar with fracking to hold signs in support of the practice during a state hearing. These supporters

Fracking in the USA 557 were bused from Winston-Salem. N.C. Energy Coalition is sponsored by the American Petroleum Institute.[32] Reports In June 2012, an assessment was released by the U.S. Geological Survey estimating that North Carolina’s Deep River Basin holds 1.7 trillion cubic feet of gas and 83 million barrels of natural gas liquids.[16]

References 1. Senate passes fracking bill, but N.C. may be less rich in gas, Sacramento Bee, Jun. 7, 2012. 2. John Murawski, Carney›s mistaken vote is key in fracking override, Charlotte Observer, Jul. 03, 2012. 3. Dylan Stableford, “What the frack? North Carolina lawmaker accidentally votes to legalize fracking,”  ABC News, Jul. 3, 2012. 4. 4.0 4.1 Fracking fight advances in North Carolina Sarah Ferris, The Washington Post, Aug. 20, 2014. 5. Senate passes fracking bill, but N.C. may be less rich in gas, Sacramento Bee, Jun. 7, 2012. 6. John Murawski,  N.C. regulators support fracking, but report calls for safeguards, News Observer, May 1, 2012. 7. Report: Fracking for shale gas can be safe in N.C., if protections in place, Fay Observer, Mar. 17, 2012. 8. John Murawski,  N.C. regulators support fracking, but report calls for safeguards, News Observer, May 1, 2012. 9. Senate passes fracking bill, but N.C. may be less rich in gas, Sacramento Bee, Jun. 7, 2012. 10. Senate passes fracking bill, but N.C. may be less rich in gas, Sacramento Bee, Jun. 7, 2012. 11. Wade Rawlins, North Carolina governor rejects fracking law, Reuters, Jul. 1, 2012. 12. John Murawski, Carney›s mistaken vote is key in fracking override, Charlotte Observer, Jul. 03, 2012. 13. Dylan Stableford, “What the frack? North Carolina lawmaker accidentally votes to legalize fracking,” ABC News, Jul. 3, 2012. 14. Bonner R. Cohen,  North Carolina Lifts Fracking Moratorium,  Heartland, Jul. 14, 2014. 15. “Judge temporarily halts ‘fracking’ permits in NC,” WRAL.com, May 20, 2015 16. 16.0  16.1  16.2 Ellen Gilmer, NORTH CAROLINA: Senate passes fracking bill as USGS counts limited resources,” Energywire, Jun. 7, 2012.

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17. Senate passes fracking bill, but N.C. may be less rich in gas, Sacramento Bee, Jun. 7, 2012. 18. Wade Rawlins, North Carolina governor rejects fracking law, Reuters, Jul. 1, 2012. 19. John Murawski, “N.C. regulators support fracking, but report calls for safeguards,” Charlotte Observer, May 2, 2012. 20. John Murawski,  Controversial fracking bill advances,  Charlotte Observer, May. 17, 2012. 21. John Murawski, Fracking bill approved by NC Senate committee, Charlotte Observer, Jun. 5, 2012. 22. Wade Rawlins, North Carolina governor rejects fracking law, Reuters, Jul. 1, 2012. 23. John Murawski, Carney›s mistaken vote is key in fracking override, Charlotte Observer, Jul. 03, 2012. 24. Dylan Stableford, “What the frack? North Carolina lawmaker accidentally votes to legalize fracking,” ABC News, Jul. 3, 2012. 25. 25.0 25.1 John Murawski, House approves bill that keeps fracking moratorium in place, Charlotte News Observer, Jun. 7, 2013. 26. John Murawski, Fracking giant Halliburton nixes NC’s chemical disclosure rule, Charlotte Observer, May 03, 2013. 27. Anne Blythe,  Fracking waste could go to N.C. coastal towns if ban is lifted, McClatchy, Mar. 5, 2013. 28. Eastern Cherokee Band Forbids Fracking on Its Sovereign Lands,  Indian Country, ICTMN Staff, Oct. 20, 2014. 29. NC town called ‹ground zero› in offshore drilling fight shows political cost of backing Big Oil over local jobs, Facing South, Jan. 2016. 30. Hundreds of Protesters Shut Down Oil & Gas Chemical Supplier to Protest Fracking, Earth First! Newswire, Jul. 8, 2013. 31. John Cox,  Over 100 people sign up to support NAACP fracking lawsuit, Winston Salem Journal, Jun. 4, 2015. 32. John Boyle, “Did energy group bus homeless in to support fracking?” CitizenTimes, Sept. 16, 2014.

North Dakota In May 2012, North Dakota passed Alaska to become the No. 2 oilproducing state in the country, which the  Wall Street Journal  attributed to the use of fracking. North Dakota›s daily production of oil rose to over 575,000 barrels by 2012, slightly above Alaska but still far below Texas, which pumped 1.7 million barrels a day.[1]  By June 2014 North Dakota was producing 1 million barrels a day, the most the state had ever produced.[2] As global oil prices dropped in late 2014 and early 2015, some

Fracking in the USA 559 analysts claimed the oil shale boom was in danger, others believed shale oil production would decline, but only temporarily.[3] North Dakota’s total oil production has approximately tripled since 2005 due largely to development of the state’s Bakken formation. Operators increased North Dakota’s production from 98,000 b/d in 2005 to over 307,000 b/d in 2010 and close to 400,000 in 2011, and some experts anticipate that the Bakken field could produce a million barrels daily by the end of 2020. According to US Geological Survey there are at least 4 billion barrels of recoverable oil in North Dakota; other estimates indicate 4-5 times more.[4] The Bakken is a tight oil deposit. It is considered to be light-sweet crude oil that is 10,000 feet below the surface within shale rock. Bakken shale consists of three layers, an upper layer of shale rock, a middle layer of sandstone/dolomite, and a lower layer of shale rock. The middle sandstone layer is what is commonly drilled and fracked.[5] As of 2011 there were 6,664 producing wells in North Dakota, and as of April 2012 there were 210 drilling rigs.[6]  North Dakota›s Gov. Jack Dalrymple has urged energy companies to see his administration as a faithful and long-term partner.[7] An industry report released in 2012 by Bentek Energy stated that the Williston Basin’s production of natural gas is expected to grow nearly six fold, to 3.1 billion cubic feet per day, by 2025.[8] As of October 2012, companies operating in North Dakota spent $2 billion a month on drilling operations.[9] For the past 60 years North Dakota has been an oil producing state. However, in recent years the state has seen a boom in the state’s Bakken region. As such, North Dakota has become the fourth largest oil producing state in the country and one of the largest onshore oil-producing regions in the United States. The Bakken shale formation extends beyond North Dakota into Eastern Montana and neighboring territories of Saskatchewan and Manitoba to the north in Canada. While its success has been largely attributed to advances in oil field technology, primarily horizontal drilling and hydraulic fracturing, it has been argued that a number of circumstances have come together to make the Bakken a successful oil play, including high oil prices, widespread and ready access to privately held prospects, and low natural gas prices.[4] Horizontal drilling in North Dakota’s area of the Bakken began in the 1980s, but was not widely used until the last decade. In the early 2000s Bakken developers began drilling horizontal laterals into the Middle Bakken formation, the sandstone layer between the two shale layers. Over the past several years fracking in the Bakken has increased dramatically.

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While this increases the cost of drilling, it also increases initial production rates and the ultimate recovery of oil from the well.[5] The first commercial Bakken well at Elm Coulee, located in Richland County, Montana, was completed in 1981 by Coastal Oil and Gas. As of 2007 the total number of horizontal Bakken wells drilled in the Elm Coulee area was more than 500 and included more than 800 lateral drilled wells.[10] Bakken formation Bakken producing zones are mainly present in Western North Dakota, Southern Saskatchewan, and Eastern Montana. The Bakken is one of the largest (possibly the largest) continuous oil accumulations in the world. It is an over pressured system; the high pressure in the formation suggests that the oil remains in place and is tightly contained throughout the geologic structure.[5] Wells have been drilled along the Bakken formation in North Dakota and Montana. Industry experts say oil appears to extend from the Bakken formation of eastern Montana into Alberta, Canada, and south to the foot of the Rocky Mountains. Fracking will likely be used to extract the oil, if it is found. Land leases for fracking in the region have increased dramatically in recent years. In North Dakota, fracking is already underway in the state’s section of the Bakken. Fracking in this area is extracting oil and not natural gas.

The bakken formation was deposited in the more central and deeper portion of the williston basin. Saskatchewan Manitoba

Bakken formation Minnosota North dakota nb

o list

Wyorning Source: USGS

n

asi

Montana l Wi

South dakota

Fracking in the USA 561 The Bakken Formation The first commercial Bakken well at Elm Coulee, which is located in Richland County, Montana, was completed in 1981 by Coastal Oil and Gas. As of 2007 the total number of horizontal Bakken wells drilled in the Elm Coulee area was more than 500 and included more than 800 lateral drill locations. [11]  In September 2015, North Dakota had 1,000 wells were drilled but not fracked due to lack of profitability as oil prices continued to stagnate.[12]

Oil Production Estimates Interest in North Dakota developed in 2007 when  EOG Resources  of Houston, Texas reported that a single well it had drilled into shale below Parshall, North Dakota was anticipated to produce 700,000 barrels (110,000 m3) of oil.[13] This, combined with other factors, including an oildrilling tax break enacted by the state of North Dakota in 2007,[14] shifted attention in the Bakken from Montana to the North Dakota side. The number of wells drilled in the North Dakota Bakken jumped from 300 in 2006[15] to 457 in 2007.[16] Those same sources show oil production in the North Dakota Bakken increasing 229%, from 2.2 million barrels (350,000 m3) in 2006 to 7.4 million barrels (1,180,000 m3) in 2007. The state Industrial Commission said crude production in September 2011 totaled 464,122 barrels a day - 123,000 more barrels than September 2010. Ron Ness, president of the North Dakota Petroleum Council, said the state should end 2011 with about 150 million barrels of oil extracted.[17] According to North Dakota government statistics, daily oil production per well seems to have peaked at 145 barrels in June 2010. Although the number of wells doubled between June 2010 and December 2011, oil production per well remained essentially unchanged. However, overall oil produced continues to increase, since more wells are continually brought online.[18] In April 2013 a government study doubled its estimates for the Bakken’s recoverable crude supplies. The U.S. Geological Survey estimated 7.4 billion barrels of undiscovered, technically recoverable oil in its study.[19] Bakken formation production peaked at 1.22 million barrels per day in December 2014. Since production has varied. The U.S. Energy Information Administration (EIA) predicts Bakken production to drop by 23,000 barrels in November 2015.[20] The Associated Press reported as of January 2016 less than 60 rigs were operating in the entire state. It was the state’s lowest levels since 2009. In January 2015, 171 rigs were operating. In January 2012, 192 were operating.[21]

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Bakken Land Leases Small and independent oil companies that made their start developing natural gas resources moved into the Bakken and accumulated acreage before the oil boom in the area. As such, the most sought after lands have already been leased for development. New Entrants into the Bakken must participate in joint ventures or buy out another company. This has not discouraged investment as several billion dollars were exchanged in mergers and acquisitions in the Bakken in the fourth quarter of 2010 alone.[5]

Public Lands and Drilling In 2009, oil drilling began outside Theodore Roosevelt National Park.[22] In October 2011, it was reported that about 80 applications for oil and gas projects in North Dakota’s national grasslands would be put on the fast-track through the federal review process. President Barack Obama announced that infrastructure projects in the Dakota Prairie and Little Missouri National Grasslands had been designated among 14 high priority projects nationwide, and would be expedited through permitting and environmental review processes so construction could begin as soon as possible. The Dakota Prairie Grasslands cover more than 1.2 million acres in southern and western North Dakota and northern South Dakota.[23] Economic impact on North Dakota economy Oil production in North Dakota accounts for six percent of domestic production in the state and is largely responsible for reversing two decades of declining oil production. Currently North Dakota is running a surplus economy. According to the North Dakota Petroleum Council, crude oil taxes on production and extraction averaged 10.3 percent in 2010, bringing in $749.5 million in state revenues. Additionally, the industry spent $1.49 billion in taxable sales and purchases. In 2010 natural gas brought in over $10.1 million in extraction taxes.[5] On the downside, it has been reported that as a result of the oil boom in North Dakota that “inadequate housing and crime” are emerging concerns for the state.[24] In an investigative report on life in the town of Williston, the biggest Bakken boom down in North Dakota, journalist Mark Ebner writes: “There’s not a motel room to be had in the city, housing prices are double what they were a year ago ($300,000 for a two-bedroom home), and the daily onslaught of new arrivals is reduced to living in their cars, RVs,

Fracking in the USA 563 sporadic tent cities or the rapidly proliferating “man camps” – clusters of trailers in an open field that pack in oil patch workers dormitory style, sometimes six to a room. Access to running water and simple sanitation is so rare that public businesses have had to lock their bathrooms to discourage makeshift sponge baths or the dumping of wastewater”[25] In April 2012, a study conducted by Headwaters Economics concluded it would be beneficial if the state of North Dakota funneled more oil and natural gas tax revenues to communities in the pathway of Bakken and hints at increasing the state tax rate on oil and gas development, which could in turn help these growing communities pay for roads, schools and other infrastructure. Currently North Dakota does not have the policies in place to reap the full economic benefits of the Bakken oil boom.[26] In October 2015, Occidental Petroleum announced that it was selling all its North Dakota holdings. Occidental claims their North Dakota assets worth $600 million.[27] OilPrice reported in November 2015 that PBF Energy and Monroe Energy would likely to decrease their purchases of oil from North Dakota. Philadelphia Energy Solutions has cut its North Dakota oil purchases by 80 percent. The company is favoring oil from Nigeria, Chad and Azerbaijan.[28] The Bismark Tribune reported in December 2015 that North Dakota drillers were in the process of selling more than 700 wells.[29] Forbes reported in November 2015 that only 4% of horizontal wells drilled since 2000 meet the Estimated Ultimate Recovery (EUR) threshold needed to break even at current oil prices, drilling and completion, and operating costs. Forbes reported in November 2015 only 1% Of the Bakken play breaks at the November 2015 prices. Petroleum geologists and Forbes analyst, Art Berman, conducted a study of the profitably of the Bakken formation Shale. The leading producing companies evaluated in his study are losing $11 to $38 on each barrel of oil that they produce, the companies evaluated were Continental Resources, EOG Resources,  Hess Corporation,  Marathon Oil, Statoil, Whiting Petroleum Corporation and XTO Energy, a subsidiary of ExxonMobil.[30] Bloomberg reported that Flint Hills Resources, the refining wing of the Koch empire, said it offered to pay $1.50 a barrel January 15, 2016 for high sulfur North Dakota Sour. This sour goes for a lower price than low sulfur Bakken[31] It was reported in February 2016 that  Continental Resources  and Whiting Petroleum, the two top producers in the Bakken, would stop fracking and bringing new wells into production. Continental plans to drill wells in the Bakken through the rest of 2016, but will leave them uncompleted to cut costs.[32] Bloomberg reported that Continental Resources has

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no more crews in the Bakken. Whiting Petroleum estimates it will leave 73 uncompleted wells in the Bakken by the end of 2016.[33] The other side of the oil boom in North Dakota Labor Injury and Fatalities According to the investigative journalism organization, Reveal, from 2006 to 2015 there have been at least 74 workplace deaths in the Bakken formation.[34] On September 14, 2011 oil rig at a bend in the Missouri River exploded at an Oasis Petroleum well pad. Worker Brendan Wegner had been exposed to oil and petroleum vapors and died immediately. Ray Hardy died the following day. Michael Twinn had both of his legs amputated.[35] From October 2014 to March 2015, at least eight workers died in North Dakota’s oil fields, which was more than the preceding 12 months. It is believed by fracking critics that these accidents are a result of cash cutting measures.[36] Water usage In 2012, it was estimated that 1.5 million gallons of water were used per fracked well in North Dakota’s  Bakken formation. However, other estimates put the range between 1.5 million and 3.5 million gallons of water used per frack.[37] Additionally, The North Dakota Department of Mineral Resources estimates that 20 million to 30 million gallons of water is used per day in fracking operations in North Dakota, or 7.3 billion to 11 billion gallons of water a year. These projections state that this amount of water will be needed to produce oil from fracking in the Bakken for decades to come.[38] The 2013 Western Organization of Resource Councils report,[39] Gone for good: Fracking and water loss in the West, found that fracking is using 7 billion gallons of water a year in four western states: Wyoming, Colorado, Montana, and North Dakota. As North Dakota’s Bakken shale fields have grown, it has been reported that the fight over who has the right to tap into the multimillion-dollar market to supply water to the energy sector. It’s been reported that “the state draws water from the Missouri River and aquifers for its hydraulic fracturing, the process also known as fracking and the key that has unlocked America’s abundant shale deposits. The process is water-intensive and requires more than 2 million gallons of water per well, equal to baths for some 40,000 people.” A co-op, backed by the government, to ensure fresh water in an area where its drinkability is compromised. “The co-op has decided to sell 20

Fracking in the USA 565 percent of its water to frackers to help keep prices low and pay back state loans. That has not gone down well with the Independent Water Providers, a loose confederation of ranchers, farmers and small businesses that for years has supplied fracking water ... The Independent Water Providers have fought back, arguing that the co-op shouldn’t be selling fracking water at all. The state Legislature stepped in with a law last month designed to quell the tension and nurture competition, but industry observers expect the acrimony to continue.”[40] Wastewater In 2013, the state produced more than 15 billion gallons of wastewater. North Dakota brine is 13 times saltier than the ocean.[41]

Wastewater Spills In 2006, a spill of almost one million gallons caused a massive death of fish and plants in a tributary of the Missouri River, called the Yellowstone River. Cleaning costs were almost $2 million. The Association Press reported that two even larger spills since then destroyed vegetation along the tributary.[42] Oil companies in North Dakota  reported  more than 1,000 accidental releases of oil, drilling wastewater, or other fluids in 2011, about as many as in the previous two years combined, according to data obtained by ProPublica. Many more illicit releases went unreported when companies dumped truckloads of toxic fluid along the road or drained waste pits illegally, state regulators acknowledged. Of the 1,073 releases reported in 2011, about 60 percent involved oil and one-third spread brine. In about two-thirds of the cases, material was not contained to the accident site and leaked into the ground or waterways. According to ProPublica: “State officials say most of the releases are small. But in several cases, spills turned out to be far larger than initially thought, totaling millions of gallons. Releases of brine, which is often laced with carcinogenic chemicals and heavy metals, have wiped out aquatic life in streams and wetlands and sterilized farmland. The effects on land can last for years, or even decades.”[43] According to Earthjustice research, more than 22 wastewater spills that occurred between 2012 and 2015.[44] In July 2014, one million gallons of wastewater leaked from an underground pipe owned by Crestwood Midstream. An EPA found investigation that the waste made it to Lake Sakakawea, the primary drinking water source for the Mandan, Hidatsa and Arikara (MHA) Nation.[45]

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In January 2015, three million gallons of oil spilled in Blacktail Creek after a pipeline leak.[46] In August 2015, it was reported that 4,000 barrels of brine spilled near the Canadian border in North Dakota. The North Dakota Dept. of Health stated that 225 barrels were recovered. It was the sixth such incident reported in 2015. The brine is used to help recover gas and oil in shale deposits. The Federal Environmental Protection Agency stated such brine may contain toxic metals and radioactive substances.[47]

Radiation Shale often contains higher levels of radium -- a chemical element used in industrial X-ray diagnostics and cancer treatments -- than traditional oil fields. Retrieving gas and oil through hydraulic fracturing, displaces radiumtinged subterranean water that comes up through the wells, where it can contaminate soil and equipment. Radiation, such as radium, builds up in the muddy sludge at the bottom of tanks, pipelines and other material that comes in extended contact with wastewater.[48]

Solid Waste Filter socks are mesh filters, several feet in length that capture the solids in flowback wastewater. The socks often contain radioactive materials, often radium. Filter socks tested by a Williston landfill were found to emit up to 47 picocuries per gram. The state prohibits disposal of waste that emits more than 5 picocuries per gram of radiation. The filter socks are often illegally dumped or snuck into landfills because according to John Harju of the Energy and Environmental Research Center at the University of North Dakota, the only disposal options are out of state. The state Department of Environmental Protection claims to have not seen problems with illegal filter sock disposal.[49] Thousands of pounds of filter socks on a truck bed in Watford City illegally dumped in February 2014.[50] Forbes reported in 2015 that North Dakota wells could produce 27 tons a day of filter socks. According Scott Radig, director of the North Dakota Health Department’s Division of Waste Management, illegal dumping of filter socks still exists.[51]

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Regulatory Enforcement Under North Dakota regulations, agencies that oversee drilling and water safety can sanction companies that dump or spill waste. Yet state data obtained by ProPublica suggests they seldom do: from 2009 to 2012, they issued fewer than 50 disciplinary actions for all types of drilling violations, including spills. State officials say they rely on companies to clean up spills voluntarily. The Health Department took just one action against an oil company from 2009-2011, citing Continental Resources for toxic oil and brine spills into two streams. The department initially fined Continental $328,500, plus about $14,000 for agency costs. Ultimately, Continental paid just $35,000 in fines.[43] Former Governor Ed Schafer served on Continental Resources’ Board of Directors from 2011 to 2015.[52] Refining and transport Northwest oil destinations TERMINALS Already receiving and shipping Global partners, clatskanie (Port westward) Planning to recieve and ship Tesoro, port of vancouver U.S. Development, Grays harbor Westway, grays harbor Imperium, grays harbor (Expansion for many products, not just crude) Targa, Tacoma REFINERIES Already receiving Tesoro, Anacortes U.S. Oil and refining, Tacoma Plan to recieve: Phillips 66, Ferndale BP, Cherry point Shell, Anacortes

Due in large part to tight oil in North Dakota, US domestic oil production has surged to its highest level since 1997, increasing the demand for domestic refining and transport. There are proposals to receive oil trains at shipping terminals in Washington, California and Alaska, as well as proposals for an oil terminal in Tacoma and three in Grays Harbor. In 2008,

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the largest US railroads carried 9,500 carloads of crude. In 2012, they carried more than 200,000.[53] The state has about 17,500 miles of pipelines, including the 2012 addition of 2,470 miles, roughly the distance from New York City to Los Angeles.[54]

Oil Pipeline Spills On October 10, 2013, over 20,000 barrels of crude oil (nearly 865,000 gallons) was reported as having spilled out of a Tesoro Corp. oil pipeline in a wheat field in northwestern North Dakota -- among the largest spills recorded in the state.[55] The spill began nearly two weeks earlier, and is believed to have been reported later than many spills due to furloughed federal government workers. Emergency crews initially lit fire to the oil spill to reach the leaking pipeline, burning an estimated 750 barrels.[56] After the spill, the Associated Press uncovered records showing 139 other pipeline leaks had been recorded so far in 2013, and 153 leaks in 2012, totaling over 1200 barrels of spilled oil. North Dakota authorities did not publicize any of the spills. State officials are not required to disclose spill information publicly.[54]

Rail Transport Of the million barrels per day that are pumped from the North Dakota’s Bakken Shale, 630,000 barrels are shipped by train to refineries on the East, West and Gulf coasts. Critics note that trains carrying fracked oil are highly combustible, noting an explosion that took place outside Casselton, North Dakota as well as an accident in Quebec that killed 47 people. Federal officials are currently investigating whether fracked oil from North Dakota should be stabilized, a process of using heat and pressure to force light hydrocarbon molecules, before the oil is shipped along railways.[57] In October 2014, the Wall Street Journal reported that California rail depots that will begin to handle oil from North Dakota’s Bakken Shale. In order to handle the demand, Alon USA Energy Inc. is building the state’s largest oil-train terminal Kern Country. That terminal, which is to be completed in 2015, will receive 150,000 barrels of oil a day in Bakersfield, California. Additionally, Plains All American Pipeline is opening a 70,000-barrel-a-day oil-train terminal, also located in Bakersfield. The oil for this terminal will also come from fracked gas from North Dakota’s Bakken Shale.[58]

Fracking in the USA 569 Gas flaring “Over 35 percent of North Dakota’s natural gas production so far in 2011 has been flared or otherwise not marketed,” the  Energy Information Administration  reported in November 2011, “due to insufficient natural gas pipeline capacity and processing facilities in the Bakken shale region.” There are also few penalties for the practice: in North Dakota, producers can flare natural gas for one year without paying taxes or royalties on it - and ask for an extension due to economic hardship associated with connecting the well to a natural gas pipeline. In the US, gas flaring has increased from 78 billion cubic feet (BCF) in 2007 to 251 BCF in 2011 - a 223 percent increase, according to the World Bank. That makes it the fifth largest gas flarer in the world, up from fourteenth in 2007. Most of the US increase is due to North Dakota, where the percentage of flared gas is far higher than the national average. North Dakota officials say the state’s flaring is responsible for about a quarter of the US total. (Less than 1 percent of natural gas produced in the US overall was vented or flared in 2009, the EIA found.) Flaring produces carbon dioxide emissions and is therefore less harmful than venting natural gas (methane) directly to the atmosphere. But it still releases GHGs. In 2011 about 5 trillion cubic feet of natural gas were flared or vented without burning worldwide - roughly equal to a quarter of all natural gas consumed in the US annually, according to the the  World Bank. Flaring also released 360 million tons of greenhouse gases into the atmosphere in 2011, equal to the exhaust of 70 million cars.[59] A 2013 report by Ceres, “North Dakota Natural Gas Flaring More Than Doubles in Two Years,” calculated that flaring in North Dakota throughout 2012 resulted in $1 billion dollars of gas burnt, with greenhouse gas emissions equivalent to one million cars.[60] It was reported in November 2013 that gas flaring in North Dakota was responsible for an increase in “ammonium nitrate, a fine particle that causes haze, as well as fine particles ammonium sulfate and black carbon, also known as soot.”[61]

Lawsuit In October 2013, North Dakota mineral owners filed lawsuits against 10 oil and gas companies seeking damages for natural gas that was flared. Bismarck attorney Derrick Braaten said the plaintiffs are owed millions in lost royalties for the flared natural gas, and the case will likely grow to include more companies.[62]

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Proposed Tax Nixed In October 2013, Wyoming legislators rejected plans for taxing flared natural gas in an 8-2 vote, after the energy industry threatened to file suit. Legislators said the $300,000 in projected annual tax revenue from the flaring plan was not worth the protracted legal battle promised by the Petroleum Association of Wyoming.[63] Air pollution

Silica In July 2012, two federal agencies released research highlighting dangerous levels of exposure to silica sand at oil and gas well sites in five states: Colorado, Texas, North Dakota, Arkansas, and Pennsylvania. Silica is a key component used in fracking. High exposure to silica can lead to silicosis, a potentially fatal lung disease linked to cancer. Nearly 80 percent of all air samples taken by the National Institute of Occupational Safety and Health showed exposure rates above federal recommendations. Nearly a third of all samples surpassed the recommended limits by 10 times or more. The results triggered a worker safety hazard alert by the Occupational Safety and Health Administration.[64]

Impacts on Wildlife The US Geological Survey conducted a survey between 2012 and 2014 and concluded that most bird species near fracking operations in North Dakota are avoiding not only the fracking infrastructure itself, but also the surrounding habitat. Researchers looked at 1,900 acres of land spread across seven counties in northwest North Dakota, where fracking is most present. They also found that three species, the Baird’s Sparrow, Chestnut-collared Longspur, and Grasshopper Sparrow, stayed as far as 1,800 feet from fracking wells.[65] Citizen activism The Smithsonian Channel featured Jim Fuglie, the former North Dakota former head of the state Democratic-Nonpartisan League Party, former state Tourism Director and author of The Prairie Blog, in the series “Boomtowners” has been an outspoken critic of the influx of oil money in North Dakota politics and lack of government oversight.

Fracking in the USA 571 Fracking studies In a Government Accountability Office report released in July 2014, the independent oversight agency reported the “EPA’s role in overseeing the nation’s 172,000 wells, which either dispose of oil and gas waste, use ‘enhanced’ oil and gas production techniques, store fossil fuels for later use, or use diesel fuel to frack for gas or oil. These wells are referred to as ‘class II’ underground injection wells and are regulated under the Safe Drinking Water Act. Oversight of these wells varies by state, with some coming under the regulatory authority of the EPA, including the 1,865 class II wells in Pennsylvania. The GAO faults the EPA for inconsistent on-site inspections and guidance that dates back to the 1980’s. Of the more than 1800 class II wells in Pennsylvania, the GAO reports only 33 percent were inspected in 2012. Some states, including California, Colorado and North Dakota, require monthly reporting on injection pressure, volume and content of the fluid. As more oil and gas wells across the country generate more waste, the GAO highlights three new risks associated with these wells — earthquakes, high pressure in formations that may have reached their disposal limit, and fracking with diesel.”[66] Oil Issues on the Fort Berthold Indian Reservation In November 2014, voters on the Fort Berthold Indian Reservation, which is home to roughly half of the 14,000 members of the Three Affiliated Tribes of Mandan, Hidatsa, and Arikara Nation (also known as MHA Nation), will vote on a new chairman, both of whom have said they will crack down on oil production on their lands. The outgoing chairman, Tex Hall, is a former oil-field services company executive. Less than half of the residents on the reservation own mineral rights. Many have voiced concerns with environmental and health impacts, as well as ways the Tex Hall has allocated oil revenue since he became chairman in 2010.[67] Mark Fox won the election on a reformist platform. 1,300 oil wells make their home on the Fort Berthold Indian Reservation. The wells pump out more than 386,000 barrels of oil daily. This accounts for a third of all oil produced in North Dakota. [68] Legislative issues In January 2012, North Dakota regulators approved new rules to reduce the number of open pits used to dump oil-drilling wastes. The rules also require oil companies to disclose the make of fluid that is used in hydraulic fracturing, requiring that the chemicals used in “frack” fluids be posted on a website two months after a well is completed.

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The new rules took effect April 1, 2012.[69] Regulations Following a draft proposal for fracking regulations, North Dakota lawmakers requested to be exempt, stating, “The unique geology, technology, and innovation in North Dakota exemplifies why a one-size-fits-all approach to oil and gas regulation does not work,” wrote Sen. John Hoeven (R), Sen. Heidi Heitkamp (D), and Rep. Kevin Cramer (R) in an Aug. 23 letter. “The federal government should allow states and tribes to move forward with their own sophisticated regulatory framework instead of stifling them with a generic blanket of federal regulations. We believe such federal regulations will hamper innovative approaches being developed throughout the country.”[70] Citizen groups Bakken Watch Dakota Resource Council Industry groups North Dakota Petroleum Trade Council Companies operating in Bakken Complete Production Services Continental Resources Key Energy Services Superior Well Services RockPile Energy Services Frac Teck Reports

Diesel in Fracking From 2010 to July 2014 drillers in the state of North Dakota had reported 4,778.51 gallons of diesel injected into 32 wells. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of

Fracking in the USA 573 Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains  benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[71] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[72]

Gas Flaring A 2013 report by Ceres, “North Dakota Natural Gas Flaring More Than Doubles in Two Years,” calculated that flaring in North Dakota throughout 2012 resulted in $1 billion dollars of gas burnt, with greenhouse gas emissions equivalent to one million cars.[73]

Road Damage A 2012 study estimated that it will cost North Dakota $7 billion over the next two decades to maintain county and township roads, in large part due to heavy truck traffic from increased drilling and fracking. The state will need to pay $834 million over the next two years alone to maintain county and township roads, two-thirds of that amount in western North Dakota, where oil production is booming. The study was presented to the state Legislature’s budget committee. The state said it has an oil-driven budget surplus, expected to reach $1.6 billion by June 2013, and incumbent Republican Gov. Jack Dalrymple has previously recommended increasing state spending on roads. Institute Director Denver Tolliver said the 28 percent increase in the group’s spending recommendation was due to rising construction costs and an 80 percent increase in the number of wells that regulators expect companies to drill in the state.[74]

References 1. North Dakota Tops Alaska in Oil Output, Wall Street Journal, May 15, 2012.

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2. Amanda Frank, “North Dakota Fails to Collect Fines for Fracking Violations,” Center for Effective Government, Nov. 25, 2014. 3. Shawn Tully, “The shale oil revolution is in danger,” Fortune, Jan. 9, 2015. 4. 4.0 4.1 Dr. Salman Ghouri, “US Shale Gas to North Dakota – Is it the beginning of a New Era for US Oil?” Fuel Fix, Dec. 16, 2011. 5. 5.0  5.1  5.2  5.3  5.4 The Bakken Boom, An Introduction to North Dakota›s Shale Oil, Energy Policy Research Foundation Inc., Aug. 3, 2011. 6. Active Drilling Rig List,  North Dakota State Government, Current Active Drilling Rig List, accessed Aug. 24, 2012. 7. Nicholas Kusnetz, North Dakota Turns Blind Eye to Dumping of Fracking Waste in Waterways and Farmland: Releases of drilling and fracking waste, which is often laced with carcinogenic chemicals, have wiped out aquatic life in streams and wetlands, ProPublica, Jun. 8, 2012. 8. David Shaffer, “North Dakota predicts big boost in natural gas,” Star-Tribune, Jul. 26, 2012. 9. Brian A. Shactman, “Could Bakken Oil Boom Go Bust After Election?” CNBC, Oct. 17, 2012. 10. Analysis optimizes well results, Brian Wright, E&P, Jan. 3, 2008. 11. Analysis optimizes well results, Brian Wright, E&P, Jan. 3, 2008. 12. Ernest Scheyder, “North Dakota oil well backlog eclipses 1,000 for first time,” Reuters, Nov. 13, 2015. 13. 2009 Magnolia Petroleum Current activities. 14. Measure offers oil tax rate cut. 15. 2006 North Dakota Oil Production by Formation. 16. 2007 North Dakota Oil Production by Formation. 17. Bakken helps North Dakota surpass oil production record [1]. 18. ND Monthly Bakken* Oil Production Statistics,  Department of Mineral Resources, Apr. 10, 2012. 19. Patrick Rucker and Valerie Volcovici, “US doubles oil reserve estimates at Bakken, Three Forks shale,” Reuters, Apr. 30, 2013. 20. James Stafford, “Oil companies are ditching North Dakota,”  OilPrice.com, Nov. 5, 2015. 21. James MacPherson, “North Dakota rigs slip below 60 for first time since 2009,” Associated Press, Jan. 5, 2016. 22. North Dakota grasslands oil and gas projects expedited,  High Country News, Apr. 27, 2015. 23. North Dakota grasslands oil and gas projects expedited,  Associated Press, Oct. 11, 2011. 24. Brian A. Shactman, “To frack or not to frack: North Dakota’s dilemma,” CNBC. com, Feb. 10, 2012. 25. Mark Ebner, “FRACKED!: Hollywood Interrupted Visits America’s New Boomtown,” Hollywood Interrupted, Apr. 24, 2012. 26. Scott Streater, “N.D. must prepare now for the end of the Bakken boom – study,” E&E News, Apr. 25, 2012.

Fracking in the USA 575 27. James Stafford, “Oil companies are ditching North Dakota,”  OilPrice.com, Nov. 5, 2015. 28. James Stafford, “Oil companies are ditching North Dakota,”  OilPrice.com, Nov. 5, 2015. 29. Regulatory focus shifts with oil industry activity, Bismarck Tribune, Dec. 11, 2015. 30. Art Berman, “Only 1% Of The Bakken Play Breaks Even At Current Oil Prices,” Forbes, Nov. 3, 2015. 31. Dan Murtaugh and Javier Blas, “The North Dakota Crude Oil That’s Worth Less Than Nothing,” Bloomberg, Nov. 3, 2015. 32. Jennifer Gollan,  Bakken energy producers stop fracking,  Reveal, Feb. 26, 2016. 33. Joe Carroll,  Shale Drillers Halt Bakken Fracking as Saudis Send Gloomy Note, Bloomberg, Feb. 24, 2016. 34. Jennifer Gollan, “OSHA to take hard look at ‘big oil’ in the Bakken,” Reveal, Jul. 3, 2015. 35. Jennifer Gollan, “In North Dakota’s Bakken oil boom, there will be blood,” Reveal, Jun. 13, 2015. 36. Caeleigh MacNeil, “Caeleigh MacNeil: In North Dakota, Fracking Could Become Even More Dangerous,” Earthjustice Blog, Nov. 23, 2015. 37. Nicholas Kusnetz, “The Bakken oil play spurs a booming business -- in water,” Aug. 2, 2012. 38. Water Consumption in the Bakken,  Beyond the Boom, accessed Jul. 29, 2015. 39. Emily Guerin, “Wastewater pipelines often leak in North Dakota,”  High Country News, Feb. 16, 2015. 40. Fracking boom triggers water battle in North Dakota, NBC News, May 20, 2013. 41. Fracking boom triggers water battle in North Dakota, NBC News, May 20, 2013. 42. John Flesher, “Oil drilling boom brings trouble to farm, ranch lands,” Associated Press, Sept. 13, 2015. 43. 43.0  43.1  Nicholas Kusnetz,  North Dakota Turns Blind Eye to Dumping of Fracking Waste in Waterways and Farmland: Releases of drilling and fracking waste, which is often laced with carcinogenic chemicals, have wiped out aquatic life in streams and wetlands, ProPublica, Jun. 8, 2012. 44. Caeleigh MacNeil, “Caeleigh MacNeil: In North Dakota, Fracking Could Become Even More Dangerous,” YubuNet.com, Nov. 23, 2015. 45. Caeleigh MacNeil, “Caeleigh MacNeil: In North Dakota, Fracking Could Become Even More Dangerous,” YubuNet.com, Nov. 23, 2015. 46. Antonia Juaszh, “From North Dakota to Paris With Love,” Newsweek, Nov. 25, 2015. 47. Daniel J. Graeber, “Byproduct of fracking spilled in North Dakota,” UPI, Aug. 7, 2015.

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48. Alex Nussbaum, “Radioactive Waste Booms With Fracking as New Rules Mulled,” Bloomberg, Aug. 16, 2014. 49. Jeff McMahon, “Strange Byproduct Of Fracking Boom: Radioactive Socks,” Forbes, Jul. 24, 2013. 50. Sharon Kelly, “Western State Regulators Struggling to Keep Up with Radioactive Fracking and Drilling Waste: New Report,” DeSmogBlog, Nov. 23, 2015. 51. Jeff McMahon, “Strange Byproduct Of Fracking Boom: Radioactive Socks,” Forbes, Jul. 24, 2013. 52. Former governor Schafer quietly exits Continental Resources board, Grand Forks Herald, Oct. 9, 2015. 53. Scott Learn,  Oil trains -- pipelines on wheels -- headed to Northwest terminals and refineries from North Dakota fracking, The Oregonian, May 13, 2013. 54. 54.0  54.1  James MacPherson,  ND Spills Went Unreported; State Testing Website, Associated Press, Oct. 25, 2013. 55. James MacPherson, North Dakota Oil Spill: Tesoro Corp. Pipeline Breaks Near Tioga; Dumps More Than 20,000 Barrels Of Crude, Associated Press, Oct 10, 2013. 56. John Upton, “Huge North Dakota oil spill went unreported by furloughed feds,” Oct. 11, 2013. 57. Russell Gold and Chester Dawson, “North Dakota Fracking: Behind the OilTrain Explosions,” Wall Street Journal, Jul. 7, 2014. 58. Alison Sider & Cassandra Sweet, “California Finally to Reap Fracking’s Riches,” Wall Street Journal, Oct. 7, 2014. 59. Mark Clayton,  Thanks to North Dakota, US waste of natural gas grows rapidly, The Christian Science Monitor, Jul. 13, 2012. 60. Ryan Salmon and Andrew Logan, North Dakota Natural Gas Flaring More Than Doubles in Two Years, Ceres, Jul. 2013. 61. Phil Taylor, “Bakken boom linked to haze at Theodore Roosevelt park,” E&E News, Nov. 7, 2013. 62. Amy Dalrymple,  Lawsuits filed against oil companies for flaring natural gas, Forum News Service, Oct. 16, 2013. 63. Joan Barron,  Wyoming legislators strikes down flaring bill after threat of lawsuits, trib.com, Oct. 29, 2013. 64. Adam Voge, Fracking dust alert not shocking in Wyoming, Wyoming Star Tribune, Jul. 30, 2012. 65. Laura Dattaro, “Birds Flee in the Face of Fracking,” Audubon, Oct. 29, 2015. 66. Congressional Watchdog Warns Fracking Waste Could Threaten Drinking Water, StateImpact, Pennsylvania, Jul. 18, 2014. 67. Tim McDonnell, “How 3,500 Voters in North Dakota Could Put the Brakes on America’s Biggest Fracking Boom,” Mother Jones, Nov. 3, 2014. 68. George Lerner & Christof Putzel, “Tribal environmental director: ‘We are not equipped’ for N.D. oil boom,” Al Jazeera America, May 15, 2015.

Fracking in the USA 577 69. Rules approved to cut North Dakota oil waste pits, Associated Press, Jan. 23, 2012. 70. John Upton, “Sens. Heitkamp, Hoeven seek North Dakota exemption from Interior ‘fracking’ rules,” The Hill, Sept. 12, 2013. 71. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 72. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014. 73. Ryan Salmon and Andrew Logan, North Dakota Natural Gas Flaring More Than Doubles in Two Years, Ceres, Jul. 2013. 74. Study: $7B bill for ND road keep over 20 years, Associated Press, Sept. 21, 2012.

Ohio According to the industry-funded Ohio Oil and Gas Energy Education Program, Ohio contains an estimated 20 trillion cubic feet of “untapped” natural gas with a value of over $100 billion. The Ohio Department of Natural Resources estimates that, in addition to natural gas and shale gas, 1.3 to 5.5 billion barrels of tight oil may be contained within Ohio, with a market value of up to $550 billion.[1] The gas and oil is contained in rock shale deep in the earth and removed through a chemical- and water-intensive process known as hydraulic fracturing, or fracking. A portion of this mixture, called “brine”, bubbles back to the surface as wastewater. The fluids are typically disposed of in Ohio by pumping them back into the ground into disposal “injection wells,”[2] which have been linked to a series of earthquakes in previously non-seismically active areas of the state.[3] Data released by DrillingInfo in late 2015 reported that permits issued  for the Marcellus region was 68 in October, down from 76 in September 2015. Additionally, there were 160 permits issued in June 2015. At the same period in 2010, during the fracking boom in the region, 600 permits were issued a month. The steady decrease in global oil prices was said to be responsible for the decline in the number of fracking permits.[4] In 2011, Gov. Kasich signed a law passed by Ohio’s Republicancontrolled legislature allowing drilling companies to frack in state parks. In November 2011, the United States Forest Service (USFS) withdrew more than 3,000 acres of public lands in southern Ohio from a federal oil and

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gas lease sale scheduled for December 7, 2012. The USFS announced that it needed more time to review the potential effects of fracking after receiving petitions and letters from concerned local leaders.[5] In the first statewide poll on  hydraulic fracturing  (January 2012), 59 percent of those polled said they had heard of or read about the method, and 72 percent said hydro-fracking should be halted until it is studied further. The poll of 1,610 registered voters was conducted from January 9 to January 16 by Quinnipiac University.[6] As part of his 2012 budget, Governor Kasich proposed a decrease in the natural gas severance tax and an increase in the gas liquids tax to 4%, a rate that locals point out would still leave Ohio behind other states like Texas (7.5% for natural gas and 4.6% on gas liquids). An April 2012 ODNR report indicated that the Ohio shale is producing much less oil and much more natural gas than had been previously estimated, which the think tank Innovation Ohio said “further highlight[ed] the weakness of the Governor’s tax changes”:[7] Governor Kasich’s proposal to ‹modernize› Ohio’s severance tax rates actually lowers the tax on natural gas, while increasing it on oil. Given that our first batch of wells are cranking out gas far ahead of schedule, with oil lagging, this plan may represent a gift to the industry; one that could result in considerable lost revenue for the state of Ohio.[8][9] In March 2012, Gov. Kasich promoted a plan to expand fees on Ohio’s oil and natural gas industry and cut income taxes. The plan is for the fee expansion on fossil fuels to pay for an income tax cut. Progressive think tank Innovation Ohio called the tax expansion a “giveaway to oil companies,” generating $19 a year for a family making $50,000 annually. Innovation Ohio estimates that once all the income tax cuts are in place, the same family would save just $65 each year; most benefits would largely go to the wealthiest Ohioans. Kasich said it’s still too early to know how significant tax cuts would be because it’s unclear how much revenue the fossil fuels tax would generate. Several weeks after Kasich’s plan was announced, fellow Republicans, who controled the General Assembly, “remain[ed] lukewarm on the plan,” according to ABC News. In response, Kasich began taking his message to the public by speaking to Chambers of Commerce and news outlets. [10] Media Matters has suggested the divide between Kasich and other Republicans is not nearly as large as the media has portrayed, and that even Grover Norquist’s Americans for Tax Reform, which was ‘consulted’ about the proposal, is tentatively approving the tax plan and giving Kasich the ‘benefit of the doubt’ regarding any potential concerns about increased taxation.”[11]

Fracking in the USA 579 Earthquakes

FracTracker analyzes earthquake patterns On New Year’s Eve 2011, a 4.0 magnitude earthquake was recorded in Ohio. This and a series of other quakes in the region have been linked to a disposal well for injecting wastewater used in the fracking process by seismologists at Columbia University›s Lamont-Doherty Earth Observatory. Wastewater from the fracking process is either recycled or trucked off site to be injected in a deep underground well. As the pressurized water is pushed below ground it can cause earthquakes on ancient fault lines. In response to the findings, the state is considering tougher rules on drilling. Governor John Kasich has been a strong proponent of fracking. In January 2012, Ohio regulators asked D&L Energy, a company that carries out fracking near Youngstown, to stop re-injecting waste water from

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hydraulic fracturing while an investigation was opened up into the cause of 12 earthquakes in the area (including a 4.0-magnitude quake on New Year’s Eve)--an area not considered seismically active. The site is at the bottom of a 9,200-foot-deep injection disposal well. Geological experts say the reinjected brine water could find its way into subterranean faults and force parts of the planet to separate, causing tremors.[12] The earthquakes started in March 2011, about the same period that the major injection activities started.[13] According to Michael C. Hansen, state geologist and coordinator of the Ohio Seismic Network, there is “little doubt” that the earthquake was related to injection wells. James Zehyringer, director of the Department of Natural Resources, announced that two 9,000-foot-deep injection wells in Youngstown Township owned by Northstar Disposal Services and operated by D&L Energy would be closed.[14] On March 9, 2012, Ohio oil and gas regulators issued a  preliminary report “on the relationship between the Northstar 1 Class II disposal well and 12 Youngstown area earthquakes.” The report found a number of co-occurring circumstances strongly indicating the Youngstown area earthquakes were induced. In response, Ohio regulators said new safeguards would be added to Ohio’s existing disposal well regulatory framework, including prohibiting any new wells to be drilled into the Precambrian basement rock formation; mandating that operators submit extensive geological data before drilling; and implementing state-of-the-art pressure and volume monitoring devices including automatic shut-off switches and electronic data recorders.[15] In 2013, the Journal of Geophysical Research paper, “Induced seismicity associated with fluid injection into a deep well in Youngstown, Ohio,” concluded that the recent earthquakes in Youngstown, Ohio were induced by the fluid injection at a deep injection and that the data may indicate that the earthquakes were directly caused by the pressure build and stopped when pressure dropped.[16] In April 2014, a state investigation of five small tremors the previous month in the Youngstown area concluded a “probable” link between the tremors and fracking in the region, marking the first time tremors in the region were tied directly to the fracking process itself, rather than the injection of wastewater.[17] In January 2015, an article published online in the Bulletin of the Seismological Society of America noted that “77 minor earthquakes last March around Poland, Ohio, just across the Pennsylvania-Ohio state line” were caused by fracking.[18] Inside Climate News reported that  hydraulic fracturing  induced earthquakes, as well as wastewater injection induced, have occurred not only in western Alberta, but also British Columbia,  Oklahoma, and

Fracking in the USA 581 Ohio. According to geophysics Dr. Jeffrey Gu, from the University of Alberta, hydraulic fracturing earthquakes likely occur days to weeks after the frack job. Wastewater injection caused earthquakes can happen months to years after the injection.[19] Drilling wells There are 64,378 active wells in Ohio as of 2012, most of them “stripper” wells producing fewer than 10 barrels of oil a day or less than 60,000 cubic feet a day of natural gas.[20] According to the Ohio Department of Natural Resources as of January 2012, permits have been issued for nearly 140 wells in Ohio for the purpose of drilling into the Utica or Marcellus Shale horizontally, at 3,000 feet or more below the surface. Most of the well sites still are not yet active, but 38 are recorded as either have been drilled or are the site of current drilling.[21] Permits were issued, but not yet active, for 75 locations in eastern Ohio. The largest share of the well locations is in Carroll County, with 38 permitted locations. There were 15 in Jefferson County and 10 in Columbiana County.[22] New permits are being issued quickly. According to Innovation Ohio, March 2012 broke the record for new natural gas permits, with the Ohio Department of Natural Resources approving 37 wells, ahead of the 27 in February and 19 in January, looking like 2012 will quickly surpass 2011’s total of 100 new permits. “These new permits bring the total to 194 permitted wells in Ohio, of which 19 are drilling, 37 are drilled, 11 are producing, and 12 are completed.”[23]

Public Lands Ohio passed a law in September 2011 that opened its parks and other stateheld lands for drilling, and officials have been developing leasing terms for drilling companies. Eastern Ohio is in the midst of a natural gas boom as developers seek to capture rights to Utica Shale deposits. In April 2012, the Ohio Department of Natural Resources state made public its proposed rules for drilling in state parks, which would require natural gas and oil companies to stay at least 300 feet — the length of a football field — from campgrounds, certain waterways and sites deemed historically or archaeologically valuable. It’s unclear whether the 300-foot buffer rule in Ohio will be applied above ground or below. The Sierra Club filed a lawsuit against the Ohio DNR, saying the agency failed to follow the state’s public records law by ignoring requests for regulatory documents as far back as October 2011.[24]

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Officials with the Wayne National Forest, in southeastern Ohio, decided to remove about 3,300 acres of park property from federal auction for oil and gas exploration because of concerns about the impact of fracking on forestland.[25] Jackie Stewart, a spokeswoman for Energy In Depth Ohio, an outreach campaign for the oil and natural gas industry, said to the Post in November 2015 that there are more than 1,200 active wells in the Wayne National Forest. In 2015, the federal government is considering Wayne National Forest again for more oil and gas development.[26] The federal government is assessing about 31,900 acres of the forest for hydraulic fracturing. On July 11, 2012, Ohio Gov.  John Kasich  signed an Executive Order reasserting the federal prohibition against the Ohio Department of Natural Resources issuing any permit, license, or lease allowing oil and gas drilling in or under Lake Erie.[27]

Targeting Activist Opposition When the Ohio Department of Natural Resources drafted its August 2012 outline of its communication plan for allowing oil and gas drilling on public lands, the document warned that “eco-left pressure groups” would be key influencers seeking to stop the drilling and would “attempt to create public panic” about health risks related to fracking. The plan listed companies like Halliburton, as well as associations like the U.S. Chamber of Commerce and the Ohio Oil and Gas Association as allied groups on behalf of the state’s initiative. Groups like the Sierra Club, Natural Resources Defense Council and the Ohio Environmental Council, as well as two state legislators, are listed as the “opposition.” A spokesman for Gov. Kasich’s office acknowledged to the Associated Press that several of the governor’s top advisers had met with DNR officials about the plan, as an email related to the communications plan had indicated. But state officials say the plan was not implemented.[28] According to a study by researchers from the University of Florida, North Carolina State University, and Florida State University in August 2015, hydraulic fracturing in, or near, public park lands could prompt tourists to stay away. The study of 225 park users in Pennsylvania, Ohio, West Virginia, Kentucky, and Tennessee found more than a third say they would be unwilling to participate in recreational activities near hydraulic fracturing. Fifty eight percent of the study’s participants claim they would support legislation prohibiting fracking near their favorite park.[29]

Fracking in the USA 583 Water use Several companies have contracts with Ohio cities that allow the drillers to draw from drinking water reservoirs. Agency records and emails obtained by the Columbus Dispatch in 2012 show that Ohio DNR officials, who manage state parks and forests as well as regulate drilling, have been discussing plans that would grant access to state-owned reservoirs, lakes, and streams to supply the water for drilling companies to hydraulically fracture the state’s Utica Shale wells. The Muskingum Watershed Conservancy District announced that it would not sell water from six reservoirs until a water-availability study was completed. District officials have asked the U.S. Geological Survey to study its Atwood, Clendening, and Leesville reservoirs to assess the amount of excess water available for drillers.[30] From 2011 to September 2014, Ohio has used a total of 4 billion gallons of water to frack wells in the state.[31] Water contamination In 2014 it was reported that Ohio has had over one hundred complaints of water contamination from 2010-2014, yet none were confirmed to be related to fracking operations.[32] Fracking wastewater West Virginia and Pennsylvania ship most of their wastewater for disposal in Ohio injection wells. In 2012, West Virginia’s Department of Environmental Protection took samples of the brine. The lab results indicated high levels of alpha particles, arsenic, barium, and toluene, among other contaminants, and are cause for the brine to be classified as “hazardous,” according to Ben Stout, professor of biology at Wheeling Jesuit University who interpreted the results. He described heavy metals found in the sample as “grossly above standard,” citing arsenic and barium levels that exceed the primary standard for acceptable drinking water concentrations by 370 and 145 times, respectively.[33] ProPublica reported in 2014 that Ohio processes thousands of tons of radioactive waste from hydraulic fracturing a year.[34]

Injection Wells In the first three quarters of 2011, Ohio had 177 active Class II wells that absorbed 368.3 million gallons of fracking wastewater, according to Ohio Natural Resources Department records. The total is up from 359.3 million

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for all of 2010, and more than in any year since 1987. Ohio approved 29 permits for wells in 2011, after averaging about four a year for the past two decades. [35] For all of 2011, oil and gas companies injected 511 million gallons into Ohio’s wells, the most on record, according to the state’s Department of Natural Resources.[36] More than half the fracking wastewater was shipped in from out of state. Of the almost 22 million gallons of wastewater that Pennsylvania’s Marcellus Shale  operators sent to disposal wells in the first six months of 2011, nearly 99 percent went to Ohio, according to production reports from the Pennsylvania Environmental Protection Department. Pennsylvania has only six active Class II wells, in part because Pennsylvania allowed companies to discharge brine into streams or take it to treatment plants until 2010. [37] Since 2010, Ohio charges a disposal a fee of five cents per barrel on Ohio brine, and twenty cents for waste originating out of state.[38]Ohio collected $1.45 million for these fees in 2011.[39]  In January 2012, when asked how Ohio would avoid becoming a dumping ground for out of state waste, Governor Kasich told Bloomberg that the U.S. Constitution prohibits interference with interstate shipments.[40] In March 2012, the Governor’s proposed energy policy legislation, Senate Bill 315, that would raise brine disposal fees from five to ten cents on in-state waste, and from twenty cents to $1 on out of state waste. In April 2015, the state’s Department of Natural Resources shut down five waste injection wells owned by Kleese Development Associates after the company spilled 2,000 gallons of waste into a tributary of Little Yankee Run. [41]

EPA Limits Wastewater in Warren On March 19, 2012, the Ohio Environmental Protection Agency issued its final permit renewal to the city of Warren, Ohio, and also an additional permit to Patriot Water Treatment LLC, the state’s lone brine-wastewater treatment plant. The permit will not allow the city of Warren to accept any more brine wastewater from fracking as of April 1, 2012. The five-year permit also calls for total dissolved solids monitoring twice a week. Patriot’s permit to install will allow the company to accept and treat “new wastewater sources.” The company can still accept fracking wastewater, from Utica and Marcellus shale exploration, but has to find a different method of disposal or reuse rather than sending the water to Warren, such as recycling or injection-well disposal.[42]

Fracking in the USA 585

Recycling Ohio, according to ORC 1509.226, allows the application of fracking wastewater on roads for dust and ice control as a legitimate form of disposal.[43] A 2012 Natural Resources Defense Council (NRDC) report “In Fracking’s Wake: New Rules are Needed to Protect Our Health and Environment from Contaminated Wastewater,” finds that from  hydraulic fracturing  wastewater from flow back and brine contains pollutants and Naturally Occurring Radioactive Materials (NORM) can be toxic to humans and the environment. Spreading wastewater on roads can wash pollutants into watersheds or groundwater.[44]

Dumping On January 31, 2013, the company Hard Rock Excavating was found dumping an estimated 40,000 to 50,000 gallons of fracking waste into a storm drain, which eventually emptied into the Mahoning River. The Ohio Environmental Protection Agency later found documents showing that Ben W. Lo, a partner in several companies headquartered at the site, and owner of both D&L Energy and Hard Rock, instructed an employee to dump the wastewater down the drain.[45] The dumping happened more than 30 times between November 1, 2012 and January 31, 2013.[46] The EPA considered the Lo case one 2014 “2014 Major Criminal Cases.” [47] On July 3, 2012, the Ohio Environmental Review Appeals Commission ruled that the Ohio Environmental Protection Agency was wrong to expressly bar the city of Warren’s sewage treatment plant from taking treated fracking wastes and dumping those wastes into the Mahoning River. Yet the Commission also ruled that the city must first obtain permission to dump the waste from the Ohio Department of Natural Resources, which oversees the disposal of oil and gas field wastes.[48]

Wastewater Pits Fracking wastewater impoundments store millions of gallons of chemicallaced fracking wastewater to recycle and frack new wells. The impoundments dot the Pennsylvania and West Virginia landscape. A provision in a 2013 Ohio state budget requires Natural Resources officials to create rules

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and permits for them, such as requiring plastic liners to prevent leakage into groundwater.[49]

Wastewater Processing Plants Austin Master Services in Martins Ferry, Ohio radioactive uranium, radium and plutonium in Marcellus Shale and Utica Shale. The old Wheeling Pitt Steel mill now houses Austin Master services. [50] Wheeling’s Channel 7 reported that trucks haul frack wastewater and drill cuttings to Austin Master Services. Their lab assesses the amount of radioactivity.[51] Proposed projects In February 2012,  NiSource  Gas Transmission and Storage›s (NGT&S) Midstream Services announced plans for a pipeline for the Utica play in eastern Ohio. The project also includes a 200 million cubic feet per day cryogenic natural gas liquids processing plant that will be delivered in July 2012. The plant and related facilities will be located in Harrison County and will process gas flowing from both the north and south. NGT&S will also construct a dry gas line originating from the tailgate of the processing plant that will also gather additional dry gas produced in the Utica trend. The system will ultimately deliver gas to multiple interconnects including Texas Eastern (Spectra), Rocky Mountain Express (Kinder Morgan) and Columbia Gas. The project is expected to provide an initial transportation and processing capacity of 200 million cubic feet per day.[52]

Natural Gas Facilities and Offices As reported by the New York Times in March 2013, “Chesapeake Energy Corporation, which is based in Oklahoma City and is the largest developer of the shale formation, known as the Utica Shale, is building a field office on a 291-acre site here that it bought here last year for $7.11 million. The project’s centerpiece is a five-story, 85,000-square-foot office tower that is scheduled to be completed early next year. The company is also building a 55,000-square-foot receiving and maintenance building and a 6,000-square-foot repair shop.”[53] Numerous drilling and energy companies have set up shop in Ohio in recent years. In 2013, a new liquefied natural gas (LNG) fueling station was built, which is owned and operated by Clean Energy Fuels Corp.

Fracking in the USA 587 and opened in Seville, Ohio to support the expanding fleet of LNG trucks deployed by major contract freight carrier Dillon Transport.[54] Spills and accidents

Methane Hazards A Cleveland, Ohio house exploded in late 2007 after methane gas seeped into its water well. The Ohio Department of Natural Resources later issued a  153-page report  (PDF) that faulted a nearby gas well›s faulty concrete casing and hydraulic fracturing pushing methane into an aquifer and causing the explosion: at least 1,000 gallons of fracturing fluid, including about 150 gallons of oil, leaked out of the well pipes and possibly out into the ground.[55]

One Dead in Natural Gas Explosion An explosion at an oil and gas well on July 16, 2012 killed a 19-year-old man. The cause of the explosion was not immediately known.[56]

70,000 Fish Died Statoil caused a blowout and fire 2014 at a city of Clarington, Monroe County fracking well that contaminated an Opossum Creek, killed 70,000 fish, and forced approximately 25 people from their houses. Halliburton was fracking the well at the time of the incident.  Halliburton  delayed releasing details on fracking chemicals after the spill.[57] The Environmental Integrity Project 2014 study  “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,”  found that the fire at the well in Clarington, Ohio, in June 2014 involved 16 different hydraulic fracturing  products, including diesel fuel. Nine thousand gallons of diesel was found on the well pad after the blowout.  Benzene, xylene,  naphthalene, and toluene were found. An EPA official also found hydrochloric acid, cesium-137 sources, terpenes, terpenoids, isoproponal, ethylene glycol, paraffinic solvents, sodium persulfate, tributyl tetradecyl phosphonium chloride, as well as other chemicals on the well pad. Firefighting efforts and flow back from well caused the chemicals to enter a tributary of Opossum

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Creek that flows to the Ohio River. Firefighting efforts and flow back from[58]

Pipeline Explosion In January 2015, an Enterprise Products owned pipeline exploded. It caused nearly 24,000 barrels of Marcellus and Utica shale ethane to burn five acres of Brooke County woodland. The accident also damaged a home 2,000 feet away. [59] State revenues According to Innovation Ohio, the state’s severance tax ranks near the bottom among oil and gas states that levy a severance tax, with a rate at $.03 per MCF (1000 cubic feet) for gas and $.20 per barrel for oil.[60] According to Gasland filmmaker Josh Fox, the gas industry tells Ohio representatives how much gas has been extracted and pays taxes to the state based on that figure, without oversight or monitoring; the state, in fact, lacks the authority to check meters at the wellhead and compare those readings against the figures turned in by producers.[61]

Jobs A 2013 report published by Cleveland State University, “Ohio Utica Shale Region Monitor,” found that overall spending in Ohio counties with the highest shale reserves increased by 21.1 percent in 2012, compared with a 6.4 percent increase in counties where no fracking was underway. Yet employment grew by 1.4 percent between 2011 and 2012 for the former, and 1.3 percent for the latter, suggesting the higher spending did not translate into more jobs. The Ohio Department of Job and Family Services (JFS) has stated that employment in fracking core-industry businesses such as pipeline construction and well drilling was up 15.5 percent in the second quarter of 2012, compared to the prior-year period.[62] In December 2013 JFS concluded that direct employment from oil and gas activity increased from 6,263 jobs in the first quarter of 2011 to 8,192 in the first three months of 2013. Ohio’s Mothers Against Drilling in Our Neighborhoods (MADION) has argued that the number of jobs created by fracking should be measured against the possible impacts and loss of jobs in other industries such as farming, dairies, and tourism.[63]

Fracking in the USA 589 Lobbying and donations The 2011 Common Cause report,  “Deep drilling, deep pockets, in Washington and Ohio,”  found that from 2001 through June 2011, the fracking industry gave $20.5 million to current members of Congress and spent $726 million on lobbying.” For Ohio, Rep. John Boehner led Ohio’s Congressional delegation with $186,900, followed by Sen. Rob Portman with $91,000, Rep. Steve Chabot with $59,050, and Rep. Steve Stivers with $51,250. The report also tracked $2.8 million in campaign contributions to Ohio’s state elected officials and notes that Ohio’s fracking regulations as of 2011 were among the weakest of any state. Gov. John Kasich was the leading individual recipient with $213,519, followed by former Gov. Ted Strickland with $87,450 and Secretary of State John Husted with $84,750.[64] Truthout analysis of Gov. Kasich campaign records showed that wealthy executives of companies connected to the natural gas industry, including billionaires William I. Koch (founder of the fracking Oxbow Corporation) and David Koch (of Koch Industries), funneled an additional $127,268 in personal donations through a political action committee (PAC) to support Kasich’s election in 2010. The money went to a PAC organized by the Republican Governors Association (RGA); the PAC used a majority of the money to pay for attack ads against former Ohio governor Strickland, whom Kasich defeated in 2010.[65] According to Truthout: Building a Better Ohio and Gov. Kasich received support from Make Ohio Great, a front group for the Republican Governors Association (RGA), which spent $11 million supporting Kasich in the 2010 election. Make Ohio Great did not reveal the amount of money it gave to Building a Better Ohio or spent on ads defending SB 5 (an anticollective-bargaining bill), but a look at its 2010 records revealed that the RGA middle-manned money from private health care companies and corporations like Coca-Cola and Wal-Mart, allowing out-of-state interests to silently support Kasich’s campaign.[66] Citizen activism Ohio governor, fracking, and Koch contributions On February 7, 2012, Ohioans rallied against Gov. John Kasich’s “open door” policy of natural gas extraction and fracking wastewater injection wells, and called for a committee hearing on SB 213 and HB 345, which would halt oil/gas drilling operations and wastewater disposal injection wells in the state until the EPA finishes a study examining whether there is a link between fracking drill sites and contaminated drinking water.[67]

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June 2012: People’s Assembly Environmental activist Bill McKibben, 350.org, Gasland director Josh Fox, and Ohio environmental activists and groups are aiming to assemble what they hope in a public letter will be the largest demonstration against natural-gas fracking in U.S. history. The action will happen in Columbus, Ohio on June 14–17, culminating on the last day with a takeover of the statehouse for “a people’s assembly” to pass legislation to stop fracking in the state. The actions were in response to Ohio Governor John Kasich’s efforts to increase fracking in the state. The protest organizers also want to take advantage of Ohio’s swing-state status: “as the nation’s attention turns to Ohio for the election this fall, it is a fitting place to make a stand and say that this process must stop once and for all.”[68]

June 2012: Moratorium on Water Sales Less than a week after dozens of environmental activists rallied outside its annual meeting, the Muskingum Watershed Conservancy District reversed course in June 2012 and decided to temporarily halt the sale of water to oil and gas drillers.[69]

July 2012: Residents Blockade Ohio Injection Well It was reported on July 16, 2012 that Ohio residents blocked access to an injection well in Trumbull County, protesting “the failure of Ohio regulators to adequately test and monitor dumping of toxic fracking waste.” One activist locked himself to the gate to prevent trucks from entering the site. Two activists were detained, and the supporter locked to the gate was eventually and safely removed by authorities and placed under arrest.[70]

November 2012: Mansfield Bill of Rights In the November 2012 election Mansfield voters approved a community bill of rights prohibiting hydraulic fracturing injection wells in the city, located in the Utica Shale basin between Cleveland and Columbus. Industry front groups including  Energy in Depth  (EID) and  Energy Citizens  (a front group of the  American Petroleum Institute) led the charge in the  astroturf campaign to try and defeat the bill.[71]

Fracking in the USA 591

March 2013: Groups Call for EPA to Step in Over Fracking Wastewater In March 2013, three activist groups asked the EPA to supersede Ohio’s authority in regulating fracking waste disposal. The Ohio office of the Center for Health, Environment and Justice; Progress Ohio; and the Buckeye Forest Council jointly issued a request for EPA action on Mar. 2013, arguing in a letter that the Ohio Department of Natural Resources has not done enough in its oversight of fracking waste. It was reported that an “EPA spokesman said the agency is reviewing the letter, which calls for the federal body to audit and investigate the Ohio DNR. Under a national program, Ohio has the right to monitor its own wells, but a string of recent incidents led the coalition of environmental and community groups to question the state’s effectiveness.”[72]

July 2013: Hundreds Protest Fracking Waste According to EcoWatch in July 2013, a “coalition of local, statewide and national groups concerned about toxic waste from hydraulic fracturing ... converged on Portage and Trumbull counties ... for Don’t Frack Ohio 2.0. The coalition called for an end to the state being used as a regional dumping ground for oil and gas waste. The rally drew 250 participants in an area heavily targeted by the oil and gas industry for disposal of toxic radioactive drilling waste from fracking.”[73]

November 2014: Lawsuit Challenges Radioactive Fracking Waste Facilities in Ohio On November 19, 2014, two environmental groups filed a lawsuit on behalf of residents in Youngstown, Ohio, which challenged the temporary approval of 23 fracking waste facilities. The suit claimed, “that the Ohio Department of Natural Resources (ODNR), which regulates the oil and gas industry, broke the law when it issued temporary orders allowing the waste facilities to begin operating without first taking comments from the public and completing a formal rule-making process to regulate the facilities. Ohio Gov. John Kasich is also named in the lawsuit.”[74] Legislation and regulations In 2004, the Ohio General Assembly gave the state Department of Natural Resources, “sole and exclusive authority to regulate the permitting, location and spacing of oil and gas wells.”[75]

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In October 2013, the Ohio Supreme Court said it would hear an appeal from the city of Munroe Falls in Summit County to determine if local governments in the state have authority to regulate fracking.[75]

Ongoing Well inspections The ohio department of natural resources plans to triple the number of its field inspectors to about 90 to ensure that wells are being properly built and operated. This is how Ohio well inspections compaere with those in foure\ other states. Ohio Year

Wells

Inspectors

Inspections

% Inspected

2009

64,427

25

12,456

19%

2010 2011

64,378

25

10,472

64,481 N.A.

11,842 N.A.

16% 18%

2012

30 36

Wells

Inspectors

Inspections

% Inspected

63,548 68,842

84

14,544

23%

84

16,199

24%

69,000 N.A.

84

35%

84

23,807 8,293

Pennsylvania Year 2009 2010 2011 2012 Oklahoma Year

–

–

Wells

Inspectors

Inspections

% Inspected

2009

125,000 147,000 180,000

73,661 58,424

59%

2010 2011

63 56 57

52,237

2012

N.A.

59

43,062

29% –

40%

Colorado Year

Wells

Inspectors

Inspections

% Inspected

2009

40,956

15

2010 2011

43,354 46,835

15 15

9,991 17,075

24% 39%

2012

47,263

15

12,071 2,907

26% –

Texas Year

Wells

Inspectors

Inspections

% Inspected

2009

278,700

83

128,270

46%

2010 2011

282,896 284,142

87

121,667

43%

2012

285,896

88 153

114,878 63,756

40% –

Fracking in the USA 593 State drilling inspections Modernize Injection Well Laws  - Introduced March 2012, sponsored by Rep. Jay P. Goyal. - Would require water testing and community approval before an injection well is approved, and would require recycling of fracking wastewater, reducing the overall demand for disposal wells. SB 213 and HB 345 — would halt drilling operations for oil and gas extraction, as well as wastewater disposal injection wells, until the U.S. Environmental Protection Agency finishes a study examining whether there is a link between fracking drill sites and contaminated drinking water.[76] HB 133, introduced by Rep. John Adams in 2010, would allow leasing state land, such as parks and universities, for natural gas and oil drilling.[77] The Fracturing Responsibility and Awareness of Chemicals Act (H.R. 2766), (S. 1215)--was introduced to both houses of the United States Congress on June 9, 2009, and aims to repeal the exemption for hydraulic fracturing in the Safe Drinking Water Act.[78]

Enacted SB 315 - Introduced March 22, 2012. Sponsored by Senator Shannon Jones. Proposes changes by Governor Kasich’s administration to Ohio’s fracking laws. Requires drillers to conduct baseline testing of local water supplies within 1,500 feet of planned fracking sites. Requires disclosure of chemicals used in servicing a well, but not drilling it, and has exemption for proprietary chemicals. Would impose a new, up front $25,000 per well impact fee on drillers for local governments, but the full $25,000 fee could be recouped by drillers as a discount on property tax payments. [79]   On May 15, 2012, the Ohio Senate passed SB 315 by a vote of 27-6. The bill had been amended by the Ohio Senate Energy and Public Utilities Committee. Among the changes introduced was the medical gag rule, which reads: A medical professional who receives information pursuant to [trade secret chemicals] shall keep the information confidential and shall not disclose the information for any purpose that is not

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Fracking 2nd Edition related to the diagnosis or treatment.[80] The bill would also allow institutions to build heating and power plants fired by natural gas and get credit for them as renewable energy -- credits that currently go to help finance wind farms.[81] At least 33 of the 45 Ohio legislators who co-sponsored SB 315 are ALEC members, and language from portions of the state Senate bill is similar to ALEC’s “Disclosure of Hydraulic Fracturing Fluid Composition Act.”[82]  The bill was signed into law by Gov. Kasich on June 12, 2012.[83] SB 165: Ohio Gas Rule Revisions - Became operational on July 1, 2010. The act sets out plans to increase setbacks for wells in urban areas, requires some disclosure of fracking fluids, dates permitting fees, and includes noise pollution and land use protections. Sec. 1509.04(A), which states that the enforcement authority of the chief of the division of mineral resources management “includes the authority to issue compliance notices and to enter into compliance agreements,” has been criticized by communities who say it allows companies to sidestep violations and thus penalties. House Bill 278  - enacted in 2004, the law gave the Ohio Department of Natural Resources sole authority to regulate oil and gas wells, stripping local governments of any authority over placement or permitting of wells.

Controversy House Bill 487, introduced by House Finance Chairman Ron Amstutz on Ohio Gov. Kasich’s behalf, included language that the group Plunderbund later claimed was provided by the Ohio Oil and Gas Association (OOGA). Specifically, the bill’s section on impact fees is almost verbatim with OOGA’s proposed language for inclusion in Kasich’s legislation: “the only change we can identify is the fee was set at $25,000, not $20,000 as proposed by OOGA,” according to Plunderbund. Representatives of the oil/gas industry (including Christina Polesovsky of the Ohio Petroleum Council and wife of Governor’s office staffer, Jeff Polesovsky) met with the Governor’s office staff twice during the week of February 12, 2012, and followed up less than a week later via OOGA’s lobbyist, Fred Mills, with a copy of the proposed language.[84] At least 33 of the 45 Ohio legislators who co-sponsored SB 315 are ALEC members, and language from portions of the state Senate bill is

Fracking in the USA 595 similar to ALEC›s Disclosure of Hydraulic Fracturing Fluid Composition Act. ALEC›s website says Ohio Gov. John Kasich participated in the group during its formative years. Kasich has not only signed a number of ALECinfluenced bills into law, he also introduced major initiatives in his 2011 State of the State address that were similar or identical to ALEC proposals taking root in other states.[85] Various economic analyses have found that SB 315’s minor tax on individual wells is offset by new tax breaks on property taxes and other tax breaks, resulting in the gas industry paying less in Ohio taxes than any other state in the country, and SB 315 contains no public notice, no public comment, and no right to appeal for drill sites, pipelines, or compressor stations.[86] For fracking chemical disclosure, Ohio state law passed in 2001 requires that drilling companies share information about hazardous chemicals only with the Ohio Department of Natural Resources, and not with emergencymanagement officials and first responders. In May 2013, EPA officials sent a letter to state emergency officials stating that the federal Right-to-Know Act of 1986, requiring companies to share a hazardous-chemical inventory with local officials, supersedes the Ohio disclosure law.[87] It was reported that the laws adopted in 2001 favoring the oil and gas industry violate “federal laws designed to protect communities facing chemical emergencies.”[88] Lawsuits

Water Contamination In March 2012, two Medina County couples filed two lawsuits against Delaware-based Landmark 4 LLC in connection with drilling in 2008 at nearby Allardale Park, Ohio. The suits say the drilling discharges caused the two families to incur “health injuries, loss of use and enjoyment of their property, loss of quality of life, emotional distress and other damages.” The suits allege Landmark 4 failed to provide sufficient cement for below-ground casings at two wells, and seek damages in excess of $75,000 each, along with court-supervised medical testing due to alleged toxic exposures.[89]

Brine Water as a De-Icer In March 2012, Duck Creek Energy Inc. of Brecksville filed a defamation lawsuit against fracking activists Tish O›Dell and Michelle Aini, asking the court to prohibit them from describing the company›s AquaSalina (used

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to defrost roads with salty brine water) as a product of fracking” or environmentally unsafe. Duck Creek seeks $1 million in punitive damages in its complaint in Cuyahoga County Common Pleas Court.[90] The defendants, members of the group “Mothers Against Drilling in Our Neighborhoods” that is trying to block drilling in Cuyahoga County suburbs, filed a counterclaim for $1 million.[90] Duck Creek is a gas and oil production company concentrated in Cuyahoga, Mahoning, Trumbull and Portage counties. It taps the Clinton sandstone layer, some 3,500 to 5,500 feet below ground. Duck Creek says it uses fracking in its wells, with about half of the frack water coming back up the well almost immediately, with the rest emitted over a period of one to three months.[90] Company President David Mansbery said frack water isn’t used in its AquaSalina de-icer (defroster). Instead, the company uses the salty water that follows during the extraction of gas, which it says is “natural” and comes from the remains of an ancient sea in the sandstone layer. Duck Creek purifies it at its filtering plant at Mittal Steel. Duck Creek attorney Robert Zimmerman said the company asked O’Dell and Aini to stop making the “false statement” that that the company uses “toxic fracking” water in its road de-icer, and sued them when they would not.[90] O’Dell and Aini state in their counterclaim that AquaSalina contains  benzene, a carcinogen, and other toxic and hazardous substances. Attachments to the counterclaim include:[90] A November 2011 analysis of a brine sample that Duck Creek had tested by independent environmental lab Precision Analytical. The lab found traces of benzene, ethyl benzene and toluene, which probably came from residual crude oil droplets, Precision Analytics President Cary Mathias said. A copy of meeting minutes from Broadview Heights in which Service Director Raymond Mack said the city “would no longer purchase AquaSalina for use on road salt” given that “benzene is a cancer-causing chemical.”

Constitutionality of State Law Reaches Ohio Supreme Court In September 2013, it was reported that litigation over the constitutionality of “Ohio’s law R.C.1509.02 granting sole authority to the Ohio Department

Fracking in the USA 597 of Natural Resources to regulate activities associated with oil and gas exploration and production has reached the Ohio Supreme Court.” A host of Ohio cities challenged the law. As reported, “First assert that ‘community of character is of immense importance to the health, identity, and economic viability of Ohio’s communities.’ Building on this notion, the Amici contend that ‘hydrofracking is a heavy industrial process with the potential to [adversely impact] community character and development goals of Ohio’s local communities.’ Here, the Amici reference, among other things, damage to surface waters, emission of airborne toxics and other air pollutants, and operational noise in support of their position that hydrofracking poses harmful risks to community character.”[91] Companies American Energy Ohio Holdings LLC - the fundraising arm of oil and gas venture American Energy Partners LP, created by former  Chesapeake Energy  CEO  Aubrey McClendon. Former  ExxonMobil  CEO  Lee Raymond  is director.[92] Chesapeake Energy  - has eight drilling rigs in Ohio and expects to have 20 rigs by late 2012 and 30 by 2014, with 800,000 acres of leases in the Utica shale. It plans to install 200 miles of pipeline for the expansion. The company said its pre-drilling surveys had detected potentially troublesome levels of methane gas in drinking water in Plain and Osnaburg townships in Stark County. Evidence of the problem was also detected in Pike and Sandy townships.[93][94] Chevron - has several thousand acres leased in Marshall and Ohio counties.[95] D&L Energy ExxonMobil  subsidiary  XTO Energy  - XTO plans to drill its first Ohio Utica Shale well just south of the former Key Ridge Elementary School in Belmont County, state records show. Public records also confirm oil giant Exxon has at least 52,334 acres leased for drilling in Belmont and Monroe counties.[96] Citizen groups

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Statewide

Fracking opponent Abram Loeb Balanced Nation (Facebook) Buckeye Forest Council Concerned Citizens Ohio EcoWatch Frack Free Ohio Green Environmental Coalition Mothers Against Drilling in Our Neighborhoods No Frack Ohio (website) No Frack Ohio (Facebook) NEOGAP Ohio Citizen Action Ohio Environmental Council Ohio Fracktion Ohio Sierra Club Ohio Student Environmental Coalition People›s Oil & Gas Collaborative- Ohio Progress Ohio EarthJustice Ohio Ecological Food and Farm Association

Local, County, Regional Ashtabula County: Ashtabula County Water Watch Athens County: Athens County Fracking Action Network Athens County:  Slow Down Fracking in Athens County (SD-FRAC)

Fracking in the USA 599 Carroll County: Carroll Concerned Citizens Carroll County: Stop Hydraulic Fracturing in Carroll County Poland Village: SASS - Sisters Against Subterranean Sludge Concord: Network for Oil & Gas Accountability & Protection Coshocton County:  Coshocton Citizens for Truth About Fracking Cuyahoga County: Burning River Anti-Fracking Network Fairfield County:  Ban Hydro-fracking in Greenfield Township (Facebook) Geauga County: Frack Free Geauga (nofrackgeauga@gmail. com) Greene County:  Gas and Oil Drilling Awareness and Education or http://swohionofrack.org/ Hamilton County:  SW Ohio No Frack Forum; also  http:// www.facebook.com/SwOhioNoFrackForum Lake Mohawk: Don’t Frack Lake Mohawk Licking County: Concerned Citizens of Licking County Mahoning County: Frackfree Mahoning Mansfield: Don’t Frack Mansfield Mansfield: Citizens Against the Dumping of Fracking Waste in Mansfield, Ohio Medina County: Medina County Concerned Citizens Morgan County: Fracking MoCo North Royalton: Protect Our Families and Homes Portage County: Concerned Citizens for Portage County Rocky River: West Shore FaCT (Faith Communities Together for Frac Awareness) - contact [email protected] Shalersville: Shalersvilleagainstfracking Southeast Ohio: Southeast Ohio Alliance to Save Our Water From Fracking Southeast Ohio: Southeast Ohio Fracking Interest Group Stark County: Stark Concerned Citizens - contact crborello@ aol.com Stark County: Frack Free Stark County (Facebook) Tuscarawas County: Don’t Frack With Tuscarawas County Washington and Marietta: Southeast Ohio Fracking Interest Group - contact [email protected] Warren:  Standing Together Against Neighborhood Drilling (STAND) Williams County: Williams County Alliance - contact [email protected]

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Industry groups FracFocus: the hydraulic fracturing chemical registry website,  a joint project of the  Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. Landowners for Energy Access and Safe Exploration Reports

The Environmental Integrity Project on Diesel in Fracking Reclamation The 2013 Environment Ohio Research & Policy Center report, Who Pays the Cost of Fracking? analyzes Ohio’s financial assurance requirements for insurance and reclamation of state oil and gas drilling operations. The report argues that Ohio’s bonding requirements do not cover the full costs, as 1.) drilling operators are only required to secure $5,000 in bonds per well front, compared to leading states that require $250,000, and 2.) Ohio’s requirement for liability insurance is a blanket statewide amount, so drillers have the same $5 million cap whether they operate one well or hundreds of wells.

Jobs In the 2013 report  “Ohio Utica Shale Region Monitor,”  researchers at Cleveland State University analyzed total employment for 2011 and 2012 in 13 eastern Ohio counties where shale gas and oil production was under way, and compared the data to the rest of the state. The researchers found that employment growth due to shale development was not evident: employment rose 1.4 percent year-over-year in counties with heavy or moderate shale production, compared to 1.3 percent in other counties without shale development.[97]

2012 recommended State Fracking Policies The 2012 report  “Fracking, Fairness and the Future: Making Sure Ohio Taxpayers and Workers Share in Benefits” by the group Innovation Ohio

Fracking in the USA 601 argues that “Ohio’s current severance tax ranks near the bottom among oil and gas states that levy a severance tax,” with a rate at $.03 per MCF (1000 cubic feet) for gas and $.20 per barrel for oil. The report recommends raising Ohio’s oil and gas severance tax to 7.5 percent on natural gas and 4.6 percent on oil and natural gas liquids, “which would raise nearly $2.5 billion from the extraction of natural gas over 10 years and could result in additional tax collections of $5.9 to $25.3 billion on estimated oil shale reserves.”[98]

Costs of Fracking The 2012 Environment Ohio Research & Policy Center  “The costs of fracking”  estimates the full costs of fracking the state, including water contamination, health and environmental impacts, and the effects on the state economy and infrastructure.

References 1. Fracking, Fairness and the Future: Making Sure Ohio Taxpayers and Workers Share in Benefits, Innovation Ohio, 2012 Report. 2. Fracking, Fairness and the Future: Making Sure Ohio Taxpayers and Workers Share in Benefits, Innovation Ohio, 2012 Report. 3. ODNR Releases Preliminary Report on Youngstown Area Seismic Activity, ODNR, Mar. 9, 2012. 4. Gas Slump Hits America›s Biggest Fracking Field, Reuters, Dec. 2, 2015. 5. Mike Ludwig, Kasich, Koch and Big-Industry Bucks: Why Ohio Is the Next Fracking Frontier, Truthout, Nov. 29, 2011. 6. Poll: 40 Percent of Voters Unfamiliar with Fracking WKBN, Jan. 19, 2012. 7. Ohio Fracking Review: Mar. 2012, Innovation Ohio, Apr. 4, 2012. 8. New fracking data shows Ohio could lose $160 million in one year by inaction, Innovation Ohio, Apr. 3, 2012. 9. Oil and Natural Gas Well and Shale Development Resources  Ohio.gov, accessed Dec. 24, 2012. 10. Dana Jay, Governor Kasich talks Fracking and Taxes, ABC, Apr. 6, 2012. 11. Brian Powell,  The Cleveland Plain Dealer Misses The Mark On Kasich›s Fracking Tax Proposal, Media Matters, Mar. 7, 2012. 12. Confirmed: Fracking caused Ohio earthquakes, RT, Jan. 3, 2012. 13. Eric Niiler,  Geologists say Ohio quakes directly tied to fracking  MSNBC, Jan. 6, 2012. 14. Bob Downing,  Northeast Ohio rocked by 11th earthquake linked to Youngstown injection wells, Akron Beacon Journal Online, Jan. 1, 2012

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15. ODNR Releases Preliminary Report on Youngstown Area Seismic Activity, ODNR, Mar. 9, 2012. 16. Won-Young Kim,  Induced seismicity associated with fluid injection into a deep well in Youngstown, Ohio, Journal of Geophysical Research, Volume 118, Issue 7, pages 3506–3518, Jul. 2013. 17. Ohio geologists link local earthquakes directly to fracking, Al Jazeera, Apr. 12, 2014. 18. Fracking caused earthquakes in existing faults in Ohio, study says  Don Hopey, Pittsburgh Post-Gazette, Jan. 5, 2015. 19. Zahra Hirja, “Alberta Earthquakes Tied to Fracking, Not Just Wastewater Injection,” Inside Climate News, Aug 6, 2015. 20. Can the shale gas boom save Ohio? The Washington Post, Mar. 3, 2012. 21. Oil and Natural Gas Well and Shale Development Resources,  Ohio Department of Natural Resources, accessed Feb. 2012. 22. Interactive Map of Eastern Ohio Well Permits, EcoWatch, Jan. 13, 2012. 23. Ohio Fracking Review: Mar. 2012, Innovation Ohio, Apr. 4, 2012. 24. Ohio Fracking: State Agency Proposes Rules For Drilling In State Parks, Huffington Post, Apr. 12, 2012. 25. Deirdre Shesgreen, Federal government considering Wayne National Forest land for fracking, The Post, Nov 11, 2015. 26. Alex Meyer,  Federal government considering Wayne National Forest land for fracking, The Post, Nov. 11, 2015. 27. Kasich signs order against Lake Erie drilling, Toledo Blade, Jul. 11 2012. 28. Kate Sheppard,  John Kasich›s Advisers Knew Of Plan To Target ‹EcoLeft› As State Promoted Fracking Effort, Huffington Post, Feb. 18, 2014. 29. Tim Kellison, “Fracking may lead to decline in visitation in public parks,” UF News, Aug. 27, 2015. 30. Spencer Hunt, “State The Columbus Dispatch, Jun. 17, 2012. 31. Shane Hoover, “Thirsty wells: Fracking consumes billions of gallons of water,” CantonRep.com, Sept. 21, 2014. 32. Water in at least three U.S. states is polluted from FRACKING as hundreds of complaints are reported across the country, Associated Press, Jan. 6, 2014. 33. First-Ever Fracking Wastewater Test in Ohio Reveals Stew of Hazardous Toxins, EcoWatch, Jul. 2, 2012. 34. Naveena Sadasivam, “In Fracking Hotbed, a Muted Approach to Regulation,” ProPublica, May 13, 2014. 35. Eric Niiler,  Geologists say Ohio quakes directly tied to fracking  MSNBC, Jan. 6, 2012. 36. Fracking Fluid Soaks Ohio, Bloomberg, Mar. 22, 2012. 37. Mark Niquette,  Ohio Tries to Escape Fate as a Dumping Ground for Fracking Fluid, SF Gate, Feb. 2, 2012. 38. Underground Injection Control (UIC), ODNR, accessed Apr. 2012. 39. Fracking Fluid Soaks Ohio, Bloomberg, Mar. 22, 2012.

Fracking in the USA 603 40. Mark Niquette,  Ohio Tries to Escape Fate as a Dumping Ground for Fracking Fluid, Bloomberg, Jan. 31, 2012. 41. Dan O›Brien,  ODNR Orders Kleese to Shut Down 5 Injection Wells, Business Journal, Apr. 7, 2015. 42. No more brine wastewater for Warren as of April 1, EPA says,  Vindy. com, Mar. 19, 2012. 43. Bernhard Debatin,  Study on fracking health risks reinforces call for moratorium, The Athens News, Jan. 16, 2012. 44. Rebecca Hammer, “In Fracking’s Wake: New Rules are Needed to Protect Our Health and Environment from Contaminated Wastewater,”  NDRC Document, May 2012. 45. Jamison Cocklin and David Skolnick,  Public outcry continues over Hard Rock›s dumping in Youngstown, Vindy.com, Feb. 7, 2013. 46. Spencer Hunt,  2014 Major Criminal Cases,  United States Environmental Protection Agency, Retrieved Oct. 9, 2015. 47. Spencer Hunt,  2014 Major Criminal Cases,  United States Environmental Protection Agency, Retrieved Oct. 9, 2015. 48. Spencer Hunt,  Ohio EPA: Fracking wastes, streams still cannot mix,  The Columbus Dispatch, Jul. 05, 2012. 49. Spencer Hunt, Big lagoons could hold Ohio fracking waste, The Columbus Dispatch, Oct 11, 2013. 50. Casey Junkins, “Radioactive Frack Waste Processed in Martins Ferry,” Wheeling News-Register, Jul. 12, 2015. 51. Fracking Waste Being Stored at old Wheeling Pitt Steel in Martins Ferry, Wtrf.com, Jul. 13, 2015. 52. NiSource Gas Transmission and Storage›s Midstream Services Announces Major Investment in The Midstream Solution for Ohio Utica Shale, PR Newswire, Feb. 29, 2012. 53. Ohio’s Resurgent Natural Gas Industry Spends Millions to Set Up Shop Keith Schneider, New York Times, Mar. 12, 2013. 54. Dillon Transport company site, accessed, Mar. 13, 2013. 55. Abrahm Lustgarten,  Officials in Three States Pin Water Woes on Gas Drilling, ProPublica, Apr. 26, 2009. 56. Bob Jones, “One dead in Bolivar natural gas explosion,”  Newsnet, Jul. 5 2012. 57. StatOil fined $223,000 over Ohio fracking-well fire,  The Columbia Dispatch, Sept. 16, 2015. 58. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 59. Casey Junkins, “One dead in Bolivar natural gas explosion,”  The Intelligence Wheeling News Register, Jan. 30, 2015. 60. Fracking, Fairness and the Future: Making Sure Ohio Taxpayers and Workers Share in Benefits, Innovation Ohio, 2012 Report.

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61. Josh Fox, We Won’t Be Silenced, EcoWatch, Feb. 7, 2012. 62. Jeff Bell,  “Shale drilling jobs up through 1st half of 2012, state report says,” Columbus Business First, Mar. 4, 2013. 63. John Upton,  “Ohio fracking boom has not brought jobs,”  Grist, Mar. 22, 2013. 64. James Browning & Alex Kaplan,  Deep drilling, deep pockets, in Washington and Ohio, Common Cause, 2011. 65. Mike Ludwig,  Kasich, Koch and Big-Industry Bucks: Why Ohio Is the Next Fracking Frontier, Truthout, Nov. 29, 2011. 66. Mike Ludwig,  Ohio Labor Movement Defeats Anti-Union Bill and Its Wealthy Supporters, Truthout, Nov. 9, 2011 67. EVENT: Fracking Protest at Ohio Gov. Kasich’s State of the State on Feb. 7, EcoWatch, Feb. 6, 2012. 68. Ohio fracking is latest target for anti-Keystone activists, Grist, Apr. 10, 2012. 69. Russ Zimmer, Conservancy district stops fracking water sales, CentralOhio. com, Jun. 8, 2012. 70. Scott Parkin, “Mid-West Fracking Actions Escalate As Residents Blockade Ohio Injection Well,” It›s Getting Hot in Here, Jul. 16, 2012. 71. Steve Horn,  “Chesapeake Energy Tied to Mansfield, OH Bill of Rights Astroturf Attack,” DeSmogBlog, Nov. 6, 2012. 72. OHIO: Groups call for EPA to step in over fracking wastewater, E&E News, Mar. 20, 2013. 73. Hundreds Protest Radioactive Fracking Waste in Ohio,  EcoWatch, Jul. 30, 2013. 74. Lawsuit Challenges Radioactive Fracking Waste Facilities in Ohio,  Mike Ludwig, Truthout, Dec. 1, 2014. 75. 75.0  75.1  Casey Junkins,  Ohio Supreme Court to check in on drilling, Ogden Newspaper, Oct. 13, 2013. 76. EVENT: Fracking Protest at Ohio Gov. Kasich’s State of the State on Feb. 7, EcoWatch, Feb. 6, 2012. 77. The ‹Fracking› Of Ohio State Parks Progress Ohio, Mar. 16, 2011. 78. The ‹Fracking› Of Ohio State Parks Progress Ohio, Mar. 16, 2011. 79. Kasich adopts one of IO’s recommendation on fracking law, falls short on others, Innovation Ohio, Mar. 23, 2012. 80. Ohio Senate passes Kasich fracking bill with medical gag rule added, Ohio Citizen Action, May 15, 2012. 81. John Funk,  Ohio Senate wants fracking chemicals identified but neglects wind farms, The Plain Dealer, May 15, 2012. 82. ALEC slips Exxon fracking loopholes into new Ohio law, Greenpeace, May 31, 2012. 83. Marc Kovac,  Ohio Gov. John Kasich calls energy legislation tough but fair,” Ravenna Record Courier, Jun. 12, 2012. 84. Exclusive Kasich allows oil & gas industry to write portions of fracking legislation, Plunderbund, May 23, 2012.

Fracking in the USA 605 85. ALEC slips Exxon fracking loopholes into new Ohio law, Greenpeace, May 31, 2012. 86. ALEC slips Exxon fracking loopholes into new Ohio law, Greenpeace, May 31, 2012. 87. Spencer Hunt, “Companies The Columbus Dispatch, Jun. 26, 2013. 88. U.S. EPA Confirms that Ohio statute favoring the fracking industry violates federal safety laws, The Morrow County Sentinel, Jul. 15, 2013. 89. Bob Downing,  Medina County couples file federal lawsuits over problems with wells, Beacon Journal, Mar. 14, 2012. 90. 90.0 90.1 90.2 90.3 90.4 Alison Grant, Deicer not fracking water, Duck Creek says in defamation lawsuit, The Plains Dealer, Mar. 29, 2012. 91. Local Ohio Communities Allied In Defense Of Ohio’s Home-Rule, Oil And Gas Showdown To Be Held In Ohio Supreme Court, MonDaq, Sept. 24, 2013. 92. 2 of energy›s heaviest hitters partner up in Ohio›s Utica, E&E News, Oct. 18, 2013. 93. Bob Downing, Chesapeake unveils system to recycle waste water from ‘fracking’ drill sites, Ohio.com, Feb. 9, 2012. 94. Can the shale gas boom save Ohio? The Washington Post, Mar. 3, 2012. 95. Casey Junkins, Exxon Is Drilling First Ohio Utica Shale Well: Oil companies continue to acquire local land,  The Intelligencer / Wheeling News-Register, Feb. 7, 2012. 96. Casey Junkins, Exxon Is Drilling First Ohio Utica Shale Well: Oil companies continue to acquire local land,  The Intelligencer / Wheeling News-Register, Feb. 7, 2012. 97. John Funk, Ohio shale gas development produced a spending surge in 2012 but not many new jobs, Cleveland State University study shows, The Plain Dealer, Mar. 19, 2013. 98. Fracking, Fairness and the Future: Making Sure Ohio Taxpayers and Workers Share in Benefits, Innovation Ohio, 2012 Report.

Oklahoma Oil output has doubled in the state since the start of 2010, from 160,000 to 320,000 barrels per day, primarily due to fracking for tight oil.[1] Oklahoma is part of the Caney and Woodford Shales, which are sites of drilling and fracking. The state also has thousands of injection and disposal wells,[2] which have been linked to a 5.7 earthquake in the state in 2011.[3] Drilling wells In 2009, the state had more than 32,000 oil wells, almost 9 percent of the U.S. total.[4] Continental Resources, the leading tight oil producer in the Williston Basin beneath North Dakota and Montana, revealed in 2012 that

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its next big target for development is an area southeast of the Cana play it has called the South Central Oklahoma Oil Province (SCOOP).[4] It was estimated that in 2012, Oklahoma had fracked 2,694 wells.[5] Shale plays According to the U.S. Energy Information Administration (EIA), there are three prospective shale plays in the state: the Ardmore, Arkoma and Cana basins, all of which contain parts of the Woodford formation. The Mississippian is also a tight oil formation.[4]

Caney Shale, Oklahoma The Caney Shale in the Arkoma Basin is the stratigraphic equivalent of the Barnett Shale in the Ft. Worth Basin. The formation has become a gas producer since the large success of the Barnett play. Bill Grieser:  Caney Shale, Oklahoma’s shale challenge, PDF file, retrieved 25 Feb. 2009.

Woodford Shale, Oklahoma The Devonian Woodford Shale in Oklahoma is from 50 to 300 feet (15 – 91 m) thick. Although the first gas production was recorded in 1939, by late 2004, there were only 24 Woodford Shale gas wells. By early 2008, there were more than 750 Woodford gas wells.[6][1]Like many shale gas plays, the Woodford started with vertical wells, then became dominantly a play of horizontal wells. The play is mostly in the Arkoma Basin of southeast Oklahoma, but some drilling has extended the play west into the Anadarko Basin and south into the Ardmore Basin.[7] The largest gas producer from the Woodford is  Newfield Exploration; other operators include  Devon Energy,  Chesapeake Energy,  Cimarex Energy,  Antero Resources,  St. Mary Land and Exploration,  XTO Energy,  Pablo Energy,  Petroquest Energy,  Continental Resources, and  Range Resources. Production from the Woodford Shale has peaked and is now in decline, however.[8] Oklahoma Geological Survey: Map of Woodford shale wells, accessed 25 Feb. 2009. Brian J. Cardott:  Overview of Woodford gas-shale play in Oklahoma, 2008 date, PDF file, retrieved 25 Feb. 2009.

Fracking in the USA 607 Disposal wells here for an interactive map of disposal wells. As of 2012, there are an estimated 11,000 private and commercial injection and disposal wells in Oklahoma. Each year those wells are injected with billions of gallons of oil and gas wastewater, according to the Oklahoma Corporation Commission -- 8.8 billion gallons of wastewater in the last two years. The Corporation Commission says they have not tallied the amount of water injected through private wells.[2] Earthquakes Oklahoma has seen a sharp rise in the number of earthquakes in the last few years. In August 2011, the Oklahoma Geological Survey examined a cluster of earthquakes in Oklahoma and found “that shortly after hydraulic fracturing began small earthquakes started occurring, and more than 50 were identified, of which 43 were large enough to be located. Most of these earthquakes occurred within a 24 hour period after hydraulic fracturing operations had ceased.”[9] On April 18, 2012, University of Memphis scientist Stephen Horton released his findings that a 5.7 quake in November 2011 was “possibly triggered” by injection wells near the fault that ruptured. Horton found that 63 percent of earthquakes have occurred within 10 kilometers (about 6 miles) of a deep injection well, compared to a 31 percent chance of a random, natural earthquake happening within 10 kilometers of a deep injection well. He did note that the correlation between the location of the quake centers and the wells was complicated by the fact that some of the nearby injection wells had been in operation for 10 years, and the amount of fluid being injected has reportedly been on the decline for the last five years.[10] In July 2012, it was reported that Oklahoma officials ignored advice about injecting water into faults, to maintain production of oil and natural gas.[11] A 2013 study published in Geology linked Oklahoma’s 5.7 earthquake to underground injection of wastewater, saying a decades-long time lag between injection and tremors is possible. Geologists placed seismometers in the area after the initial quake and were able to track fault rupture areas, which showed close proximity to disposal wells. According to the researchers: “we interpret that a net fluid volume increase after 18 yrs. of injection lowered effective stress on reservoir-bounding faults. Significantly, this case indicates that decades-long lags between the commencement of fluid injection and the onset of induced earthquakes are possible.”[12] In October 2013, a drilling wastewater operator ceased injections at Oklahoma’s Love County Disposal Well after a series of earthquakes.

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Injection began September 3 and the earthquakes started September 17 in the area near the Texas border, about 100 miles north of Dallas. The strongest was magnitude 3.4.[13] Oklahoma had 580 earthquakes in 2014 that registered 3 or more on the Richter scale. This was a 500 percent increase in Oklahoma earthquakes over 2013.[14] In March 2015, it was reported that Oklahoma geologists were pressured by oil industry not to push on with their assessments of possible links between earthquakes in the state fracking.[15] In June 2015, the Oklahoma Supreme Court ruled that citizens had the right to sue the oil and gas companies responsible for the wells that caused earthquakes, which in turn caused personal injuries or property damage.[16] Inside Climate News reported that  hydraulic fracturing  induced earthquakes, as well as wastewater injection induced, have occurred not only in western Alberta and also British Columbia, but also Oklahoma, and Ohio. According to geophysicist Dr. Jeffrey Gu, from the University of Alberta,  hydraulic fracturing  earthquakes likely occur days to weeks after the frack job. Wastewater injection caused earthquakes can happen months to years after the injection.[17] In November 2015, a regulator with the Oklahoma Corporation Commission said Oklahoma has the most earthquakes of anywhere on earth.[18] In December 2015, state regulators shut down 7 waste disposal wells.[19] In January 2016, Oklahoma was hit with a dozen or so earthquakes in less than a week. As a result Oklahoma Corporation Commission ordered a number of injection well operators to limit their wastewater disposals.[20] Oklahoma experienced more than 800 earthquakes in 2015 that had a magnitude 3.0 or greater.[19] Water usage Oklahoma averages 4 million gallons per fracked well, or 2% of freshwater use in the state by sector. That amount is estimated to grow to 4.8 percent over the next fifty years.[21] From 2005 to 2012, it was estimated that Oklahoma used 10 billion gallons of freshwater in fracking operations in the state.[5] Spills and accidents here for an interactive map of spills, leaks, and other drilling incidents. A  2009  and  2010  report from the EPA Water Quality Protection Division lists concerns the agency has with the state›s injection well

Fracking in the USA 609 program, including inaccurately reported data and operators injecting for years without valid permits. Ultimately, the report recommends the Corporation Commission in Oklahoma take immediate actions to fix “critical problems.”[2]

Worker Deaths and Injuries Between October and June 2012, the U.S. Occupational Safety and Health Administration (OSHA) Oklahoma City reported nine work-related deaths in the oil/gas industries and three people who were injured in a drilling rig fire. In response, OSHA, the state Department of Labor, and the MidContinent Exploration & Safety Production Network asked Oklahoma’s oil and gas exploration and production companies to stand down and stop operations for a meeting on safety issues.[22] Legislative issues and regulations In July 2011, the Oklahoma Corporation Commission was established to regulate hydraulic fracturing of oil and gas wells as a well completion operation. The Commission’s environmental protection rules were set up to address various aspects of well completion, and compliance with the rules is assured through inspection, reporting, investigation, and enforcement mechanisms.[23] In May 2015, Oklahoma lawmakers followed Texas’s lead and voted to place a ban on local fracking bans. As of May 26, 2015, Oklahoma’s governor was deciding whether or not to sign the bill.[24]

Chemical Disclosure In May 2012, it was voted that Oklahoma oil and natural gas producers would be forced to disclose the chemicals used in their hydraulic fracturing operations under new rules set to go into effect July 1, 2012. Oklahoma Governor Mary Fallin signed off on the rules, which were approved by the Oklahoma Corporation Commission. Companies will report directly to the commission or use FracFocus.org.[25] As of January 2014, operators of all oil and gas wells in the state must report the chemicals used in hydraulic fracturing either directly to the website FracFocus.org or to the Oklahoma Corporation Commission, which will add the information to the FracFocus database.[26]

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Federal Lands In September 2013, it was reported that the Oklahoman government would join Alabama, Montana and Alaska in protesting Bureau of Land Management plans to regulate hydraulic fracturing on federal land.[27] Citizen activism Citizen groups Stop Fracking Oklahoma Reports

Diesel in Fracking From 2010 to July 2014, drillers in the state of Oklahoma reported using 1,465.68 gallons of diesel injected into 23 wells. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains  benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[28] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[29]

Fracking and Earthquakes A 2011 United States Geological Survey (USGS) report,  Examination of Possibly Induced Seismicity from Hydraulic Fracturing in the Eola Field, Garvin County, Oklahoma,” links a series of earthquakes in Oklahoma in January 2011 to a fracking operation underway there. The USGS found that, overall, some 50 small earthquakes had been registered in the region,

Fracking in the USA 611 ranging in magnitude from 1.0 to 2.8. The bulk occurred within 2.1 miles of Eola Field, a fracking operation in southern Garvin County. The USGS determined that “the character of the seismic recordings indicate that they are both shallow and unique.”

References 1. John Kemp, Oklahoma is next destination for shale revolution, Reuters, Oct 21, 2013. 2. 2.0 2.1 2.2 Jennifer Loren, Oklahoma Oil And Gas Injection Regulations Come Under Fire, Oklahoma Six, Feb. 21, 2012. 3. Katie M. Keranen, Heather M. Savage, Geoffrey A. Abers, and Elizabeth S. Cochran, Potentially induced earthquakes in Oklahoma, USA: Links between wastewater injection and the 2011 Mw 5.7 earthquake sequence,  Geology, Jan. 2013. 4. 4.0  4.1  4.2  John Kemp,  Oklahoma is next destination for shale revolution, Reuters, Oct 21, 2013. 5. 5.0 5.1 Fracking by the Numbers, Environment America, Oct. 2013. 6. Travis Vulgamore and others, Hydraulic fracturing diagnostics help optimize stimulations of Woodford Shale horizontals, American Oil and Gas Reporter, Mar. 2008, p.66-79. 7. David Brown, Big potential boosts Woodford,  AAPG Explorer, Jul. 2008, p.12-16. 8. Woodford Shale production, 2005-2011, The Oil Drum 9. Austin Holland,  Examination of Possibly Induced Seismicity from Hydraulic Fracturing in the Eola Field, Garvin County, Oklahoma, Oklahoma Geological Survey Open-File Report, 2011. 10. Mike Soraghan, EARTHQUAKES: Drilling waste disposal risks another damaging Okla. quake, scientist warns, E&E News, Apr. 19, 2012. 11. “Okla. officials ignore advice about injecting into faults,” E&E News, Jul. 25, 2012. 12. Katie M. Keranen, Heather M. Savage, Geoffrey A. Abers, and Elizabeth S. Cochran, Potentially induced earthquakes in Oklahoma, USA: Links between wastewater injection and the 2011 Mw 5.7 earthquake sequence, Geology, Jan. 2013. 13. Mike Soraghan,  Okla. disposal well shuts down after tremors,  E&E News, Oct. 2, 2013. 14. John Paul Brammer, “Earthquake in Oklahoma: Fracking and the Quake Epidemic (500% Increase),”  BNR, Dec. 29, 2015. 15. Oil & gas execs ‘pressured’ Oklahoma geologists not to reveal frackingquakes link, Russia Today, Mar. 5, 2015. 16. Anastasia Pantsios, “Citizens Can Sue Fracking Companies for Earthquake Damage, Says Oklahoma Supreme Court,” EcoWatch, Jul. 1, 2015.

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17. Zahra Hirja, “Alberta Earthquakes Tied to Fracking, Not Just Wastewater Injection,” Inside Climate News, Aug 6, 2015. 18. Eric Levitz, “Citizens Can Sue Fracking Companies for Earthquake Damage, Says Oklahoma Supreme Court,”  New York Magazine, Nov. 11, 2015. 19. 19.0  19.1  Samantha Page, “This One Suit Could Take Down Oklahoma’s Oil And Gas Industry,” Think Progress, Dec. 11, 2015. 20. Cole Mellino, “12 Earthquakes Hit Frack-Happy Oklahoma in Less Than a Week,” EcoWatch, Jan. 5, 2016. 21. Adam Wilmoth, “Oklahoma oil industry uses less than 2 percent of state’s water,” NewsOK, Mar. 30, 2014. 22. Safety groups ask for Okla. oil, gas stand downs,  Associated Press, Jun. 19, 2012. 23. Regulations, GroundWork, accessed Apr. 24, 2012. 24. Joe Wertz, “Oklahoma Lawmakers Pass Measure Preventing Local Fracking Bans,” NPR, May 26, 2015. 25. Jay F. Marks, “Oklahoma approves fracking disclosure rules,”  NewsOk, May 29, 2012. 26. Adam Wilmoth,  New disclosure rules target chemicals used in fracking, NewsOK, Jan. 1, 2014. 27. Montana joins 3 other states in protesting fracking rules,  Associated Press, Aug. 29, 2013. 28. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 29. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014.

Oregon Oregon currently has no active fracking wells. However, in the past natural gas extraction from the Coos Bay basin in Southern Oregon fracked nine wells in the basin.[1] It has been reported that the Coos Bay Basin still has potential for future gas production.[2] LNG Terminals

Oregon LNG Oregon LNG is a $6 billion liquefied natural gas development project in Warrenton, Oregon, at the mouth of the Columbia River. The project

Fracking in the USA 613 began in 2004 as an import facility, but owner Leucadia has applied for it to become an export facility with liquefaction capabilities. They plan for construction to begin in 2015 and for the project to be fully operational in early 2019.[3] In July 2014, the Department of Energy (DOE) gave conditional approval to the facility to export liquefied natural gas to countries that don’t have a Free Trade Agreement (FTA) with the U.S. It is authorized to export up to 1.25 billion standard cubic feet per day of natural gas for 20 years.[4]

Jordan Cove LNG In 2009, FERC approved the Jordan Cove LNG import terminal proposed near Coos Bay, Oregon. Environmental groups suggested import made little sense, given plans to build a natural gas pipeline delivering gas from Wyoming to Oregon. In September 2011, acknowledging little import market existed, the Jordan Cove project filed an application for an export license with the Department of Energy. Ohio Attorney General Kroger responded by asking FERC to set aside the license it gave Jordan Cove for an import facility and pipeline, saying an importexport project has the potential to harm Oregon’s environment and economy.[5] In December 2011, the Department of Energy granted the Jordan Cove and Pacific Connector Pipeline project a license to export liquefied natural gas, making Jordan Cove the first project in 40 years in which developers proposed a new pipeline and terminal primarily to export natural gas. A 230-mile pipeline would stretch from the Klamath Basin to Coos Bay, crossing hundreds of streams and rivers, protected federal forestland, and private property. Developer Jordan Cove filed a preliminary application with FERC in February 2012 seeking pre-filing status to explore the feasibility of a liquefaction export project that would be built and operated at the same site. FERC granted that status.[5] On April 16, 2012, FERC vacated authorization of the proposed Jordan Cove LNG terminal, as well as the certificate to construct the pipeline, concluding that an export facility serves a different purpose than an import facility, and requires its own full analysis of environmental and economic impacts. Those federal approvals are now void. Jordan Cove said they are working on getting their export application ready by 2013.[6] On March 23, 2014, the US Department of Energy conditionally approved the Jordan Cove LNG project, permitting it to export up to 0.8 billion standard cubic feet of natural gas per day for 20 years.[7]

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Geothermal A U.S. geothermal company is working on extracting  geothermal energy  from a dormant volcano in central Oregon through fracking. It has been reported that AltaRock Energy and Davenport Newberry, the companies behind the $43 million plan, have been granted a permit to hydrofrack the hot rocks flanking the Newberry volcano in Oregon, where Davenport Newberry has secured federal leases on 62 square miles of land. The plan is in the early stages of development.[8] The Newberry geothermal project will inject some chemicals into the ground along with pressurized water that will break open cracks in underground rock. There are two geothermal plants in operation in Oregon, a small one in Klamath Falls at the Oregon Institute of Technology. Geothermal energy provides heat for the city of Klamath Falls. A second larger geothermal plat is in Malheur County, which borders Idaho and Nevada.[9]

References 1. Natural Gas date: Technology and Regulatory Advances,  Citizens› Utility Board of Oregon, Dec. 2, 2011. 2. Oregon Gas Drilling: Different Challenges Between Sandstone and Coal Beds, OPB, Bonnie Stewart, Jul. 31, 2011. 3. Home, Oregon LNG website, accessed Jul. 2014. 4. DOE approves second gas export terminal in Oregon, The Hill, Jul. 31, 2014. 5. 5.0 5.1 Amelia Templeton, Department of Energy Gives Jordan Cove License to Export Natural Gas, OPB, Dec. 7, 2011. 6. Rob Manning,  Backers Of Proposed Natural Gas Terminal Undeterred By FERC Decision, NPR, Apr. 17, 2012. 7. David Unger,  US approves more LNG exports as Europe looks to curb Russian gas, CSM, Mar. 24, 2014. 8. Energy Company Plans to Frack a Volcano, Wired UK, Dec. 4, 2012. 9. NW Forestland Could Be Leased For Geothermal Development,  Jefferson Public Radio, APR 12, 2015.

Pennsylvania Pennsylvania’s shale gas resources are part of the Marcellus Shale, an extensive formation of shale (a type of sedimentary rock that is high in carbon) in New York, Pennsylvania, Ohio, West Virginia, and other states in the

Fracking in the USA 615 region.  [1] It underlies about 18,700 square miles in southern New York, including New York City›s entire 1,585-square-mile watershed west of the Hudson River.[2] This shale has received renewed attention both because of new estimates of the quantity of  methane gas  believed to be under these rocks[3] and because of the significant environmental concerns that have been raised about the method of extracting the gas from the shale, fracking.” Data released by DrillingInfo in late 2015 reported that permits issued for the Marcellus region was 68 in October, down from 76 in September 2015. Additionally, there were 160 permits issued in June 2015. At the same period in 2010, during the fracking boom in the region, 600 permits were issued a month. The steady decrease in global oil prices was said to be responsible for the decline in the number of fracking permits.[4] The Utica Shale lies beneath the Marcellus Shale, which has already been explored.[5] Between January 1, 2005 and March 2, 2012, the Pennsylvania Department of Environmental Protection issued 10,232 drilling permits, and denied only 36 requests. Tom Corbett’s first major political appointment after his election as Governor in November 2010 was to name C. Alan Walker, an energy company executive, to head the Department of Community and Economic Development. Corbett also repealed environmental assessments of gas wells in state parks. Within the budget bill, Corbett authorized Walker to “expedite any permit or action pending in any agency where the creation of jobs may be impacted.” Between 2007 and the end of 2010, the Pennsylvania Department of Environmental Protection (DEP) issued 1,435 violations to natural gas companies; 952 of those violations related to potential harm to the environment. In March 2011, Michael Krancer, the new DEP secretary and a political appointee of Corbett, took personal control over the department’s issuance of any violations. By Krancer’s decree, every inspector could no longer cite any well owner in the Marcellus Shale development without first getting the approval of Krancer and his executive deputy secretary.[6] On February 14, 2012, Pennsylvania Governor Tom Corbett signed into law Act 13, which revoked local zoning authority to discourage oil and gas development, allowing municipalities to adopt rules on drilling, but preventing them from banning it. The law also allows the state’s Public Utilities Commission to overturn local zoning and decide whether a community is eligible for a share in impact fee revenues, and enables the industry to seize private property for a drilling operation.[7]

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Despite the regulations to encourage shale gas development in the state, by 2013 fracking in the Marcellus Shale formation in Pennsylvania had dropped by more than 50 percent since its peak in 2010, attributed primarily to the low market price of gas. David Masur of PennEnvironment said gas companies that once touted the benefits of cheap natural gas for the Pennsylvania economy are looking instead toward facilities to ship liquid gas to markets overseas, where prices are higher.[8] Revenues In 2012, Pennsylvania was the only major gas-producing state that does not tax natural gas production.[9] In February 2012, the Pennsylvania House and Senate approved a compromise plan for a “local impact fee” on natural gas drillers, which Gov. Corbett is expected to sign. Corbett had refused to impose a “severance tax” on drillers, arguing that it would hinder the industry’s presence in the state, so instead the “impact fee” was created. The compromise calls for a fee that would fluctuate with the price of natural gas and, starting in 2013, the rate of inflation. In the first year alone, Republicans say, the levy would raise $180 million from 3,850 wells. The bill sends 60 percent of proceeds to localities directly affected by drilling, to cover such items as road repair and increased public-safety costs. The other 40 percent goes to statewide projects.[10] Many Democrats and environmental groups have criticized the bill, saying it was crafted behind closed doors by Republicans. The bill requires that all types of oil and gas operations (except for natural gas processing plants)—unlike any other commercial or industrial business—be allowed in all zoning districts, and mandates a state ordinance that supersedes municipal ordinances.[11]

Taxes Defeated in Part by Industry Study Pennsylvania remains the largest U.S. state without a tax on natural gas production, due in part to a 2009 Pennsylvania State University study predicting drillers would shun Pennsylvania if new taxes were imposed; lawmakers cited it the following year when they rejected a 5 percent tax proposed by then-Governor  Ed Rendell. The tax would have generated an estimated $100 million in its first year. It was later reported that the PSU study was sponsored by the industry-funded  Marcellus Shale Coalition, which provided a grant of about $100,000, and led by economist Dr. Tim Considine, the lead analyst for natural gas deregulation on the

Fracking in the USA 617 U.S. Congressional Budget Office, according to his University of Wyoming profile. Considine has also conducted contract research for industry groups such as the  American Petroleum Institute  and the  Wyoming Mining Association.[12] A 2010 expansion of the 2009 PSU study was funded by the American Petroleum Institute.[13] The impact fee will bring in about $85 million in 2012 compared to $200 million under a 5 percent tax, assuming a gas price of $2.50 per thousand cubic feet, according to the non-partisan Pennsylvania Budget and Policy Center. The fee will peak at about $200 million a year, while the tax could have reached $500 million in 2015 if gas prices rebound to $4.50.[14] Considine was also the lead author on a SUNY-Buffalo report in May 2012 that claimed state regulation had made fracking safe in Pennsylvania. Within days, a top Pennsylvania environmental official quoted the Buffalo study in testimony to Congress about the effectiveness of fracking regulations. However, both the official and the study itself declined to mention Considine’s close ties to the industry — and that his department had received nearly $6 million in donations from the oil and gas industry in 2011.[15] A separate PSU study on fracking also funded by the Marcellus Shale Coalition was cancelled in 2012 after some faculty members said the project was being slanted toward industry.[16]

Tax Loopholes According to the Pennsylvania Budget and Policy Center, more than 400 corporate subsidiaries linked to Marcellus Shale gas exploration have been registered in Delaware, most within the last four years; more than two-thirds of the companies in the Coalition are registered to a single address: 1209 North Orange Street. In 2004, the Center estimated that the Delaware loophole had cost the state $400 million annually in lost revenue.[17]  SEIU  of Pennsylvania has calculated $550 million/year in lost tax revenue in the state from the shale gas industry due to the loophole.[18] Lobbying and donations A 2012 press release by MarcellusMoney.org stated that the “natural gas industry and related trade groups have now given nearly $8 million to Pennsylvania state candidates and political committees since 2000.... Top recipients of industry money given between 2000 and April 2012 were Governor Tom Corbett (R) with $1,813,205.59, Senate President Joseph Scarnati (R-25) with $359,145.72, Rep. Dave Reed (R-62) with $137,532.33,

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House Majority Leader Rep. Mike Turzai (R-28) with $98,600, and Sen. Don White (R-41) with $94,150.”[19] The 2011 Common Cause report,  “Deep drilling, deep pockets, in Washington and Pennsylvania,” found that from 2001 through June 2011, the fracking industry gave $20.5 million to current members of Congress and spent $726 million on lobbying.” Two Pennsylvanians, Rep. Tim Murphy, and Sen. Pat Toomey, ranked among the leading recipients in Congress in gas industry donations (10th and 28th respectively). Murphy has received $275,499 and Toomey $160,750. Other PA recipients included Rep. Jason Altmire (D) with $65,365; Rep. Jim Gerlach (R) with $60,800; Rep. Bill Shuster (R) with $59,000; Rep. Charles Dent (R) with $56,500; and Rep. Glenn Thompson (R) with $52,000. The natural gas industry contributed about $1.6 million to Gov. Corbett’s political campaigns from 2001 to 2011, about $1.1 million of that for his campaign for governor.[20]

Revolving Door The 2013 Public Accountability Initiative report “Fracking and the Revolving Door in Pennsylvania” identified 45 current or former Pennsylvania state officials who have links to the energy industry and gas drilling and fracking regulation, including 28 who have left to take industry jobs. According to the report: Pennsylvania’s previous three governors have strong ties to the natural gas industry - Tom Ridge’s firms benefited from a $900,000 contract to lobby for the Marcellus Shale Coalition, Mark Schweiker joined a lobbying firm with a Marcellus Shale practice, and Ed Rendell is a partner in a private equity firm invested in fracking services companies and recently lobbied on behalf of driller Range Resources. Current governor Tom Corbett received more than $1 million in campaign contributions from the oil and gas industry. Every Secretary of Environmental Protection since the DEP was created has had business ties to the natural gas industry. Twenty Department of Environmental Protection employees have held jobs in the energy industry either before or after their agency jobs. Former high-level staffers include Terry Bossert, who has worked for three law firms that represent the energy industry before being hired as a vice

Fracking in the USA 619 president at Chief Oil & Gas; John Hines, a former Executive Deputy Secretary, who is now a government relations advisor to Shell; and Barbara Sexton, a former Executive Deputy Secretary who is now a government affairs director at Chesapeake Energy. Wells

Drilling Wells As of January 12, 2012, the Department of Environmental Protection has issued 5,751 permits in the Marcellus Shale region of the state, and 2,891 wells have been drilled.[21] In the Marcellus Shale region in Pennsylvania, drilling companies were issued approximately 3,300 gas-well permits in 2009, compared with 117 in 2007.[22] In 2014, 9,400 wells have been drilled.[23] In 2012, staffers at the Carnegie Museum of Natural History’s Powdermill Nature Reserve compiled what is believed to be the first comprehensive list of every Marcellus Shale well site in Pennsylvania; Powdermill believes that since 2000, the state has permitted 9,848 Marcellus Shale wells, of which 6,391 are either drilled and/or producing. There are 2,457 active permits that could eventually be drilled. Another 349 wells have either been abandoned, plugged, declared inactive, shut-in, or their status is unknown.[24]

Map courtesy of FracTracker

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Waste Injection Wells At the end of 2011, Pennsylvania had six active Class II wells. Of the almost 22 million gallons of wastewater that Pennsylvania’s  Marcellus Shale  operators sent to disposal wells in the first six months of 2011, nearly 99 percent went to Ohio, according to production reports from the Pennsylvania Environmental Protection Department. According to state regulators, Pennsylvania has only six active wells because the geological formations in Pennsylvania’s east are not permeable and because, until 2010, the state allowed companies to discharge brine into streams or take it to treatment plants. Fluid recycled or sent to outof-state disposal wells increased after the state started limiting wastewater sent to treatment plants.[25]

Abandoned Wells As of 2012 the state DEP knows the location of 8,257 abandoned/orphaned oil and gas wells -- an estimated 2 to 4 percent of the total abandoned wells in Pennsylvania, according to the DEP. As many as 300,000 wells have been drilled in Pennsylvania since the first oil well was drilled in 1859, with an unknown number of them left behind as abandoned wells. The number is unknown because most abandoned wells were drilled before Pennsylvania required permits, record-keeping, or any kind of regulation. The abandoned wells can serve as conduits for the surface migration of methane gas, particularly from newly drilled wells, sometimes leading to explosions.[26] Pipelines

Regulatory Issues In December 2011, Governor Corbett signed a law giving the Pennsylvania Public Utility Commission (PUC) authority to begin taking steps to do safety checks of some natural gas pipelines in the Marcellus Shale regions - hiring inspectors and drafting new rules that bring the state in line with federal rules. However, the new safety-inspection and construction regulations will not apply in the most rural areas with “gathering” pipelines, which typically link wells with interstate pipelines. Because the pipelines

Fracking in the USA 621 are in remote, rural areas, the federal safety rules - covering everything from steel quality to welding standards - do not apply.[27] After the law, the PUC began the job of enforcing federal safety rules for pipeline systems, but none of the rules applies when the pipes or compressors are in the most rural areas, known as Class 1. For decades, the gas industry has fought hard to protect that exemption, according to The Inquirer. An Inquirer series in 2011 found that such regulatory gaps, coupled with a slow response from Pennsylvania, meant that hundreds of miles of high-pressure pipelines had been built with no safety oversight, and up to 25,000 miles could be built, experts say.[28] On March 29, 2012, a natural gas explosion rattled a compressor station near Springville, part of Marcellus Shale drilling in northern Pennsylvania, shaking houses up to half a mile away. After the blast, a gas safety inspector from the state Public Utility Commission began an investigation into possible violations of gas safety rules, but the PUC shut down its examination a few weeks later, after determining the station was in a rural area - and thus outside its jurisdiction.[28]

MARC 1 In January 2012, Central New York Oil & Gas Co., LLC went to court to condemn nearly half the properties along its FERC approved 39-mile natural gas pipeline through northern Pennsylvania, despite the company›s assurance to federal regulators that it would minimize using eminent domain. Eminent domain would give the company the right to excavate and lay the 30-inch diameter pipeline on private property. Landowners would not lose their properties and would be compensated. Landowners say the company steamrolled them by refusing to negotiate in good faith on either monetary compensation or the pipeline›s route, which cuts through the state›s pristine Endless Mountains. The MARC 1 pipeline is seen as key infrastructure for tapping into the  Marcellus Shale, as the high-pressure steel pipeline will connect to major interstate pipelines and the company’s own natural gas storage facility in southern New York state. Central New York Oil & Gas hopes to start construction soon and finish by July 2012, but awaits permits from Pennsylvania environmental regulators and the U.S. Army Corps of Engineers. The EPA has expressed concern that the pipeline will cross dozens of pristine waterways.[29] Environmental and health effects

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Hospitalizations A study released in July 2015 in the journal PLOS ONE reported that that those living near fracking operations had a higher likelihood of going to the hospital than people who did not live in such areas. The study revealed that “hospitalizations for heart conditions, neurological illness, and other conditions were higher among people who live near unconventional gas and oil drilling.” The report was based on a study done by researchers at University of Pennsylvania and Columbia University.[30]

Low Birth Weight A 2015 study from the University of Pittsburgh, published in PLOS, reported an increase of underweight babies born to women living nearby fracking wells.  [31] The researchers studied birth weights of 15,400 babies born in southwestern Pennsylvania in Washington, Westmoreland and Butler Counties between 2007 and 2010. It reports that mothers living near fracking had a 34% chance of delivering smaller babies than mothers living farther away.

Water Use Approximately 4.3 million gallons of fluid are injected per fractured well in Pennsylvania, according to researchers from San Jose State University and the consulting firm Downstream Strategies. This comes out to 3.2 to 4.3 gallons of water per thousand cubic feet of gas - three times what previous research has calculated. On average, only 6% of injected fluid is recaptured. Pennsylvania operators reported an almost 70% increase in wastewater generated from 2010 to 2011—rising to a reported 613 million gallons of waste in 2011.[32] A 2015 Stanford study found that Arkansas, Louisiana, West Virginia and Pennsylvania had the highest average water use per each  hydraulic fracturing job.[33]

Fracking Wastewater: History Pennsylvania farmer speaks to anti-fracking rally Interactive Map  displaying where fracking waste from PA drilling was produced and disposed, across six states.

Fracking in the USA 623 On January 5, 2010, ProPublica reported that Pennsylvania was dumping hundreds of millions of gallons of the wastewater utilized in extracting natural gas in the Marcellus Shale into streams across the state. They reported that Pennsylvania was largely unprepared for the vast quantities of salty, chemically tainted wastewater produced by drilling operations... While the state Department of Environmental Protection called for the fluids to be sent through municipal treatment plants, those facilities are largely unable to remove the salts and minerals, also known as Total Dissolved Solids (TDS), from the waste...[R]esearchers still don›t know whether high TDS levels are harmful to humans or wildlife. But the analysis found that some public water utilities had exceeded the federal limit for levels of cancer-causing trihalomethanes, which can form when chlorine in drinking-water treatment systems combines with bromide, which can be present in drilling waste.[34] In February 2011, the New York Times reported that “In Pennsylvania, [water] treatment plants discharged [drilling] waste into some of the state’s major river basins. Greater amounts of the wastewater went to the Monongahela River, which provides drinking water to more than 800,000 people in the western part of the state, including Pittsburgh, and to the Susquehanna River, which feeds into Chesapeake Bay and provides drinking water to more than six million people, including some in Harrisburg and Baltimore. Lower amounts have been discharged into the Delaware River, which provides drinking water for more than 15 million people in Philadelphia and eastern Pennsylvania.”[35] The New York Times concluded that “More than 1.3 billion gallons of wastewater was produced by Pennsylvania wells [from 2008 to 2011], far more than has been previously disclosed. Most of this water — enough to cover Manhattan in three inches — was sent to treatment plants not equipped to remove many of the toxic materials in drilling waste.” Under federal law, testing for radioactivity in drinking water is required only at drinking-water plants, but federal and state regulators have given nearly all drinking-water intake facilities in Pennsylvania permission to test only once every six or nine years.[36]

Wastewater Disposal and Contamination During the first half of 2012, oil and gas companies reported a total of 12.1 million barrels of fracking wastewater (drilling fluid, frac fluid, and produced fluid) generated from unconventional wells in Pennsylvania, up from 9.6 million barrels in the same period 2011.[37] Some experts say the

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state›s 70,000 older oil and gas wells are also a concern: an AP analysis of state data found that in the second half of 2011, about 78 million gallons of drilling wastewater from conventional oil and gas wells were still being sent to treatment plants that discharge into rivers.[38] In a peer-reviewed study released in April 2013, it was reported that, “Wastewater produced by hydraulic fracturing (“fracking”) for natural gas in the Marcellus Shale is already overwhelming disposal options and will continue to do so as gas development increases, according to newly published research. The investigation did not evaluate environmental consequences of the wastewater.” However, it was also reported that, “Fracking wastewater could have a range of environmental and health impacts if not managed correctly.” The analysis was limited to Pennsylvania.”[39] A study released in January 2015 in Environmental Science & Technology, authored by Avner Vengosh and Gary Dwyer of Duke University, found that high levels of two potentially hazardous contaminants, ammonium and iodide, were being discharged or spilled into streams and rivers from oil and gas operations in Pennsylvania and West Virginia. The authors found that the levels of contamination were as high in fracking wastewater as those coming from conventional oil and gas wells. “Wastewater from both conventional and unconventional oil and gas operations is exempted from the Clean Water Act, which allows their disposal to the environment. This practice is clearly damaging the environment and increases the health risks of people living in these areas, and thus should be stopped,” Vengosh said.[40] From 2010-2014, Pennsylvania had a confirmed 106 water-well contaminations.[41]

Barium and Wastewater Hydraulic fracturing’s production of hazardous wastewater is assumed to be partly due to chemicals introduced into freshwater injected into a well when it mixes with salty brine naturally present in the shale rock. Dartmouth University researchers studied samples from three drill sites from the Marcellus Shale in Pennsylvania and New York to determine the possible reactions between the rock and water that release  barium, and other toxic metals, during fracking. Dartmouth College’s 2015 study, published in Applied Geochemistry, found  barium  in fracking wastewater finds chemically reacts between injected freshwater and the fractured shale. This could play a role in generating barium in hydraulic fracturing wastewater. Fracking

Fracking in the USA 625 takes place a mile below the surface. This is where chemical reactions occur  between water and fractured rock at high temperature and pressure. Dartmouth team found that a large amount of barium in the shale is tied to clay minerals. This barium is readily released into the injected water as the water becomes more saline over time.[42]

Radium A 2013  Environmental Science and Technology  study performed by scientists from Duke University, based on two years of water samples at a Pennsylvania plant that treats fracking wastewater, found high concentrations of the element radium, a highly radioactive substance. The concentrations were roughly 200 times higher than background levels. In addition, amounts of chloride and bromide in the water were two to ten times greater than normal. Scientists note that the plants are not designed to handle the radioactive elements present in the wastewater, and are not required to test their effluent for radioactive elements. The study suggests that the treated water released back into local streams retains significant levels of radioactivity. The researchers believe the findings would likely be similar for many of the other facilities in Pennsylvania – currently, 74 facilities treat wastewater from fracking and release it into streams. Elevated levels of chloride and bromide, combined with strontium, radium, oxygen, and hydrogen isotopic compositions, are present in the Marcellus shale wastewaters, the study found.[43] The study examined the water discharged from Josephine Brine Treatment Facility into the nearby Blacklick Creek, which feeds into a water source for western Pennsylvania cities, including Pittsburgh. Scientists conducting the study took samples stream and downstream from the treatment facility over a two-year period, with the last sample taken in June this year.[44] In 2015, a Greene County stream called 10 Mile Creek that flows into the Monongahela River tested positive for radium at 60 times the level of EPA drinking water standards.[45] It is suspected that this radiation comes from drilling waste. Pittsburgh Action News reported that water authorities cannot easily get rid of radium through the standard filtering process. The Izaak Walton League cancelled plans to stock 10 Mile Creek with trout this year after consulting with state officials. EPA regulates Radium 226 and Radium 228 radionuclides in drinking water.[46]

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Fracking wastewater may be more radioactive than assumed. A study published in April 2015 in Journal Environmental Health Perspectives shows that current assessments of the radioactivity wastes from hydraulic fracturing  focus on radium rather than a comprehensive analysis of multiple radioactive elements. The use of radium alone to predict radioactivity concentrations can greatly underestimate total levels.[47] Dr. Marvin Resnikoff in a report for Delaware River Keeper wrote that the state’s Department of Protection (DEP) failed to act on evidence of radium leaking from landfills where oil and gas waste is dumped.[48]

Radon In April 2015, Environmental Health Perspectives published a paper linking radon in homes to shale drilling. [49] The study analyzed more than 860,000 indoor radon measurements. It concluded that well water, geologic unit, community, weather and unconventional natural gas drilling were associated with indoor radon concentrations. The authors emphasize that radon is the second-leading cause of lung cancer.

Wastewater Dumping On March 17, 2011, Pennsylvania Greene County resident Robert Allan Shipman and his company, Allan’s Waste Water Service Inc., were charged with illegally dumping millions of gallons of natural gas drilling wastewater across six counties in Pennsylvania from 2003-2009. The investigation of Shipman began after a client grew suspicious of illegal dumping when an in-house audit “revealed a large discrepancy in the amount of sludge received by Allan’s Waste Water and the amount of sludge disposed” by the company at treatment facilities. A review of reports by the Department of Environmental Protection confirmed that over 170,000 gallons of sludge were unaccounted for from June 2006 to the summer of 2007.[50] In 2014, U.S. Ecology came under fire for its expansion plans and handling of  hydraulic fracturing  radioactive sludge from out of state at its Wayne Disposal, Inc. facility in Belleville, MI. Wayne Disposal is one of only 17 sites in the U.S. qualified to handle such wastes, also called technologically enhanced naturally occurring radioactive material (TENORM).

Fracking in the USA 627 U.S. Ecology agreed to halt a shipment of hydraulic fracturing waste from Pennsylvania until a panel appointed by Michigan Governor Rick Snyder had reviewed the waste transaction. After four months of review, the panel decided in February 2015 that U.S. Ecology could accept the shipment. In fall 2015, controversy ensued over the expansion of operations at a hazardous waste plant called U.S. Ecology in Detroit near Hamtramck, MI, which raised concerns among neighbors that Detroit is being used as a dumping ground for out of state hydraulic fracturing operations.[51]

Wastewater Pits As reported in The Columbus Dispatch, fracking wastewater impoundment lots as big as football fields already dot heavily fracked landscapes in Pennsylvania and West Virginia. The impoundments store millions of gallons of water with fracking chemicals, toxic metals, and radium that come up from shale wells. Companies clean the water of pollutants so it can be recycled to frack new wells.[52] According to the Department of Environmental Protection, there are 25 centralized impoundments in Pennsylvania.[53] In Pennsylvania, wastewater must be removed within nine months of competed drilling at a site, according to the DEP. The state has permits for 23 such lagoons.[52] A West Virginia University study of 15 waste and freshwater lagoons in that state found that eight were built to contain more water than permitted, or had structural problems that threatened leaks.[52] The state Department of Environmental Protection investigated two  Range Resources  gas fracking impoundment sites in Washington County at a Cecil Township and an Amwell Township site. Eleven thousand contaminated tons were removed at the Amwell site. [54] In August 2014, the State Department of Environmental Protection issued a violation to  Range Resources  because another gas fracking wastewater impoundment contaminated groundwater at a nearby river in Southwestern Pennsylvania in Washington County. The open pit leaked chloride and salt into groundwater.

Methane In 2009, there were 1.26 cases of methane gas migrating into groundwater for every 1,000 new Marcellus wells drilled, according to the Pennsylvania

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Department of Environmental Protection. In 2010, there were more than seven cases for every 1,000 new wells. The contamination is believed to be due to lack of historical drilling in the PA region, the large amount of methane generated deep underground, and leaks in cement and casings that allow gas and fluids encountered in rock formations to migrate up outside of the wellbore.[55] The State’s Department of Environmental Protection announced in July 2012 that it was going to monitor ground-level ozone, particulate matter, carbon monoxide, nitrogen oxides, hydrogen sulfide and methane at compressor stations and gas processing facilities in the state.[56]

Silica In July 2012, two federal agencies released research highlighting dangerous levels of exposure to silica sand at oil and gas well sites in five states: Colorado, Texas, North Dakota, Arkansas, and Pennsylvania. Silica is a key component used in fracking. High exposure to silica can lead to silicosis, a potentially fatal lung disease linked to cancer. Nearly 80 percent of all air samples taken by the National Institute of Occupational Safety and Health showed exposure rates above federal recommendations. Nearly a third of all samples surpassed the recommended limits by 10 times or more. The results triggered a worker safety hazard alert by the Occupational Safety and Health Administration.[57] The rise of hydraulic fracturing to enhance oil and natural gas production also boosted the demand for sand to prop open shale formations. The fall of oil prices in 2015 has prompted layoffs in several frac sand companies. Pennsylvania based Preferred Sands, which owns frac sand plants in Wisconsin and Nebraska did a number of lay-offs in fall of 2015.[58] Social effects

Jobs According to the Pennsylvania Department of Labor and Industry, shalegas development has created 245,000 direct and indirect jobs, amounting to 4 percent of total employment in a state with 5.7 million jobs. Mark Price, a labor economist with the Keystone Research Center, puts 20,000 direct jobs created from Marcellus Shale.[59]

Fracking in the USA 629 A 2013 report by the Multi-State Shale Research Collaborative concluded that the Department overstated the industry›s effect on employment by including ancillary jobs in its counts. By the collaborative›s count, the industry supported 29,856 jobs in the state in 2012. That same year, West Virginia’s energy industry supported 13,147 jobs, and Ohio’s shale business generated 8,972 positions, according to the study. Virginia, Maryland and New York -- the three remaining states in the analysis -- each had fewer than 5,000 shale industry jobs. Pennsylvania state officials fired back, saying that excluding those jobs minimizes the industry’s positive community impacts.[60]

Displacement In March 2012, Pennsylvania mobile park owner Richard A. “Skip” Leonard told residents he sold the 37-unit park to Aqua PVR LLC. The company, whose parent company is Bryn Mawr-based Aqua America, plans to eliminate the park and build a water withdrawal facility to be used by the natural gas industry. The Lycoming County Planning Commission approved the company’s land development plans for the pump station project in mid-February 2012. A news story about the commission’s action was the first residents said they knew of the plans. Later, a letter to residents stated the developer would provide residents with a $2,500 incentive payment if they moved by April 1, and a $1,500 payment if they moved by May 1.[61] When six of the households were unable to move because of the financial burden, members of The Occupy Movement and others stepped in to set up a resistance camp. The campaign lasted two weeks during which activists set up a functioning community. On June 12, 2012, residents received notice from Aqua America that excavation at the mobile home park would begin that day and that people would have to leave or risk arrest. Huffmaster Crisis Response, which activists were told was hired by Aqua America, was sent in to remove them.[62] Employment in the larger logging and mining industry that includes shale gas fell 7.7 percent from 2014 year ago to 35,000 in October 2015.[63] Spills and accidents From January 2011 to June 2012 Pennsylvania records show 134 oil, gas, or chemical spills in the state.[64] FrackAlert contains a map of accidents and spills in the region here.

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May 2009: Leak in Cross Creek Park A leaking waste water pipe from a Range Resources Marcellus shale gas well drilled in Washington County’s Cross Creek Park polluted an unnamed tributary of Cross Creek Lake, killing fish and sea life approximately threequarters of a mile of the stream. The state Department of Environmental Protection said Range Resources reported the May 26 wastewater discharge from a coling on a 6-inch pipe running from a recently drilled well to a wastewater impoundment.[65]

September 2009: Dimock Spill and Methane Leakage Explosive Gas Emissions from Dimock Water Well In September 2009, eight thousand gallons of drilling fluids were leaked near the town of Dimock, at a  hydraulic fracturing  site run by  Cabot Oil and Gas  and involving a compound (LGC-35 CBM) manufactured by Halliburton that is described as a potential carcinogen and is used in the drilling process. The contaminants seeped into a nearby creek, where a fish kill was reported by the state Department of Environmental Protection. The spill was blamed on “faulty pipe work” and resulted in a significant number of fish killed and other fish “swimming erratically,” according to Pennsylvania’s Department of Environmental Protection.[66]

November 2009: Atlas Energy Contamination in Southwest Pennsylvania On November 9, 2009, Reuters reported that the owner of 480 acres of land in southwest Pennsylvania claimed Atlas Energy Inc. ruined his land with toxic chemicals used in or released there by hydraulic fracturing and he also claimed to find seven potentially carcinogenic chemicals above permissible levels set by the U.S.  Environmental Protection Agency. He performed tests on his well water a year before drilling began and said the water conditions were “perfect.” After the drilling began, water tests found arsenic at 2,600 times acceptable levels, benzene at 44 times above limits and naphthalene five times the federal standard. He has decided to sue Atlas Energy Inc. for negligence and is seeking an injunction against further drilling, and unspecified financial damages. Jay Hammond, general

Fracking in the USA 631 counsel for Atlas, said Zimmermann’s claims are “completely erroneous” and said Atlas will “vigorously” defend itself in court and declined further comment.[67]

March 2010: Spill in Sproul State Forest An estimated 8,000 gallons to 12,000 gallons of mud used by Anadarko E&P Co. Inc. for drilling operations overflowed at its well site due to “human error,” spilling into Sproul state forestland that had been leased out by the state for drilling. It was part of 32,000 acres of state forestland leased to five firms interested in drilling the deep gas pockets of the Marcellus Shale formation.[68]

May 2010: Cattle Quarantined Over Fracking Fluid Twenty-eight cows were quarantined after having access to a leaking waste water holding pond on a farm in Tioga County (north-central Pennsylvania). Tracks were found around and in the pond with dead grass in a 30-foot by 40-foot area around it. Water quality tests established levels of chloride, magnesium, potassium, and strontium - a heavy metal and particularly toxic to children. This is the first time animals have been quarantined in response to natural gas drilling. “We took this precaution in order to protect the public from consuming any of this potentially contaminated product,” said Agriculture Secretary Russell Redding. Twenty adult cows will be quarantined for six months and eight calves will be quarantined for two years. The farm is located near an East Resources drilling site.[69]

June 2010: Somerset County Spill One of the largest single-incident fines in the  Marcellus Shale  stemmed from an incident that began on June 10, 2010, at a Marcellus well site on a dairy farm in Somerset County. The Pittsburgh Post-Gazette reported that state inspector, April Weiland, determined that it appeared that Chief Oil & Gas had “intentionally buried” the spill with soil and rock. Chief Oil & Gas denies hiding spill and the company was fined $180,000.[70]

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June 2010: EOG Resources Blow Out On June 4, 2010, a western Pennsylvania natural-gas well owned by  EOG Resources Inc. blew out, releasing over one million gallons of gas and drilling fluids before being contained about 16 hours later, as reported by The Wall Street Journal and WCAJTV in Pennsylvania.[71][72] Operators at this site were preparing to extract gas after through [hydrofracking]]. In a press release, the Pennsylvania Department of Environmental Protection stated that it would aggressively investigate the methane well blowout and that it would take the appropriate enforcement action.[73] As a result, the well released natural gas and flowback (fracturing) fluid onto the ground and 75 feet into the air, the Pennsylvania Department of Environmental Protection said in the press release. EOG Resources is the new namesake for the company formerly known as  Enron. Pennsylvania Governor  Ed Rendell  has stated that the incident should serve as an open for what could unfold in the future if proper regulation methods are not implemented with expedience.[74] More on this statement can be seen here: http://www.cnbc.com/id/15840232?play=1&video=1517214459

January 2011: Spill in Tioga County In January 2011, approximately 21,000 gallons of fracking wastewater was released from a Tioga County, Pennsylvania well when a valve was left open, releasing chloride, sodium, barium and strontium, as well as hydrochloric acid used in the fracking fluid.[75]

March 2011: Potter County Chesapeake Energy  paid $215,000 after multiple warnings from state inspectors about erosion problems at a well site in the Pine Creek watershed in Potter County in the northern Pennsylvania. The Pittsburgh Post-Gazette reported that during a March 2011 rain and snow melt created a muddy runoff from the well site. The borough of Galeton was forced to close one of its public water supplies for three months after the runoff clogged its filters.[76]

April 2011: Wastewater Spill in Towanda In April 2011, near Towanda, Pa., seven families were evacuated after about 10,000 gallons of wastewater contaminated an agricultural field and a

Fracking in the USA 633 stream of Towanda Creek that flows into the Susquehanna River, the result of an equipment failure, according to the Bradford County Emergency Management Agency.[77] Chesapeake Energy lost control of the well during a hydraulic fracturing.

January 2012: Wastewater Spill in Susquehanna County In January 2012, an equipment failure at a drill site in Susquehanna County led to a spill of several thousand gallons of fluid for almost a half-hour, causing “potential pollution,” according to the state DEP. In its citation to Carizzo Oil and Gas, the DEP “strongly” recommended that the company cease drilling at all 67 wells “until the cause of this problem and a solution are identified.”[78]

March 2012: Explosion On March 29, 2012, a natural gas explosion rattled a compressor station near Springville, part of Marcellus Shale drilling in northern Pennsylvania, shaking houses up to half a mile away. After the blast, a gas safety inspector from the state Public Utility Commission began an investigation into possible violations of gas safety rules. The PUC, however, shut down its examination a few weeks later, after determining the station was in a rural area - and thus outside its jurisdiction. The PUC began the job of enforcing federal safety rules for the pipeline systems being built to serve the thousands of new Marcellus wells, but none of the rules applies when the pipes or compressors are in the most rural areas, known as Class 1. For decades, the gas industry has fought hard to protect that exemption, according to The Inquirer. An Inquirer series in 2011 found that such regulatory gaps, coupled with a slow response from Pennsylvania, meant that hundreds of miles of high-pressure pipelines had been built with no safety oversight, and up to 25,000 miles could be built, experts say. The state Department of Environmental Protection, which issued an air-quality permit for the station, is conducting its own investigation into whether the owners, Williams Partners of Tulsa, Okla., committed any violations. But DEP typically enforces emissions standards for compressor stations, not gas safety regulations. The agency says it told Williams not to restart the compressor without its permission, but the company began running it anyway a day or two later.[79]

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March 2013: Range Resources Flowback Water Injures Worker A West Virginia truck driver, Russell Evans, was splashed with flowback water at a Buffalo Township, Pennsylvania Range Resources well site in May 2013. Evans claims that he was doused with water when he attempted to stop the leak, and was told by a Range Resources employee that the water was safe. He stayed in his wet clothes for four hours. Evans claims to have suffered from nausea, shortness of breath, indigestion, vertigo, headaches, skin discoloration, permanent sensitivity to sunlight, chemical burns, blisters, and rashes. In May 2015, he filed a suit against Range Resources. The complaint alleges Range Resources “kept the chemical make of the fracking fluid a secret.”[80]

March and April 2013: Carrizo Spills Carrizo Oil and Gas spilled in March and April 2013. In March, a drill malfunction caused a fracking fluid spill. At one point, the fluid spilled at 800 gallons a minute. [81] In April, Carizzo spilled 9,000 gallons of flow backwater. [82]

May 2013: Injuries at Gas Pipeline Facility In May 2013, a fire at a Branchburg natural gas pipeline compression station, Transco Pipeline, sent two workers to hospitals and caused minor injuries to 13 other workers. Three emergency fire crews were needed to extinguish the fire. [83]

September 2014: Gas Well Fire In September, Hillcorp Energy Company started a fire at their well site Shenango Township in Mercer County. In August, Hillcorp caused another explosion on their well pad in Jefferson Township. [84]

December 2014: Pipeline Fire in Washington County A Williams Energy Company caused a fire in Houston, PA. The pipeline transported ethane from Marshall County, West Virginia to Houston, in Washington County.[85] Federal Investigations

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Clean Water Act Violation, Youngstown In January 2013, U.S. Attorney Steven Dettelbach and Ohio Attorney General Mike DeWine announced criminal charges against, Ben Lo, the owner of Hardrock LLC was charged with violating the Clean Water Act. Le allegedly ordered his employees to dump more than 20,000 of hydraulic fracturing waste into sewers that empty into a Mahoning River tributary. In Aug. 2014, a federal judge sentenced Lo to 28 months in prison. [86]

DOE, Greene County In July 2013, the Department of Energy said the first year of its study suggested no evidence that chemicals from natural gas drilling moved up to contaminate drinking water aquifers at a site in Greene County, PA. Drilling fluids tagged with unique markers were injected more than 8,000 feet below the surface at the gas well bore, but were not detected in a monitoring zone at a depth of 5,000 feet. The researchers also tracked the maximum extent of the man-made fractures, and all were at least 6,000 feet below the surface.[87]

Dimock Water for Dimock In November 2009, fifteen families in Dimock filed a lawsuit against Cabot Oil and Gas, alleging the company allowed methane and metals to seep into drinking water wells, failed to hold terms of its contracts with landowners, and acted fraudulently when it said that the drilling process, including the chemicals used in the underground manipulation process called hydraulic fracturing, could not contaminate groundwater and posed no harm to the people who live there.[88] The complaint says residents have suffered neurological, gastrointestinal and dermatological symptoms from exposure to tainted water. They also say they have had blood test results consistent with exposure to heavy metals. The lawsuit accuses Cabot of negligence and says it has failed to restore residential water supplies disrupted by gas drilling.[89] PA Resident Lights Running Tap Water on Fire Previously, Dimock had experienced several contamination incidents. In winter 2008, drinking water in several area homes was found to contain heavy

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metals and methane gas that state officials determined leaked underground from Cabot wells. In spring 2008, Cabot was fined for several other spills, including an 800-gallon diesel spill from a truck that overturned.[90] Under Gov. Ed Rendell, the DEP found Cabot’s activities to be at fault for contamination and the DEP was going to force Cabot to pay for construction of a water pipeline to provide replacement water for eleven Dimock families. When Tom Corbett - who received more than $1 million from the gas industry during his campaign - took over as governor in 2011, the plans for the water pipeline were scrapped.[91]  Cabot had been trucking water to Dimock’s residents, but stopped in November 2011 when a judge declined to order the company to continue deliveries.[92] Under pressure, the Environmental Protection Agency started delivering water supplies in 2012, and organizations and nearby residents organized water caravans to deliver water to an additional seven families.[93] In 2011, the EPA began testing drinking water in 61 locations in Dimock, Pennsylvania, for possible fracking-related contamination in response to the 2009 reports of methane leakage into the water supply, including several incidents of drinking water wells exploding.[94]On March 15, 2012, EPA released a statement saying that results from the first 11 homes sampled “did not show levels of contamination that could present a health concern,” but that it will perform additional sampling at three homes currently receiving replacement water and two homes where arsenic was detected.[95] In response, Water Defense and Gasland director Josh Fox went to Dimock for the test summaries and had them looked at by experts. The outside analysis found high levels of methane or chemicals in the water of all the families, Water Defense said. The water of four of the six families had methane levels in excess of Pennsylvania’s threshold for mitigation efforts. One of the reports “showed methane levels seven times” the state limit and nearly twice “the EPA’s less stringent standard,” according to ProPublica. The tests also showed that the methane was accompanied by the gas ethane, which the experts said indicated that the methane may have come from a deep underground reservoir that was drilled and not from surface sources.[96] Among the other substances detected at low levels in Dimock’s water were a suite of chemicals known to come from some sort of hydrocarbon substance, such as diesel fuel or roofing tar. They include anthracene, fluoranthene, pyrene and benzo(a)pyrene – all substances described by a branch of the Centers for Disease Control and Prevention as cancer-causing even in very small amounts. Another host of chemicals detected by the water testing has not been evaluated by the federal government for the risks they might pose to human health.[96]

Fracking in the USA 637 On May 11, 2012, the EPA completed its testing of water at all 61 homes in Dimock, and said the drinking water is safe to consume. The EPA said it will re-sample four wells where previous Cabot and state data showed levels of contaminants. The EPA also said one of the 12 water wells was found to have an elevated level of methane.[97] In response, Water Defense distributed a statement from Ron Bishop, a chemist and drilling opponent at the State University of New York at Oneonta, who reviewed the EPA tests and said many of the wells are “significantly contaminated” with pollutants that threaten human health: “One-third of the wells (20/59) are contaminated with methane at levels of concern” and “arsenic (As) above the EPA´s cancer prevention limit were found in ten wells, barium (Ba) levels above the ATSDR´s comparison values were found in 3 wells, high lithium (Li) levels were found in 2 wells, and manganese (Mn) above the EPA’s MCL [Maximum Containment Limit] was found in one water well.” The Associated Press reported that “the Dimock plaintiffs, who sued Cabot in 2009, appear to have quietly entered into settlement talks with the company.”[98] Even though levels of manganese and lead exceeded the EPA’s federal MCL standards, the residents’ filtered tap water was tested and declared within the MCL limits. Bishop criticized the EPA for ignoring a November 2011 analysis of water testing data gathered from Dimock wells prepared for the agency by the US Agency for Toxic Substances and Disease Registry. The report raised concerns about the reliability of the water filters and methane removal systems used by residents in Dimock and concluded that there is could be a “possible chronic public health threat” based on prolonged use of water from some wells in Dimock if exposure was not reduced in the future.[99] In August 2012, the state Department of Environmental Protection granted Cabot Oil and Gas Corp. permission to resume hydraulic fracturing in an area of Dimock.[100] The Agency for Toxic Substances and Disease Registry (ATSDR) (a branch of the Centers for Disease Control) is following up on the EPA study. ATSDR’s study will account for risks of long-term exposures to the water through showering, drinking, bathing, and washing, as well as risks that might be compounded when people are exposed to multiple toxicants. There is no time frame for the completion of the report.[101] In July 2013, The Tribune/Los Angeles Times reported that as the federal EPA moved to close its Dimock investigation, the staff at the midAtlantic EPA office in Philadelphia, which had been sampling the Dimock water, argued for continuing the assessment. The newspapers pointed to an  internal EPA PowerPoint presentation  by Washington Bureau staff

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members warning their superiors that several wells had been contaminated with methane and substances such as manganese and arsenic, most likely because of local natural gas production. The presentation identified five wells contaminated with methane whose chemical fingerprint, or isotopic composition, was the same as methane from the Marcellus shale formation at the center of Pennsylvania’s natural gas boom.[102] The EPA also dropped its investigations into water contamination from shale gas drilling in Parker County, TX, and Pavillion, WY.[103]

Washington County In September 2011, the U.S. Environmental Protection Agency began investigating whether specific Marcellus Shale drilling and compressor station operations in Washington County have caused environmental damage that violates federal regulations. Washington County has more wells and compressor stations than any other county in the region, with 700 drilled Marcellus Shale gas wells, 278 of which are “producing.”[104] Regulations Between 2000 and 2010, the number of active wells in Pennsylvania almost doubled from 36,000 to 71,000. In response, the Pennsylvania Department of Environmental Protection increased the size of its enforcement staff to 130 employees, 65 of which are inspectors. In 2010, each Pennsylvania oil and gas inspector was responsible for, on average, 1,092 active wells. In 2011, the investigative group ProPublica looked at records for 48 wells and found most were inspected at least once during drilling, however none were inspected during fracking, and six had not been inspected at all.[105] The Press & Sun-Bulletin reported that the DEP had 100 inspectors responsible for overseeing 131,283 active oil and gas wells.[106]

Wastewater Treatment Plants In April 2011, Pennsylvania Department of Environmental Protection asked all Marcellus Shale fracking operations to cease sending their wastewater to wastewater treatment plants. This request was voluntary, but it motivated most drillers to directly reusing a most of their produced water or reusing it after treatment in waste treatment plants specially equipped to handle drilling waste.

Fracking in the USA 639 Before 2011, most produced water was sent to wastewater treatment plants, where it was treated then discharged into rivers and streams.[107]

Wastewater for Roadways Pennsylvania permits spreading brine from natural gas wells on roads for ice and dust control. The state’s Department of Environmental Protection (DEP) allows a “beneficial use” permit to legally enable spreading wastewater on roads. [108] A 2012 Natural Resources Defense Council (NRDC) report “In Fracking’s Wake: New Rules are Needed to Protect Our Health and Environment from Contaminated Wastewater,” finds that from  hydraulic fracturing  wastewater from flow back and brine contains pollutants and Naturally Occurring Radioactive Materials (NORM) can be toxic to humans and the environment. Spreading wastewater on roads can wash pollutants into watersheds or groundwater.[109] Regulatory violations

Water Contamination In 2014, the Pennsylvania Department of Environmental Protection determined that oil and gas operations had damaged Pennsylvania water supplies 209 times since the end of 2007.[110] According to a 2014, an Associated Press investigation, which reviewed state data on water contamination allegations related to fracking that it was able to obtain from state agencies, Pennsylvania had confirmed at least 106 water-well contamination cases since 2005, out of more than 5,000 new wells.[111] State environmental regulators determined that oil and gas development damaged the water supplies for at least 161 Pennsylvania homes, farms, churches and businesses between 2008 and the fall of 2012, according to a cache of nearly 1,000 letters and enforcement orders written by Department of Environmental Protection officials. One in six investigations - 17 percent of the records - found oil and gas activity disrupted water supplies either temporarily or seriously enough to require companies to replace the spoiled source. Impacts included “methane contamination, sediment, and frack water spills from the surface.” Methane migration was the leading cause of damage.[112]

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From January 2011 through October 2012, there were 166 complaints filed in Fayette, Greene, and Washington counties to the PA state Department of Environmental Protection by residents who believed their water was contaminated due to oil and gas activity. The DEP does not keep a record of how these complaints were resolved or if they were definitely related to oil and gas activity.[113]

ExxonMobil In September 2013, Pennsylvania’s Attorney General filed criminal charges against ExxonMobil for illegally dumping tens of thousands of gallons of hydraulic fracturing waste at a drilling site in 2010. The Exxon subsidiary, XTO Energy, had removed a plug from a wastewater tank, leading to 57,000 gallons of contaminated water spilling into the soil. XTO was charged with five counts of unlawful conduct under the Clean Streams Law and three counts of unlawful conduct under the Solid Waste Management Act.[114]

2012 spills In 2012, Pennsylvania state regulators levied fines in 13 percent of the cases where inspectors found gas spill violations.[115]

Ambiguity Over Violations According to CNN Money, fracking companies might be violating drilling rules but affected landowners may not know “because the state agency charged with regulating the wells — the Department of Environmental Protection (DEP) — does not have to notify landowners if a violation is discovered. Even if landowners inquire about safety violations, DEP records are often too technical for the average person and incomplete.” If landowners do want to find out about violations on their property, such as “subpar cementing” that can lead to flammable drinking water, they have to schedule a meeting with the DEP and request the violation records in person.[116]

Chesapeake Energy Weeks after a peer-reviewed Duke University study  “Methane contamination of drinking water accompanying gas-well drilling and hydraulic

Fracking in the USA 641 fracturing,”  found systematic evidence for methane contamination of drinking water associated with shale gas extraction at sixty sites in NY and Pennsylvania, the Pennsylvania Department of Environmental Protection fined Chesapeake Energy $1.1 million – the largest fine against an oil and gas operator in the agency›s history – for contaminating 17 shale gas drilling wells in Bradford County, including some that had been part of the Duke study.[117][118][119] In 2015, a Pennsylvania State University study published in the Proceedings of the National Academy of Sciences found that fracking had contaminated three drinking wells in Bradford with a chemical, 2-Butoxyethanol, found in drilling fluid commonly used for fracking Marcellus Shale. The authors of the study believe the drinking water contamination came from a 2009 leaking tank or poor well integrity. The research used well water gathered on behalf of three families, which sued Chesapeake Energy after the company drilled faulty wells near them in 2009.[120] In June 2012, Chesapeake Energy settled a lawsuit filed by three families in Bradford County over the water contamination, paying $1.6 million.[121] In 2011, Chesapeake Energy violated Pennsylvania’s erosion and sediment control requirement to prevent water pollution 35 times. This was more than any other company in the state. [122] A 2015 NDRC report claims Chesapeake Energy was the top fracking violator from 2008 to 2013 in Pennsylvania with 589 violations for 2,618 wells.[123]

State Finds Methane Migration In September 2009, the Pennsylvania DEP presented its compilation of known cases related to gas well leaks to the Pennsylvania state’s Oil and Gas Technical Advisory Board. According to the briefing, methane migration from gas drilling, had “caused or contributed to” at least six explosions that killed four people and injured three others over the course of the decade preceding full-scale Marcellus development. At least 60 water wells (including three municipal supplies) had been contaminated.[124] Moratorium In September 2013, Pennsylvania State Senator Jim Ferlo (D-Pittsburgh) announced the introduction of the Natural Gas Drilling Moratorium Act, Senate Bill 1100, that would place a moratorium on issuing new permits for fracking in Pennsylvania. EcoWatch reported that “SB 1100 would

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cease granting new permits for fracking while an appointed commission prepares a study analyzing the agricultural, environmental, economic and social impacts of drilling for natural gas, due in January 2017.”[125]

Water A large portion of the Marcellus Shale formation underlies the environmentally sensitive Chesapeake Bay Watershed as well as the Delaware River Basin. The Delaware River Basin Commission holds regulatory jurisdiction in the watershed that houses much of the Marcellus Shale formation of any operations that involve water usage, extraction, or potential contamination. They were set to vote in November 2011 on whether any hydro-fracking operation that is to take place within the boundaries of their Special Protection Waters would first have to be permitted by the DRBC, but later canceled the vote. Communities and drillers are waiting for a ruling.[126] The Susquehanna River Basin Commission oversees another portion of the watershed. SRBC and the Pennsylvania Department of Environmental Protection issued orders to suspend operations at several wells in May 2008 because surface water was being diverted by the drillers without the necessary permits, and precautions to protect streams from contaminated runoff were questioned.[127]

DEP Reports Omit Chemicals Found in Water Tests In November 2012, it was reported that the Pennsylvania Department of Environmental Protection had created incomplete lab reports and used them to dismiss complaints that Marcellus Shale gas development operations have contaminated residential water supplies and made people sick, according to court documents and other sources in a Washington County case of residents against  Range Resources. Two DEP employees said the department’s oil and gas division directed the lab to generate water test reports to homeowners that omitted the full findings for heavy metals, including lithium, cobalt, chromium, boron, and titanium, some of which are human carcinogens, as well as volatile organic compounds that are associated with hydraulic fracturing fluids. As a result, state Rep.  Jesse White (D-Cecil) called on state and federal law enforcement agencies to investigate the DEP for alleged misconduct and fraud described in the sworn depositions.[128]

Fracking in the USA 643 DEP spokesperson Kevin Sunday said oil and gas division officials wanted to see only the results they deemed relevant to determining whether drinking water was being contaminated by Marcellus Shale gas drilling and production, and the omitted chemicals were not. Yet the 2009 study, “Sampling and Analysis of Water Streams Associated with the Development of Marcellus Shale Gas,” linked the unreported metals and fracking. The study, prepared for the industry-funded  Marcellus Shale Coalition  by Thomas Hayes of the Gas Technology Institute with input by the state DEP, did a sampling of water at 19 locations, before and after fracking. The study found aluminum, boron, cadmium, chromium, copper, lead, lithium, molybdenum, nickel, tin, titanium, thallium, and zinc in the flowback water after fracking. Using a computer code called Suite Code 942, the DEP tested for 24 contaminants but listed only eight of the metals in the report given back to a resident who requested the analysis; zinc, nickel, cobalt, molybdenum, titanium, and boron were found but omitted, as was acetone, chloroform, and T-butyl alcohol, which were dismissed and omitted as a lab error.[129] Toxicology tests on seven plaintiffs who live within a mile of a Range Resources drill site and wastewater pond in Amwell Township have found the presence of toluene, benzene, and arsenic in their bodies.[130] A Washington County resident is suing the agency for failing to fully investigate the air and water contamination she says made her sick. In connection with the lawsuit, Democratic State Rep. Jesse White has demanded that state and federal agencies investigate the DEP for “alleged misconduct and fraud.”[131] Lawsuits

Non-Disclosure Agreements On May 27, 2010, Stephanie and Chris Hallowich initiated a water contamination case against  Range Resources, MarkWest Energy Partners, and Williams Gas/Laurel Mountain Midstream Partners. No official complaint was ever filed and the case was settled as a non-disclosure agreement in July 2011, a request by the defendant companies that former Washington County Common Pleas Judge Paul Pozonsky granted Aug. 23, 2011. The Pittsburgh Post-Gazette and The Washington Observer-Reporter challenged the decision, saying the organizations had the right to information about the case.

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On March 20, 2013, President Judge Debbie O’Dell-Seneca found that the presumption of openness in the court system must trump the interest of the companies to keep the records sealed, opening the door to challenging other closed door fracking settlements.[132]

Gag Order It was reported in early August 2013 that in 2011, two young children living in Pennsylvania were banned from “talking about fracking for the rest of their lives under a gag order imposed under a settlement reached by their parents with a leading oil and gas company.” The gag order was imposed under a $750,000 settlement between the Hallowich family and Range Resources Ltd. The settlement barred the Hallowichs’ son and daughter, who were then aged 10 and seven, from ever discussing fracking or the Marcellus Shale. While gag orders on adults is normal, such gag orders on children are uncommon.[133]

Contaminated Water Wells According to a motion filed in October 2015 in a Pennsylvania court by attorneys for Loren “Buzz” Kiskadden,  Range Resources  did not tell their neighbors in Amwell, Washington County they were dealing with contaminated water wells. A major issue of the complaint is Range Resources use of tracers. Tracers are chemical and low-level radio nuclei added to the  hydraulic fracturing  process to judge the success of the drilling project. Kiskadden’s lawyers are trying to get information from the tracers to prove that the contamination in their client’s water well is caused by a nearby 13.5 million gallon open wastewater pit.[134]

State sues Chesapeake Over Fracking Leases with Landowners In December 2015, Pennsylvania’s Attorney General filled a lawsuit against Chesapeake over fracking leases with landowners. The lawsuit claimed Chesapeake underpaid landowners who leased land for hydraulic fracturing.[135] Fracking studies

Fracking in the USA 645

Government Accountability Office Study In a Government Accountability Office report released in July 2014, the independent oversight agency reported the “EPA’s role in overseeing the nation’s 172,000 wells, which either dispose of oil and gas waste, use ‘enhanced’ oil and gas production techniques, store fossil fuels for later use, or use diesel fuel to frack for gas or oil. These wells are referred to as ‘class II’ underground injection wells and are regulated under the Safe Drinking Water Act. Oversight of these wells varies by state, with some coming under the regulatory authority of the EPA, including the 1,865 class II wells in Pennsylvania. The GAO faults the EPA for inconsistent on-site inspections and guidance that dates back to the 1980’s. Of the more than 1800 class II wells in Pennsylvania, the GAO reports only 33 percent were inspected in 2012. Some states, including California, Colorado and North Dakota, require monthly reporting on injection pressure, volume and content of the fluid. As more oil and gas wells across the country generate more waste, the GAO highlights three new risks associated with these wells — earthquakes, high pressure in formations that may have reached their disposal limit, and fracking with diesel.”[136]

EPA Radiation Reports The EPA report “Technologically Enhanced Naturally Occurring Radioactive Materials (TENORM)” looks at how naturally-occurring radioactive materials are produced when radionuclides deep in the earth are brought to the surface by oil and gas drilling. A radionuclide is an atom with excess nuclear energy making it unstable. To become more stable, the unstable nucleus emits energy in the form of rays or high-speed particles. This is called ionizing radiation because it can create “ions” by displacing electrons in the body e.g. in the DNA, disrupting its function. The three major types of ionizing radiation are: alpha particles, beta particles and gamma rays. The radioactive materials include uranium, thorium, potassium-40, and their decay products. These materials are known to dissolve in produced water, or brine, from the  hydraulic fracturing  can be found in drilling muds, and accumulate in drilling equipment. [137] The U.S. EPA regulates radionuclides in drinking water to protect public health. Radionuclides in drinking water may cause health problems. It covers this issue in the report, “Drinking Water Contaminants.”[138]

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According to the U.S. EPA, roughly 80% of human exposure to radioactivity is natural and another 20% is from man made sources, such as x-rays, CT scans. We are exposed to naturally occurring radiation for example from radon gas emanating from rocks and soil, and radiation from space. Humans carry small amounts of potassium-40 in their bodies from the foods containing potassium such as bananas. Depending on the type of rocks where people live, 55 to 70% of natural exposure comes from radon gas, while cosmic radiation (which is greater at higher altitude) represents about 11%, and potassium-40 about 5%. Radiation may exist in drinking water from nuclides dissolved in the water from natural sources in the earth that come to the surface with drilling. Potassium is a primordial nuclide, a nuclide found on the Earth that existed in its current form since before Earth was formed.

DEP Radiation Report The Department of Environmental Protection (DEP) January 2015 study found little cause for concern to public health about radioactive materials in waste from drilling operations. In December 2015, the Delaware Riverkeeper Network released a review on the DEP study of technologically enhanced, naturally occurring radioactive materials (TENORM) brought to the surface by shale gas drilling. It says the study used inaccurate radon measurements and sampling methods. Delaware Riverkeeper Network also accused the DEP of improperly tested stream water quality. Dr. Marvin Resnikoff authored the Delaware Riverkeeper Network report.[139]

Diesel in Fracking From 2010 to July 2014, drillers in the state of Pennsylvania reported using 751.92 gallons of diesel injected into 27 wells. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains  benzene, toluene, xylene, and other chemicals that have

Fracking in the USA 647 been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[140] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[141]

Civil Rights Ordinances Some towns and cities in Pennsylvania (such as Pittsburgh and nearby suburbs) have been adopting community civil rights ordinances to keep fracking out of their locales. These are not the same as zoning laws that have been recently preempted by the state’s Act 13 (2012). According to the Community Environmental Legal Defense Fund (CELDF), communities ground the civil rights ordinances in community rights to local self-government, the rights of natural communities and ecosystems, the right to water, and the rights of community members over corporations. Few corporations have challenged the ordinances because, according to CELDF: “What happens if a corporation were to sue a community that has adopted a rights-based ordinance? Rather than arguing over Municipal Planning Code law and the violation of a corporation’s rights, the battle would be over democratic local self-governance,” which corporations want to avoid.[142] Pittsburgh’s ordinance, like other Pennsylvania municipalities, also states that “natural gas extraction” companies “shall not have the rights of ‘persons’ afforded by the United States and Pennsylvania Constitutions, nor shall those corporations be afforded the protections of the commerce or contact clauses within the United States Constitution or corresponding sections of the Pennsylvania Constitution.”[143] Kids Speak on Fracking Supporters of the civil rights ordinance argue the state Constitution is on their side: in 1972, Section 27 was added to Article One of the Pennsylvania Constitution, and reads, “The people have a right to clean air, pure water, and to the preservation of the natural, scenic, historic and esthetic values of the environment. Pennsylvania’s public natural resources are the common property of all the people, including generations yet to come. As trustee of these resources, the Commonwealth shall conserve and maintain them for the benefit of all the people.”[144]

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Moratoriums Gasland director Josh Fox and an alliance of conservation groups called on the Delaware River Basin Commission to ban fracking in Wayne County, Pennsylvania, arguing that the drilling technology would pollute the river’s 14,000-square-mile basin, a source of drinking water for 15 million people. In May 2009, the Commission declared that gas companies wanting to drill in Wayne County would need a permit from the DRBC as well as from the state of Pennsylvania. A year later the commission announced that it would not issue permits and would study the impact of fracking.[145] In September 2015, actor Mark Ruffalo held a rally in Harrisburg, the state capital, urging the legislator to enact a  hydraulic fracturing moratorium. [146]

Water Rights On February 27, 2012, the citizen group Damascus Citizens for Sustainability (DCS) filed a Freedom of Information Act public records request to force the Susquehanna River Basin Commission (SRBC) -- which includes officials from Pennsylvania, New York State, Maryland and the federal government -- to show what it has been doing to protect regional waters and the general public from hydrofracking water demand and pollution.[147]

Association of Pennsylvania State College and University Faculty Anti-Extraction Resolution In September 2013, the Association of Pennsylvania State College and University Faculty—APSCUF—passed by a vote of 68-31 a position statement with response to the SB 367—the PA Frack U Bill—and more generally the state university union’s position with respect to hydraulic fracturing—fracking—on state university properties.[148]

Police Backlash In March 2015, NRP reported that some fracking opponents are feeling police pressure in Pennsylvania drilling hotspots. Activists claimed that local authorities are working to protect the oil and gas industry, and view

Fracking in the USA 649 their protests as potential threats to their activities. As such, activists allege their civil rights are being violated.[149]

Non-Violent Protests In December 2015, a group of activists made up of grandparents in rocking chairs attempted to block Rex Energy’s access to its drilling operation in Adams Township, PA. While protesters blocked the entrance to the site, no drilling operations were taking place during the time. The activists noted that they were concerned with the close proximity of the operations to schools in the area.[150] During the protest, the activists were harassed by a man who used racist slurs against them.[151] Companies active in the area: Atlas Energy Chesapeake Energy Cabot Oil and Gas EOG Resources Range Resources Southwestern Energy Williams Energy Legislative issues

SB 875 Incentivizing Coal Mine Water in Oil/Gas Wells In October 2015, a bill that would limit liabilities for drillers that use treated coalmine water to drill and stimulate its wells has passed both House and Senate. This plan to incentivize coalmine water in wells is designed to be a recycling strategy.[152]

Act 13 In early February 2012, the Pennsylvania House and Senate approved a plan (Act 13) for a “local impact fee” on natural gas drillers, which Gov. Corbett signed into law on February 14. Corbett had refused to impose a “severance tax” on drillers, arguing that it would hinder the industry’s presence in the state, so instead the “impact fee” was created. The compromise

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calls for a fee that would fluctuate with the price of natural gas and, starting in 2013, the rate of inflation.[153] Many Democrats and local communities have criticized the bill, saying it was crafted behind closed doors by Republicans with the gas industry. The bill requires that all types of oil and gas operations (except for natural gas processing plants)—unlike any other commercial or industrial business—be allowed in all zoning districts, even in residential neighborhoods, schools, and sensitive natural protection areas. The bill also mandates a state ordinance that supersedes all existing municipal ordinances and prevents municipalities from adopting any zoning provisions that are stricter than the mandated standards.[154]

Impact Fee Act 13 has an impact fee rather than taxes, due in part to a 2009 Pennsylvania State University study predicting drillers would shun Pennsylvania if new taxes were imposed; lawmakers cited it the following year when they rejected a 5 percent tax proposed by then-Governor  Ed Rendell. It was later reported that the PSU study was sponsored by the industry-funded  Marcellus Shale Coalition, which provided a grant of about $100,000. The impact fee will bring in about $85 million in 2012 compared to $200 million under a 5 percent tax, assuming a gas price of $2.50 per thousand cubic feet, according to the non-partisan Pennsylvania Budget and Policy Center. The fee will peak at about $200 million a year, while the tax could have reached $500 million in 2015 if gas prices rebound to $4.50.[155]

Banning Local Zoning Ordinances Act 13 essentially disregards a 2009 decision by the Pennsylvania Supreme Court holding municipal rights to write zoning laws that excluded oil and gas drilling if it did not fit the community’s “character” and “special nature.” Under the Act, municipalities can adopt some rules on how drilling is to be done, but they cannot say no to drilling. The law also tells municipalities that they must revise their local ordinances to allow drilling if they want to receive payment under the new per-well impact fee. The law also empowers the state’s Public Utilities Commission—a body of appointed officials—to overturn local zoning, and to determine if a community is eligible to share in impact fee revenues. If a gas company or any individual

Fracking in the USA 651 disagrees with a local law that affects drilling, the “aggrieved” party can go to the PUC and the board will be required to “determine whether [the local law] violates” the new state oil and gas law.[156] It was later reported that this section of the Act was likely modeled after an  ALEC  bill titled,  An Act Granting the Authority of Rural Counties to Transition to Decentralized Land Use Regulation,  passed by ALEC›s Energy, Environment, and Agriculture Task Force at its Annual Meeting in 2010.[157]

Chemical Disclosure and Medical Censorship The Act also requires that companies provide to a state-maintained registry the names of chemicals and gases used in fracking. Physicians and others who work with citizen health issues may request specific information, but the company does not have to provide that information if it claims it is a trade secret or proprietary information, nor does it have to reveal how the chemicals and gases used in fracking interact with natural compounds. If a company does release information about what is used, health care professionals are bound by a non-disclosure agreement that forbids them from warning the community of potential water and air pollution, but also forbids them from telling their own patients what the physician believes may have led to their health problems.[158] A strict interpretation of the law would also forbid general practitioners and family practice physicians who sign the non-disclosure agreement and learn the contents of the “trade secrets” from notifying a specialist about the chemicals or compounds, thus delaying medical treatment.[159] On April 11, 2012, it was reported that the Pennsylvania Department of Health refused to give the Associated Press copies of its responses to people who claimed that drilling had affected their health. The Associated Press also reported that Act 13 stripped $2 million annually from a statewide health registry that tracked respiratory problems, skin conditions, stomach ailments, and other illnesses potentially related to gas drilling.[160]

Legal Challenge The law was scheduled to take effect on April 14, 2012, but aggrieved municipalities said they will sue to challenge sections of the bill and try to keep it from taking effect.[161] Seven municipalities -- including the southwestern towns of Cecil, Peters, South Fayette, Mt. Pleasant and Robinson, plus two towns in

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Bucks County -- filed a lawsuit challenging the Act in March 2012, along with a Monroeville doctor and environmental activists from the Delaware Riverkeeper Network. A state appellate judge granted a 120-day injunction to prevent the zoning section of the law from going into effect in mid-April.[162] In support of the lawsuit, the Pennsylvania State Association of Township Supervisors, representing 1,455 townships, approved resolutions in May 2012 opposing any state legislation that would limit or remove local zoning and land use regulations.[163] The case against Act 13 was argued in Commonwealth Court in Harrisburg in June 2012. If Act 13 is held, municipalities must revise their Marcellus Shale-related ordinances to comply with state regulations. Plaintiffs say whichever party loses the court case is expected to appeal, so either way, it’s going to the Pennsylvania Supreme Court.[164] On July 27, 2012, a Commonwealth court panel ruled that the state cannot take away zoning control away from local municipalities. The majority opinion stated that requiring municipalities to change their zoning rules in a way that would conflict with their development plans “violates substantive due process because it does not protect the interests of neighboring property owners from harm, alters the character of neighborhoods and makes irrational classifications – irrational because it requires municipalities to allow all zones, drilling operations and impoundments, gas compressor stations, storage and use of explosives in all zoning districts, and applies industrial criteria to restrictions on height of structures, screening and fencing, lighting and noise.”[165] On December 19, 2013, the Pennsylvania Supreme Court ruled 4-2 that townships and other local governments in Pennsylvania can use their zoning codes to control gas drilling within their borders, and that parts of Act 13 infringed on the state constitution’s guarantee of clean air and pure water. All four majority justices ruled that Delaware Riverkeeper had standing to challenge Act 13, which could pave the way for other groups to bring environmental cases. The justices also said that Mehernosh Khan, a doctor, had standing to challenge Act 13’s “gag rule” that prevents physicians from obtaining and sharing information about chemicals used in drilling. The Supreme Court ordered a lower court to reconsider his challenge to the law.[166]

National Bills The Fracturing Responsibility and Awareness of Chemicals Act (H.R. 2766), (S. 1215)--was introduced to both houses of the United States

Fracking in the USA 653 Congress on June 9, 2009, and aims to repeal the exemption for hydraulic fracturing in the Safe Drinking Water Act.[167] Citizen groups Allegheny Defense Project Alliance for Aquatic Resource Monitoring (ALLARM), Dickinson College Berks Gas Truth Carbon County Groundwater Guardians Center for Coalfield Justice Center for Healthy Environments & Communities, Univ. of Pgh. Center for Natural Resources Development & Protection, Temple University Clean Water Action Damascus Citizens for Sustainability Delaware Riverkeeper Delaware River Basin Commission Environmental Law Clinic, Univ. of Pgh. Frack Alert: Northeast Pennsylvania Residents and Landowners Against Fracking Gas Drilling Awareness Association Group Against Smog and Pollution Kiski-Conemaugh Stream Team Lawrenceville Marcellus Action Group Marcellus Shale Protest Mountain Watershed Association NE PA Gas Action PennEnvironment Pennsylvania Environmental Council Penn Future Protecting Our Waters Sierra Club – Allegheny Group SkyTruth Spectra Energy Watch Three Rivers Waterkeeper Water Quest The Shale Justice Coalition Reports

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2015 Fracking May Lead Decline Visitation in Public Parks According to a study by researchers from the University of Florida, North Carolina State University, and Florida State University in August 2015,  hydraulic fracturing  in, or near public park lands could prompt tourists to stay away. The study of 225 park users in Pennsylvania, Ohio, West Virginia, Kentucky, and Tennessee found more than a third say they would be unwilling to participate in recreational activities near hydraulic fracturing. Fifty eight percent of the study’s participants claim they would support legislation prohibiting fracking near their favorite park.[168] The National Parks Conservation Association claims the Delaware Water Gap National Recreation Area stretching across Pennsylvania and New Jersey is affected by hydraulic fracturing. [169]

2014 Pittsburgh Post-Gazette Spill Investigation The investigation focused on DEP data. It looked at 425 incidents involving 48 companies. The incidents incurred nearly $4.4 million in fines. The gas companies did not spot half the spills at the well sites that resulted in fines. Of those 425 fine incidents, 137 were due to spills at, or near, the well pad. They investigation identified the top drillers with the most spills. They were:  Atlas Energy  with 15 spills, East Resources with 14 spills,  Range Resources  with 14 spills,  Chesapeake Energy  with 12 spills, Chief Oil & Gas with 10 spills, EOG Resources with 7 spills, Cabot with 7 spills, CNX with 6 spills, EQT with 6 spills, and Chevron with 5 spills. About one third of the spills that received a fine impacted a stream, pond or wetland. About 25% of them happened in a specialty or highquality watershed.[170]

2013 Social Costs of Fracking The Food & Water Watch report “The Social Costs of Fracking” (Sep 24, 2013) argues that fracking is associated with more heavy-truck crashes, social disorder arrests, and STIs.

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2013 Shale Gas Roundtable The 2013 report  Shale Gas Roundtable: Deliberations, Findings, and Recommendations  by the University of Pittsburgh offers recommendations on natural gas development in Southwestern Pennsylvania based on public deliberations with regional stakeholders. The report found scientific research on the impacts of shale development is scant, and where it exists, it lives under a suspicion based on who funded the work. The report therefore recommends a model of funding research similar to health studies on the auto industry by the Boston-based Health Effects Institute, whose research priorities are set and carried out by independent scientists, and funded by both industry and government.

2012 Earthworks Oil and Gas Accountability Report Earthworks Oil and Gas Accountability’s 2012 report, “Gas Patch Roulette: How Shale Gas Development Risks Public Health in Pennsylvania,” consists of community health surveys and air and water testing. Surveying 108 residents in 14 Pennsylvania counties, the report found that those living closer to gas facilities reported higher rates of symptoms of impaired health. The water and air tests conducted by Earthworks found that more than half of the water well samples had elevated levels of methane and some had iron, manganese, arsenic, and lead at levels higher than the Maximum Contaminant Levels (MCLs) set by the PA Department of Environmental Protection (DEP). All of the air samples were taken in rural and residential areas; in several, higher levels of the BTEX chemicals (benzene, toluene, ethylbenzene, and xylene, which are known carcinogens) were detected, as compared to samples taken by the DEP in 2010.”

2012 PennEnvironment on Hidden Costs The 2012 PennEnvironment Research & Policy Center report,  “In the Shadow of the Marcellus Boom,” identified more than a dozen categories of hidden,  external costs  linked to  Marcellus Shale  gas development in Pennsylvania. External costs included aquifer contamination, human health problems, and damage to roadways, home values, and natural resources including public forests. The report also found that bonding amounts required by the state will be inadequate to cover long-term future costs

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of plugging abandoned wells. Pennsylvania drillers paid $197.6 million in the first round of 2012 Marcellus Shale impact fees, exceeding legislative estimates, but the report said those fees fall far short of covering all costs.

Pennsylvania Land Trust Report According to a report from the Pennsylvania Land Trust, Marcellus Shale gas drillers in Pennsylvania commit an average of 1.5 regulatory violations per day from 2008 to 2010, based on Right To Know requests to the Department of Environmental Protection. From 2008 to 2010, drilling companies were cited for 1,435 violations -- 952 of which were considered most likely to harm the environment, according to the report. The industry average in Pennsylvania was a “serious environmental incident” in six out of eight wells. Nearly half of the violations were related to improper erosion and sedimentation plans and improper construction of wastewater impoundments that contain fracking water. These impoundments were improperly lined or not structurally sound. There were 155 citations for discharging industrial waste onto the ground or into commonwealth waters, and 100 violations of the state Clean Streams Law. East Resources Inc. of Warrendale had the highest number of violations with 138, followed by Chesapeake Appalachia LLC, a subsidiary of Oklahoma City-based Chesapeake Energy, with 118, and Chief Oil & Gas LLC of Dallas with 109. Houston-based Cabot Oil and Gas, the company responsible for contaminated drinking water wells in Dimock, was fourth with 94 violations.[171] For casing and cementing, there were 47 violations issued on 33 Marcellus wells in the first five months of 2011, according to DEP records. In 2010, there were 90 violations issued on 64 faulty wells. The faulty casings are believed to be linked to methane leakage into water supplies. In 2011, dated DEP regulations on casings and cementing took effect that require a third string of steel casing; cement with gas-blocking additives in areas with known shallow gas-bearing zones; and a longer period to let the cement harden.[172]

Clean Water Action Report According to the environmental group  Clean Water Action, there were 1,200 violations of environmental regulations in 2010 by gas drillers in

Fracking in the USA 657 the  Marcellus Shale, a quarter of them from leaks or poor construction of waste pits for fluids that flow back to the surface after fracking. Over 1 well in 6 had violations. Gas companies that are members of Gov. Corbett’s Marcellus Shale Advisory Commission were responsible for almost half of the violations.[173]

References 1. Catskill Mountainkeeper, Marcellus Shale: The Marcellus Shale – America›s next super giant, Catskill Mountainkeeper website, accessed Mar. 2009. 2. [1] Mary Esch, “NYC says Catskill gas drilling risks are too great,” Associated Press, Dec. 23, 2009 3. Mary Esch,  Estimated gas yield from Marcellus shale goes, International Business Times, Nov. 4, 2008. (This is an AP story). “Got gas, lots,” Pittsburgh Tribune-Review, Nov. 5, 2008. 4. Gas Slump Hits America›s Biggest Fracking Field, Reuters, Dec. 2, 2015. 5. Tom Wilber, “The Promise of Fracking,”  Press& Sun-Bulletin, Nov. 22, 2015. 6. Walter Brasch,  Fracking: Corruption a Part of Pennsylvania’s Heritage, Truthout, Mar. 23, 2012. 7. Steven Rosenfeld, Fracking Democracy: Why Pennsylvania›s Act 13 May Be the Nation›s Worst Corporate Giveaway, AlterNet, Feb. 14, 2012. 8. Will Bunch, Pa. fracking boom goes bust, Philly.com, Sept. 11, 2013. 9. Angela Couloumbis and Amy Worden, Pa. House approves fee on Marcellus Shale gas, The Philadelphia Inquirer - Harrisburg Bureau, Feb. 9, 2012. 10. Angela Couloumbis and Amy Worden, Pa. House approves fee on Marcellus Shale gas, The Philadelphia Inquirer - Harrisburg Bureau, Feb. 9, 2012. 11. PA Senate and House vote for preemption of municipal zoning, No Frack Ohio, Feb. 9, 2012. 12. Jim Efstathiou Jr.,  Frackers Fund University Research That Proves Their Case, Bloomberg, Jul. 22, 2012. 13. Tim McDonnell, “Smelling a leak: Is the natural gas industry buying academics?” Grist, Jul. 30, 2012. 14. Jim Efstathiou Jr.,  Frackers Fund University Research That Proves Their Case, Bloomberg, Jul. 22, 2012. 15. Tim McDonnell, “Smelling a leak: Is the natural gas industry buying academics?” Grist, Jul. 30, 2012. 16. Jim Efstathiou Jr.,  Penn State Faculty Snub of Fracking Study Ends Research, Bloomberg, Oct 3, 2012. 17. Leslie Wayne, How Delaware Thrives as a Corporate Tax Haven, New York Times, Jun. 30, 2012. 18. Steve Horn,  Delaware Tax Haven: The Other Shale Gas Industry Loophole, DeSmogBlog, Aug. 3, 2012.

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19. Gas Industry Spends $23 Million to Influence PA Officials, Conservation Voters of Pennsylvania, Jul. 12, 2012. 20. James Browning & Alex Kaplan, Deep drilling, deep pockets, in Washington and Pennsylvania, Common Cause, 2011. 21. Marcellus Shale, Pennsylvania DEP, accessed Mar. 2012. 22. Susquehanna named Most Endangered River in the Nation: Natural Gas Drilling Posing Unprecedented Threat,  PA Sierra Club Press Release, May 2011. 23. The Promise of Fracking, Tom Wilber, Press & Sun-Bulletin, Nov. 22, 2015. 24. Sean D. Hamill, Powdermill compiles list of Pa. shale wells, The Pittsburgh Post-Gazette, May 25, 2012. 25. Mark Niquette, Ohio Tries to Escape Fate as a Dumping Ground for Fracking Fluid, SFGATE, Feb. 2, 2012. 26. Scott Detrow,  Perilous Pathways: How Drilling Near An Abandoned Well Produced a Methane Geyser, StateImpact, Oct. 9, 2012. 27. Craig R. McCoy and Joseph Tanfani, Rural loophole curbing Pennsylvania pipeline inspections, The Philadelphia Inquirer, Feb. 12, 2012. 28. 28.0 28.1 Joseph Tanfani, Northern Pennsylvania gas explosion was out of regulatory reach, The Philadelphia Inquirer, Apr. 8, 2012. 29. Michael Rubinkam,  Landowners Fight Eminent Domain in Pa. Gas Field, ABC, Jan. 31, 2012. 30. Hydraulic fracturing linked to increases in hospitalization rates in the Marcellus Shale, Science Daily, Jul. 15, 2015. 31. Perinatal Outcomes and Unconventional Natural Gas Operations in Southwest Pennsylvania, Science Daily, Jun. 3, 2015. 32. Evan Hansen, Dustin Mulvaney, and Meghan Betcher,  Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania, Downstream Strategies and Earthworks, Oct 30, 2013. 33. Evan Hansen, Dustin Mulvaney, and Meghan Betcher,  The Depths of Hydraulic Fracturing and Accompanying Water Use Across the United States, Environmental Science & Technology, Jul. 2015. 34. [2], Kusnetz, Nicholas, “Pennsylvania’s Drilling Wastewater Released to Streams, Some Unaccounted For,” ProPublica. Jan. 5, 2010. 35. Ian Urbina,  Regulation Lax as Gas Wells’ Tainted Water Hits Rivers,  New York Times, Feb. 26, 2011. 36. Ian Urbina,  Regulation Lax as Gas Wells’ Tainted Water Hits Rivers,  New York Times, Feb. 26, 2011. 37. Ellen M. Gilmer, Wastewater disposal concerns persist despite rise in reuse, E&E News, Sept. 6, 2012. 38. Kevin Begos, Expert says all Pa. oil, gas waste needs treatment, Associated Press, Apr. 15, 2012. 39. Charles W. Schmidt, “Estimating Wastewater Impacts from Fracking,” Environmental Health Perspectives, Apr. 2013.

Fracking in the USA 659 40. New Contaminants Found In Oil And Gas Wastewater, Duke Environment, Jan. 14, 2015. 41. Water in at least three U.S. states is polluted from FRACKING as hundreds of complaints are reported across the country,Associated Press, Jan. 6, 2014. 42. Fracking plays active role in generating toxic metal wastewater, study finds, Science Daily, Dec. 15, 2015. 43. Joseph Stromberg,  Radioactive Wastewater From Fracking Is Found in a Pennsylvania Stream, Smithsonian Magazine, Oct 2, 2013. 44. Felicity Carus, “Dangerous levels of radioactivity found at fracking waste site in Pennsylvania,” The Guardian, Oct. 2, 2013. 45. Radiation found in Greene County stream near water supply: Biologist concerned about residents› health, WTAE Pittsburgh, Jul. 16, 2015. 46. [3] Basic Information about Radionuclides in Drinking Water, United States Environmental Protection Agency, Retrieved Oct. 8, 2015. 47. Understanding the Radioactive Ingrowth and Decay of Naturally Occurring Radioactive Materials in the Environment: An Analysis of Produced Fluids from the Marcellus Shale, Environmental Health Perspectives, Jul. 2015. 48. Jon Hurdle, “Report revives debate over risks of radiation from drilling waste,” State Impact, Dec. 28, 2015. 49. [4], Nicholas Kusentz, “Predictors of Indoor Radon Concentrations in Pennsylvania, 1989–2013.” Environmental Health Perspectives, Apr. 2015. 50. Aaron Skirboll, Toxic Wastewater Dumped in Streets and Rivers at Night: Gas Profiteers Getting Away With Shocking Environmental Crimes,  AlterNet, Aug. 15, 2012. 51. Jim Lynch, Hazardous waste facility’s expansion prompts worries, The Detroit News, Sept. 24, 2015. 52. 52.0  52.1  52.2  Spencer Hunt,  Big lagoons could hold Ohio fracking waste,  The Columbus Dispatch, Oct. 11, 2013. 53. Valerie J. Brown. “Radionuclides in Fracking Wastewater: Managing a Toxic Blend,” Environmental Health Perspectives, Feb. 2014. 54. DEP: 3 Range frackwater impoundments are leaking,  WTAE Pittsburgh, Aug. 6, 2014. 55. Laura Legere, Stray gas plagues NEPA Marcellus wells, The Times-Tribune, Jul. 10, 2011. 56. “NATURAL GAS: Pa. plans to keep close tabs on air in Marcellus,” E&E News, Jul. 25, 2012. 57. Adam Voge,  Fracking dust alert not shocking in Wyoming, Wyoming Star Tribune, Jul. 30, 2012. 58. Cole Epley, “Sand industry — including Nebraska plant — feels the pain as oil prices drop,” World-Herald, Oct. 23, 2015. 59. Andrew Maykuth, Debating economic impact of Marcellus Shale in Pa., The Inquirer, May 06, 2013. 60. Pamela King,  Industry supporters inflate shale jobs figures -- report,  E&E News, Nov. 25, 2013.

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61. David Thompson, 32-unit village no more, Williamsport Sun-Gazette, Mar. 18, 2012. 62. Sara Jerving,  Police Raid Anti-Fracking Encampment in Pennsylvania,  PR Watch, Jun. 15, 2012. 63. David Conti and Tory N. Parrish, Fracking decline slows business in shale towns, Pittsburgh Tribune-Review, Jun. 15, 2012. 64. Local officials say they aren’t told about spills, Associated Press, Jun. 16, 2012. 65. Waste from Marcellus shale drilling in Cross Creek Park kills fish, Pittsburgh Post-Gazette, Jun. 5, 2009. 66. David O. Williams,  “Fracking fluid kills fish in Pennsylvania stream, state environment officials say,” Colorado Independent. Sept. 22, 2009 67. [5] Jon Huddle, “Pennsylvania lawsuit says drilling polluted water,” Reuters, Nov. 9, 2009. 68. Robert Swift, Spill in state forest moves gas drilling moratorium debate, The Times-Tribune, Mar. 30, 2010. 69. Pennsylvania quarantine cattle over gas drilling fluid, Reuters, Jul. 1, 2010. 70. Sean D. Hamill, “Drillers did not report half of spills that led to fines,” UF News, Pittsburgh Post-Gazette, 2014. 71. [6], “Blowout Occurs at Pennsylvania Gas Well,” Wall Street Journal, Jun. 4, 2010. 72. [7], “Gas Well Blowout Under Control In Clearfield County.” Jun. 4, 2010. 73. [8], “DEP Plans Thorough Investigation in to Marcellus Shale Well Blowout in Clearfield County: EOG Resources Well Released Fracking Fluid, Natural Gas for 16 Hours,” Pennsylvania Department of Environmental Protection, Jun. 4, 2010. 74. [9], “Rendell: Marcellus Shale Incidents ‘A Warning,’” KDKA, Jun. 10, 2010. 75. Aaron, Jeffrey, “Anatomy of a well blowout,” Elmira (New York) Star-Gazette, Mar. 13, 2011. 76. Sean D. Hamill, “Drillers did not report half of spills that led to fines,” UF News, Pittsburgh Post-Gazette, 2014. 77. Laura Legere, After blowout, most evacuated families return to their homes in Bradford County, The Times-Tribune, Apr. 21, 2011. 78. Walter Brasch, Fracking›s Health and Environmental Impacts Greater Than Claimed, Truthout, Mar. 19, 2012. 79. Joseph Tanfani, Northern Pennsylvania gas explosion was out of regulatory reach, The Philadelphia Inquirer, Apr. 8, 2012. 80. Emily Petsko, Truck driver sues Range Resources over injury claims, ObserverReporter, May 8, 2015. 81. Sofia Ojeda,  DATE: Fracking Fluid Leak In Wyoming County,  16 WNEP, Mar. 15, 2013. 82. Amanda Kelley, Fracking Fluid Clean Continues, 16 WNEP, May 1, 2013. 83. Walter O›Brien, Multiple injuries reported at Branchburg gas pipeline facility flash fire, NJ.com, May 30, 2013. 84. Nadine Grimley Gas well fire sparks evacuation, WKBN.com, Sept. 6, 2014.

Fracking in the USA 661 85. Gas pipeline fire in Washington Co. prompts urgent evacuations,  WPXI. com, Dec. 25, 2014. 86. Jeff Levkulich, “Lupo sentenced in dumping case,” Observer-Reporter, Aug. 15, 2014. 87. Kevin Begos, DOE study: Fracking chemicals didn›t taint water, Associated Press, Jul. 22, 2013. 88. Abrahm Lustgarten, Pa. Residents Sue Gas Driller for Contamination, Health Concerns, ProPublica, Nov. 20, 2009. 89. [10] Jon Huddle, “Pennsylvania residents sue over gas drilling,” Reuters, Nov. 20, 2009. 90. Frack Fluid Spill in Dimock Contaminates Stream, Killing Fish, ProPublica, Sept. 21, 2009. 91. Christine Shearer,  About That Dimock Fracking Study: Result Summaries Show Methane and Hazardous Chemicals, Truthout, Mar. 21, 2012. 92. Ellen Cantarow,  Fracking Gets Its Own Occupy Movement, The Nation, Jan. 23, 2012. 93. Christine Shearer,  About That Dimock Fracking Study: Result Summaries Show Methane and Hazardous Chemicals, Truthout, Mar. 21, 2012. 94. Sharon Guyn, The Fracking Industry Buys Congress, ENS, Feb. 16, 2012. 95. Laura Legere,  EPA not yet ‹drawing conclusions› about full Dimock picture, The Times-Tribune, Mar. 17, 2012. 96. 96.0  96.1  Neela Banerjee,  Clouded readings of EPA study of Dimock water, featured in ‹Gasland,› Los Angeles Times, Mar. 21, 2012. 97. Timothy Gardner,  Dimock, PA Water Deemed Safe By EPA, Reuters, May 11, 2012. 98. Michael Rubinkam, “EPA: Well water in Pa. gas drilling town is safe, Associated Press, May 11, 2012. 99. Mike Ludwig,  When Polluted Water Is Safe to Drink: Inside the Dimock Fracking Fight, Truthout, May 16, 2012. 100. Laura Legere, “DEP lets Cabot resume Dimock fracking,” The Times-Tribune, Aug. 22, 2012. 101. Tom Wilber, Federal health officials to assess Dimock pollution risk: Probe follows positive tests by EPA for hazards in aquifer, Sept. 4, 2012. 102. Neela Banerjee,  Internal EPA report highlights disputes over fracking and well water, The Los Angeles Times, Jul. 27, 2013. 103. Kate Sinding, Why Would EPA Hide Info on Fracking & Water Contamination in Dimock? NRDC, Jul. 28, 2013. 104. Don Hopey,EPA probing Washington County shale operations,  Pittsburgh Post-Gazette, Feb. 13, 2012. 105. Kusnetz, N. “Many PA gas wells go unreported for months,” ProPublica, Feb. 3, 2011. 106. Tom Wilber, “The Promise of Fracking Lessons from Pennsylvania,”  Press Sun Bulletin, Nov. 23, 2015. 107. Valerie J. Brown, “Radionuclides in Fracking Wastewater: Managing a Toxic Blend,” Environmental Health Perspectives, Feb. 2014.

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108. Heather Poole, “STATE POLICIES ON USE OF HYDRAULIC FRACTURING WASTE AS A ROAD DEICER,” OLR Research Report, 2013. 109. Rebecca Hammer.  “In Fracking’s Wake: New Rules are Needed to Protect Our Health and Environment from Contaminated Wastewater,”  NDRC Document, May 2012. 110. Laura Legere, DEP: Oil and gas operations damaged water supplies 209 times since end of ’07, Pittsburgh Post-Gazette, Jul. 22, 2014. 111. Kevin Begos,  4 states confirm water pollution from fracking, Associated Press, Jan. 5, 2013. 112. Laura Legere,  Sunday Times review of DEP drilling records reveals water damage, murky testing methods, The Times-Tribune, May 19, 2013. 113. DEP says 166 water complaints filed in tri-county area, Herald-Standard, Nov. 15, 2012. 114. Rebecca Leber, Charged With Illegally Dumping Polluted Fracking Fluid, Exxon Claims ‘No Lasting Environmental Impact,’ Climate Progress, Sept. 11, 2013. 115. Mike Soraghan, Many mishaps among drillers, but few fines, E&E News, Jul. 15, 2013. 116. Erica Fink, Reporting of fracking and drilling violations weak, CNN Money, May 1, 2012. 117. Jeff Goodell,  The Big Fracking Bubble: The Scam Behind the Gas Boom, Rolling Stone, Mar. 2011. 118. Sabrina Shankman and Abrahm Lustgarten,  “How Big is the Gas Drilling Regulatory Staff in Your State?” ProPublica, accessed May 2012. 119. Abrahm Lustgarten, “State Oil and Gas Regulators Are Spread Too Thin to Do Their Jobs,” ProPublica, Dec. 30, 2009. 120. “Fracking Chemicals Detected in Pennsylvania Drinking Water,” New York Times, May 4, 2015. 121. Alex Cameron, Chesapeake Settles With Pennsylvania Landowners, Oklahoma Impact Team, Jun. 25, 2012. 122. “Pennsylvania Oil & Gas Enforcement – Violations,” Natural Gas Watch. NaturalGasWatch.org, Aug. 11, 2011, accessed Aug. 12, 2015. 123. Amy Mall, Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015. 124. Andrew Revkin,  More Views on the Gas Rush and Hydraulic Fracturing, New York Times, Jul. 2, 2012. 125. Pennsylvania State Senator Announces Fracking Moratorium Legislation Laura Beans, EcoWatch, Sept. 18, 2013. 126. DRBC date: When Will New Rules Come to a Vote? Marcellus Drilling News, Mar. 8, 2012. 127. Thompson, David (2008-05-31).  “Gas Drilling  : Companies told to stop operations,” Williamsport Sun Gazette. Retrieved on 2008-06-09. 128. Don Hopey,  State representative calls for probe of DEP water testing reports, Pittsburgh Post-Gazette, Nov. 1, 2012.

Fracking in the USA 663 129. Rachel Morgan,  Heavy metals: Study links water contamination to fracking, The Times Online, Nov. 3, 2012. 130. Jon Hurdle, Pennsylvania Report Left Out Data on Poisons in Water Near Gas Site, The Times Online, Nov. 2, 2012. 131. Ellen Cantarow, Fracking ourselves to death in Pennsylvania, Grist, May 4, 2013. 132. Paula Reed Ward, Washington County judge orders Marcellus Shale development settlement records unsealed,  Pittsburgh Post-Gazette, Mar. 20, 2013. 133. Suzanne Goldenberg, Children given lifelong ban on talking about fracking, The Guardian, Aug. 5, 2013. 134. Don Hopey, “New information surfaces in water well contamination complaint,” Pittsburgh Post-Gazette, Oct. 16, 2015. 135. Brett Carlsen, “Pennsylvania sues Chesapeake over fracking leases with landowners,” Reuters, Dec. 9, 2015. 136. Congressional Watch-Dog Warns Fracking Waste Could Threaten Drinking Water, StateImpact, Pennsylvania, Jul. 18, 2014. 137. [11]  Technologically Enhanced Naturally Occurring Radioactive Materials (TENORM), United States Environmental Protection Agency, 2015. 138. [12] Basic Information about Radionuclides in Drinking Water, United States Environmental Protection Agency, retrieved Oct. 8, 2015. 139. Jon Hurdle, “Report revives debate over risks of radiation from drilling waste,” State Impact, Dec. 28, 2015. 140. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 141. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014. 142. Non-Rights Based Fracking Ordinances, Community Environmental Legal Defense Fund, accessed Mar. 2012. 143. Steven Rosenfeld,  How an Anti-Democratic, Corporate-Friendly Pennsylvania Law Has Elevated the Battle Over Fracking to a Civil Rights Fight, AlterNet, Mar. 13, 2012. 144. Steven Rosenfeld,  How an Anti-Democratic, Corporate-Friendly Pennsylvania Law Has Elevated the Battle Over Fracking to a Civil Rights Fight, AlterNet, Mar. 13, 2012. 145. Roben Farzad, The Land That Fracking Forgot, Bloomberg, Jun. 07, 2012. 146. Roben Farzad,  Actor Mark Ruffalo joins anti-fracking rally at state Capitol, ABC27.COM, Oct. 7, 2015. 147. Citizen Group Takes Action to Force Interstate Body to Show It Is Protecting the Vital Water Resources of PA, NY State and MD from Fracking, Damascus Citizens for Sustainability website, Feb. 27, 2012.

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148. Wendy Lee, “Education Matters More Than Money: The Association of Pennsylvania State College and University Faculty Anti-Extraction Resolution,” No Fracking Way, Sept. 24, 2013. 149. Marie Cusick, “Fracking Opponents Feel Police Pressure In Some Drilling Hotspots,” NPR, Mar. 1, 2015. 150. David Kaplan, Grandparents take to rocking chairs to protest fracking near schools, WTAE, Dec. 21, 2015. 151. David Edwards, “Pennsylvania man goes on N-word tirade against antifracking activists — and quickly loses his job,” RawStory, Dec. 30, 2015. 152. Jamison Cocklin, Pennsylvania Bill Incentivizing Coal Mine Water in Oil/ Gas Wells Nears Law, Shale Daily, Oct. 1, 2015. 153. Angela Couloumbis and Amy Worden, Pa. House approves fee on Marcellus Shale gas, The Philadelphia Inquirer Harrisburg-Bureau, Feb. 9, 2012. 154. PA Senate and House vote for preemption of municipal zoning,  No Frack Ohio, Feb. 9, 2012. 155. Jim Efstathiou Jr.,  Frackers Fund University Research That Proves Their Case, Bloomberg, Jul. 22, 2012. 156. Steven Rosenfeld, Fracking Democracy: Why Pennsylvania›s Act 13 May Be the Nation›s Worst Corporate Giveaway, AlterNet, Mar. 7, 2012. 157. Steve Horn, Pennsylvania Act 13 Overturned by Supreme Court, Originally an ALEC Model Bill, DeSmogBlog, Jul. 27, 2012. 158. Walter Brasch, PhD,  FRACKING: Pennsylvania Gags Physicians,  The Moderate Voice, Mar. 18, 2012. 159. Walter Brasch, PhD,  FRACKING: Pennsylvania Gags Physicians,  The Moderate Voice, Mar. 18, 2012. 160. Doctors say drilling law hurts health, Associated Press, Apr. 11, 2012. 161. Steven Rosenfeld, Fracking Democracy: Why Pennsylvania›s Act 13 May Be the Nation›s Worst Corporate Giveaway, AlterNet, Mar. 7, 2012. 162. Laura Olson, State judges throw out Act 13 zoning provisions, Post-Gazette, Jul. 26, 2012. 163. Andrea Iglar, Communities see Marcellus law as striking at heart of autonomy, Post-Gazette, Jul. 26, 2012. 164. Andrea Iglar, Communities see Marcellus law as striking at heart of autonomy, Post-Gazette, Jul. 26, 2012. 165. Laura Olson, State judges throw out Act 13 zoning provisions, Post-Gazette, Jul. 26, 2012. 166. Mike Lee,  Pa. Supreme Court rules towns can control drilling with zoning, E&E News, Dec. 20, 2013. 167. The ‹Fracking› Of Ohio State Parks, Progress Ohio, Mar. 16, 2011. 168. Tim Kellison, “Fracking may lead to decline in visitation in public parks,” UF News, Aug. 27, 2015. 169. Tim Kellison, “Fracking may lead to decline in visitation in public parks,” UF News, Aug. 27, 2015.

Fracking in the USA 665 170. Sean D. Hamill, “Drillers did not report half of spills that led to fines,” UF News, Pittsburgh Post-Gazette, 2014. 171. Don Gililand, “Marcellus Shale gas drillers committed 1,435 violations in 2.5 years, report says,” PennLive, Aug. 2, 2010. 172. Laura Legere, Stray gas plagues NEPA Marcellus wells, The Times-Tribune, Jul. 10, 2011. 173. Over 1,200 Marcellus Shale gas well violations in 2010, Clean Water Action, accessed Mar. 2012.

Rhode Island Rhode Island does not have oil or gas reserves, according to the EIA’s 2013 state profile. A Chicago-based company, Spectra Energy, plans to build a natural gas facility in Burrillville, Rhode Island. Members of Fighting Against Natural Gas (FANG) and the Burrillville Against Spectra Expansion rallied against building this facility.[1] Citizen activism During 2015, protesters repeatedly demonstrated against pipeline expansions and compressor station grades the Burrillville facility as well as plans for a new natural gas-fired power plant.[2] Legislative issues and regulations Citizen groups FANG Fighting Against Natural Gas Burrillville Against Spectra Expansion

References 1. Chicago firm to build clean energy facility in Rhode Island, Associated Press, Aug. 4, 2015. 2. Ambar Espinoza, “Eight Activists Released After Their Arrests At A Burrillville Protest,” NPR, Dec. 6, 2015.

South Carolina South Carolina has no oil or gas reserves, according to the EIA’s 2013 state profile.

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Offshore South Carolina has methane hydrate reserves, also known as fire ice. The methane hydrate is not typical natural gas. [1]. According to the U.S. Department of Energy, methane hydrate chief constituent is natural gas. It is encased in ice. Cold and gravity create a high-pressure situation. When methane hydrate is warmed or depressurized, it will revert back to water and natural gas. [2] The process to extract the methane hydrate is different than hydraulic fracturing, but both processes inject fluid at high pressure. Offshore Drilling In January 2014, 300 residents of Kure Beach, North Carolina protested Mayor Dean Lambeth’s decision to sign a letter, written by America’s Energy Forum part of the American Petroleum Institute, supporting seismic testing for future offshore oil and gas drilling. The seismic testing is part of a plan to open an area 50 miles off the East Coast from Virginia to Georgia to oil and gas drilling by 2022. [3]

References 1. Bo Peterson, “Methane hydrate offshore is tempting, perilous natural gas,” The Post Courier, Jan. 5, 2014. 2. U.S. Department of Energy, “Methane Hydrate,” retrieved Sept. 18, 2015. 3. “NC town called ‘ground zero’ in offshore drilling fight shows political cost of backing Big Oil over local jobs,” Facing South, Jan. 2016.

South Dakota In 2014, South Dakota produced 179,800 barrels (7.5 million gallons) of crude oil. However, currently there are no fracking operations taking place in South Dakota.[1] Denver-based South Dakota Proppants (SDP) plans to develop a mine on federal lands in southwestern South Dakota. A mine could be twenty miles west of Hill City in the Black Hills region of South Dakota. It is slated to be used for sand for hydraulic fracturing oil/natural gas production in the Williston Basin in North Dakota and the Julesburg Basin in Colorado. Coveted is the sandstone formation with a thick silica. [2] In 2014, the South Dakota Department of Environment and Natural Resources published a study concluding that the state’s grains do not meet

Fracking in the USA 667 the standards of American Petroleum Institute (API) for proppant sand that could be used for hydraulic fracturing. The company states they will still pursue building the mine.[3] Fracsand South Dakota Proppants, LLC, a fracsand company based in South Dakota, is reported as building the state’s first silica mine under a sprawling 960acre site in the state’s largest forest, Black Hills.[4]

References 1. U.S. Energy Information Administration, Petroleum & Other Liquids, Eia. gov, Retrieved Oct. 31, 2015. 2. Kevin Woster,  Hill City Area Mine Tabbed for Fracking-Sand Production, KELOLAND TV, Oct. 21, 2014. 3. Richard Nemec, Richard Nemec, Jun. 6, 2014. 4. Zahra Hirji, “Frac Sand Boom: South Dakota Is Latest State to Try to Cash In,” InsideClimate News, Jun. 26, 2014.

Tennessee Tennessee sits above the Chattanooga Shale, which has been slated as a site for increased drilling and fracking. By 2013, six natural gas drilling companies had looked at mineral rights and property leases in the Chattanooga Shale play. As of February 2013, there are fracking wells in Anderson, Campbell, Fentress, Morgan, Overton, Pickett, Scott, and Union counties in Tennessee.  Atlas Energy  has bought up 105,000 acres in eastern Tennessee. The company believes that this property could contain up to 500 potential horizontal drilling locations.[1] Environmental groups speculate that a drilling lease already has also been made in eastern or northern Hamilton County, TN, based on industry blogs.[2] According to the Tennessee Clean Water Network, a process called nitrogen fracking is occurring in Tennessee, which involves the injecting of nitrogen and 2-4 tankers of water into a gas well in karst geology.[3] A representative from Atlas Energy stated that the Chattanooga Shale is too fragile for high-pressure water fracking treatment, so nitrogen gas will replace some of the water.[1]

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Fracking futures in the Southeast (Illustration by Laura McNutt, Times Free Press.) On September 28, 2012, the Tennessee Department of Environment and Conservation (TDEC) and the Tennessee Oil and Gas Board (TOGA) passed regulations to govern the oil and gas industries. For more than a year prior to the passage, environmental groups met with the TDEC and recommended: Establishing a baseline system for monitoring water quality before and after drilling Notifying the public before any wells are hydro-fracked

Fracking in the USA 669 Matching state standards with the industry standards formulated by the American Petroleum Institute According to critics, the rules passed ignored the recommendations. Most notably, the rules contain a 200,000-gallon threshold: if fewer than 200,000 gallons of water are used to frack a well, the industry is not required to monitor groundwater or notify the public. Yet it is estimated that most fracking jobs in Tennessee would require less water.[4] Controversies

University Proposes Fracking In March 2013, the University of Tennessee proposed allowing an outside company to drill on about 8,000 acres of mature woodlands it maintains as an outdoor laboratory in the Cumberland Plateau — all while performing research on the effects of the process on water quality, air quality, and ground impacts. Gov. Bill Haslam is supportive of the university’s proposal. Gas driller Consol Energy hired Bryan Kaegi, a fundraiser for Tennessee Republicans, to help shepherd the proposal through the approval process.[5]

Governor’s Oil and Gas Ties The Governor of Tennessee, Bill Haslam, is an oilman and stands to profit from petroleum and gas. The Haslam family of Knoxville, Tennessee founded Pilot Travel Centers in 1958, which merged with Flying J in 2001. In 2012, the Haslam family purchased Western Petroleum and Maxum Petroleum, which are both major suppliers of fuel to the gas drilling and fracking operations in the U.S. The Haslam family will also start installing natural gas fueling pump stations, and plan to have 100 truck stops capable of fueling 18-wheelers with liquefied natural gas.[1] Citizen groups Frack-Free Tennessee Stop Fracking Around Chattanooga (Facebook) Tennessee Clean Water Network Tennessee Riverkeeper Reports

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2015 Fracking May Lead Decline Visitation in Public Parks According to a study by researchers from the University of Florida, North Carolina State University, and Florida State University in August 2015, hydraulic fracturing in, or near public park lands could prompt tourists to stay away. The study of 225 park users in  Pennsylvania,  Ohio,  West Virginia, Kentucky, and Tennessee found more than a third say they would be unwilling to participate in recreational activities near hydraulic fracturing. Fifty eight percent of the study’s participants claim they would support legislation prohibiting fracking near their favorite park.[6]

References 1. 2. 3. 4. 5. 6.

1.0 1.1 1.2

     David Whiteside, Fracking goes south, Tennessee Riverkeeper, Feb 20, 2013. Pan Sohn,  Stage is set for fracking in Tennessee,  Times Free Press, Jan 28, 2013. What is fracking? Tennessee Clean Water Network, accessed Apr 2013. David Cook, David Cook: Fracking comes to Tennessee, Times Free Press, Sep. 28, 2012. Kristin Hall, University Of Tennessee Fracking Proposal Allows Drilling On Their Land, Associated Press, Mar 15, 2013. Tim Kellison, “Fracking may lead to decline in visitation in public parks,” UF News, Aug. 27, 2015.

Texas If Texas were a country, it would be the third largest producer of natural gas in the world, behind Russia and the rest of the U.S. Despite the increase in fracking, the state has never matched its peak gas production level of 26.3 BCF/day in 1972.[1] As of March 2012, Texas had listed nearly 6,000 oil and gas fracking wells on FracFocus, an industry fracking disclosure site. The Texas list was by far the most of any state in the country.[2]In 2011, Texas had about 93,000 natural-gas wells, up from around 58,000 in 2000.[3] According to the Texas Railroad Commission, more than 15,300 wells have been drilled in the Barnett Shale underlying Texas.[4] Between 2009 and 2014, shale gas production more than doubled.[5]

Fracking in the USA 671 Barnett Shale: Some have suggested the Barnett Shale underlying Texas may contain the largest producible reserves of any onshore natural gas field in the United States. Industry analysts say the field is proven to have 2.5×1012 cu ft. (71 km3) of natural gas, and has been estimated to contain as much as 30×1012 cu ft. (850 km3) of natural gas resources. Oil also has been found in lesser quantities. The Barnett Shale is known as a “tight” gas reservoir, indicating that the gas is not easily extracted without hydraulic fracturing.[6] Major portions of the field are in urban areas, including the rapidly growing Dallas-Fort Worth Metroplex, creating controversy within different communities over whether and how fracking of the Barnett Shale should be allowed.[7] In July 2010,  ExxonMobil  subsidiary  XTO Energy  finalized a merger agreement with Ellora Energy, adding 46,000 acres to XTO›s reserves in the Haynesville and Bossier plays of east Texas.[8] History

Photo courtesy of geology.com

It has been argued that the first “frac job” - creating fractures from a wellbore drilled into reservoir rock formations - was performed in 1947,[9] but that the current fracking technique was not used on a commercial scale

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until the 1990s, in the  Barnett Shale  in Texas.[10]  The first Barnett Shale well was completed in 1981 in Wise County, Texas.[11] Drilling expanded greatly in the early 2000s due to higher natural gas prices and use of horizontal wells to increase production. Texas Shale Forum Shale plays

Barnett Shale The Barnett Shale is a geological formation of sedimentary rocks with oil and gas resources. The productive part of the formation is estimated to stretch from the city of Dallas west and south, covering 5,000 square miles (13,000 km2) and 18 counties.[12] In contrast to older shale gas plays, such as the Antrim Shale, the New Albany Shale, and the Ohio Shale, the Barnett Shale completions are much deeper (up to 8,000 feet). The thickness of the Barnett varies from 100 to 1000 feet, but most economic wells are located where the shale is between 300 and 600 feet thick. The success of the Barnett has spurred exploration of other deep shales for more deposits. In 2007, the Barnett shale (Newark East) gas field produced 1.11 cubic feet of gas, making it the second-largest source of natural gas in the United States.[13] By mid-2012 the Barnett had produced 10 TCF of gas, accounting for approximately 50% of all modern shale gas production.[14] The U.S. Geological Survey estimated in 2015 that the Barnett Shale contains recoverable mean volumes of 53 trillion cubic feet of shale natural gas, 172 million barrels of shale oil and 176 million barrels of natural gas liquids. This estimate is double the 2003 USGS assessment. The 2003 estimate relied took in account only vertical drilling, and did not account for horizontal.[15]

Pearsall Shale, Texas Operators have completed approximately 50 wells in the Pearsall Shale in the Maverick Basin of south Texas. The most active company in the play has been the former  TXCO Resources, although  Encana  and  Anadarko Petroleum have also acquired large land positions in the basin.[citation needed]

Eagle Ford Shale The  Eagle Ford Shale  is a sedimentary rock formation from the Late Cretaceous age underlying much of South and East Texas in United States,

Fracking in the USA 673 consisting of organic matter-rich fossiliferous marine shale. It derives its name from the old community of Eagle Ford, now a neighborhood in West Dallas, where outcrops of the Eagle Ford Shale were first observed. Such outcrops can be seen in the geology of the Dallas–Fort Worth Metroplex, and are labeled on images with the label Kef.” The Eagle Ford Shale is one of the most actively drilled targets for oil and gas in the United States in 2010.[16] According to researchers at Earthworks, locals near the Eagle Ford Shale are exposed to benzene and other chemicals that leak from pipelines, wells, and compressor station facilities that transport gas and oil.[17] Economic impacts Permit growth Drilling permits issued for the texas eagle ford shale area 3,000

2,826

2,500 2,000 1,500 1,010

1,000 500 0

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A Fort Worth Star-Telegram article reported over 100,000 new leases were recorded in Tarrant County in 2007. Terms of leases have included $15,000 per acre ($37,000/ha) and a 25% royalty for homeowners in Ryan Place, Mistletoe Heights, and Berkley on Fort Worth’s south side, and $22,500 per acre and a 25% royalty for a group of homeowners in south Arlington. Later articles in the Fort Worth Weekly report that many signed lease agreements have not been honored, with lessors alleging that they were paid significantly less than promised or were not paid at all.[18][19] Drilling industry advocacy groups claim that by 2015 the Barnett Shale may be responsible for more than 108,000 jobs.[20] Offsets to tax revenues may include clean costs for toxic byproducts of gas drilling, such as benzene and naturally occurring radioactive material (NORM).[21] Environmental groups and state regulators have come under increasing pressure to begin forcing cleans, and one group, the San Juan Citizens Alliance, has sued to force the EPA to tighten regulations.[22] In 2015, the greater Houston area lost 40,000 oil related jobs.[23]

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The Wall Street Journal reported in September 2015 that a number of fracking investment groups operating in Texas are financially suffering. Small well service companies like Pro-Stim Services, who competed with other hydraulic fracturing providers like Halliburton and Schlumberger f iled for bankruptcy when the price crude dropped between Summer 2014 and early 2015.[24] Fort Worth-based Compass Well Services was formed in 2010 to frack wells. The Wall Street Journal reported that by September 2015, Compass continued doing other oil field work, and its fracking operation was idled.[25]. September 2015 also brought a 75% decrease in shares for publicly traded and Houston based, Key Energy Services Inc. and Basic Energy Services.[26]

Proximity to Schools In 2012, a spatial database being built and used by the Department of Geography at the University of North Texas found a disparity in the proximity of gas wells to elementary schools in certain Barnett Shale neighborhoods: somewhat surprisingly, researchers found that the middle-class neighborhoods in Denton and Tarrant County - not poor neighborhoods - were more likely to have gas wells near their elementary schools. Generally, the researchers found inner-city neighborhoods and their  elementary schools to be the most “socially vulnerable” to drilling  (considering measures such as income and language). However, they also found those neighborhoods were no more likely to have gas wells near their elementary schools than schools in middle-class neighborhoods, such as the outermost areas of Denton and Tarrant County cities. One possible explanation is that inner-city neighborhoods are already densely developed, leaving little room for new gas wells and pipelines. Locally, school districts in Aubrey, Lake Dallas, Pilot Point, and Sanger have not signed leases. Four other districts - Denton, Argyle, Krum and Ponder - have signed leases, according to documents obtained in open records requests. According to Denton documents, leases and mineral pooling agreements for gas wells drilled near Denton schools include Guyer High School, which has a well site within 500 feet, and McNair Elementary School, which is about 1,000 feet from a gas well. The state’s required setback is 200 feet.[27]

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Race and Class A January 2016 article in American Journal of Public Health found that poor, heavily Hispanic neighborhoods disproportionately bear the brunt hydraulic fracturing  wastewater burden in Texas› booming  Eagle Ford Shale. Wastewater disposal wells in southern Texas are disproportionately permitted in areas with higher proportions of people of color and residents living in poverty. Of the more than 217,000 racial minorities living less than three miles from the Texas disposal well sites, 83% were Hispanic.[28] The study found [[hydraulic fracturing] slightly higher in white communities but wastewater wells higher in communities of color. Dr. Jill Johnston, the lead author of the study told Environmental Health News, “A lot of people there [Eagle Ford area] are reliant on groundwater, putting this all underground is jeopardizing water sources.” [29] Air pollution

Eagle Ford According to an investigation into air quality and Eagle Ford oil/gas wells by the Center for Public Integrity:[30] there has been a 100-percent statewide increase in unplanned toxic air releases associated with oil and gas production in the region since 2009; only five permanent air monitors are installed in the 20,000-square-mile Eagle Ford region; drillers of thousands of wells are allowed to self-audit their emissions without reporting them to the state, and the Texas Commission on Environmental Quality (TCEQ) does not know some of the facilities exist. An internal agency document acknowledges that the rule allowing this practice “[c] annot be proven to be protective”; companies that break the law are rarely fined: of the 284 oil and gas industry-related complaints filed with the TCEQ by Eagle Ford residents between Jan. 1, 2010, and Nov. 19, 2013, only two resulted in fines despite 164 documented violations. The largest was just $14,250; the Texas legislature has cut the TCEQ’s budget by a third since the Eagle Ford boom began, from $555 million in 2008 to $372 million in 2014.

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Dish, TX By 2009, residents of Dish, Texas living near 11 natural gas compression stations became concerned about the odor, noise, and health problems they were experiencing, including headaches and blackouts, as well as neurological defects and blindness in their horses. Their mayor reported the accounts to Texas regulators and eventually hired a private environmental consultant, who in 2009 found that air samples contained high levels of neurotoxins and carcinogens.[31]

Denton, TX In October 2014, infrared videos that were taken over a three-month period showed that oil and gas air pollution is “ongoing, chronic, and unaddressed in Denton, Texas despite assurances of safety by industry.”[32]

Decatur, TX A Texas jury on April 2014 awarded $2.9 million to Bob and Lisa Parr who alleged their family suffered health problems, as well as sick pets and livestock, on their ranch because of wells drilled and fracked in the Barnett Shale by Aruba Petroleum Inc. on neighboring property, finding Aruba intentionally created a private nuisance. [33]

VOCs The Texas Commission on Environmental Quality has reported that storage tanks used in the exploration and production of natural gas and oil are the largest source of VOCs in the Barnett Shale.[34]

Ozone Ground-level  ozone  (smog) is formed when nitrous oxides (NOx) react with volatile organic compounds (VOCs) in the presence of heat and sunlight. According to a 2009 Environmental Defense Fund report, the natural gas and oil industry in the Barnett Shale area produced more smog-forming

Fracking in the USA 677 emissions during the summer of 2009 than were produced by all motor vehicles in the Dallas Fort Worth metropolitan area.[35] Using computer models, the Houston Advanced Research Center estimated that emissions from natural gas compressor stations and flares may be contributing significant amounts of ground-level ozone and formaldehyde in the Dallas-Fort Worth area.[36] San Antonio, Texas has violated federal ozone standards dozens of times since 2008, and U.S. Environmental Protection Agency could designate the city a nonattainment area for ozone. Local officials are waiting for the results of a state-funded study to pinpoint the source of the pollution. Preliminary numbers from the study indicate that much of the problem lies in the Eagle Ford.[37]

Silica In July 2012, two federal agencies released research highlighting dangerous levels of exposure to silica sand at oil and gas well sites in five states: Colorado, Texas, North Dakota, Arkansas, and Pennsylvania. Silica is a key component used in fracking. High exposure to silica can lead to silicosis, a potentially fatal lung disease linked to cancer. Nearly 80 percent of all air samples taken by the National Institute of Occupational Safety and Health showed exposure rates above federal recommendations. Nearly a third of all samples surpassed the recommended limits by 10 times or more. The results triggered a worker safety hazard alert by the Occupational Safety and Health Administration.[38]

Benzene In drinking water, the  Environmental Protection Agency  (EPA) has set the maximum contamination level at five parts per billion. The EPA has also set the level of benzene permissible in outdoor air levels at five parts per billion. The Environmental Integrity Project puts this EPA figure in perspective. A quarter teaspoon of benzene will make an average sized swimming pool exceed the EPA benzene limit.[39] The non-profit group  Shaletest.org  monitored gas drilling sites in Texas›s Barnett Shale in 2012 and found elevated levels of several chemicals, including toluene and the carcinogen benzene. The Texas Commission on Environmental Quality found airborne benzene near Barnett Shale wells at levels of up to 500 to 1,000 parts per billion

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— more than five times higher than allowable limits. The commission’s results came shortly after tests conducted by Deborah Rogers, who runs an organic goat farm in west Fort Worth and by the town of Dish in Denton County. Those privately funded tests showed, along with benzene and other chemicals, high levels of carbon disulfide, which can lead to neurological problems. Honeycutt said the commission began finding plumes of volatile organic compounds at Barnett oil and gas sites as far back as 2007.[40] In September 2014, BlackBrush O&G, reported injecting a mix of crude oil, butane, and other fluids containing up to 48,000 gallons of benzene into a well in Dimmit County, Texas. Between May 2013 and February 2014, Discovery Operating Services reported injecting solvents containing almost 1,000 gallons of benzene into eleven wells in Midland and ton Counties.[41]

Methane Texas Monthly reported that the Environmental Defense Fund estimates that approximately 25,000 natural gas wells in the Barnett Shale emit up to 60,000 kilograms of methane an hour. Aliso Canyon in Porter Ranch, California emitting at its peak back 58,000 kilograms an hour in November 2015.[42] In July 2015, a two-year study sponsored by the Environmental Defense Fund reported that fracking in the Barnett Shale region of Texas was releasing at least 50 percent more methane from drilling operations than the EPA has estimated.[43] After the Environmental Defense Fund completed the statistical analysis of their study December 2015, the organization graded that 50 percent figure to 90 percent.[44] Water

Water Use A 2013 study published in Environmental Science and Technology looked at past and projected water use for fracking in the Barnett, Eagle Ford, and Haynesville shale plays in Texas, and found that fracking in 2011 was using more than twice as much water in the state as it was three years earlier. In Dimmit County, home to the Eagle Ford shale development in South Texas, fracking accounted for nearly a quarter of overall water consumption in

Fracking in the USA 679 2011 and is expected to grow to a third in a few years, according to the study.[45] According to various news reports, droughts in Texas are being exacerbated by fracking operations.[46] From January 2011 through May 2013, fracking operators in the Eagle Ford Shale region of Texas used approximately 19 billion gallons of water for its 4,300-plus wells. This was the highest water use of any fracking region in the country.[47]

Water Contamination From 2004-2014, it was reported that a “Texas spreadsheet contains more than 2,000 complaints, and 62 of those allege possible well-water contamination from oil and gas activity.”[48] A 2013 study of 100 private water wells in and near the Barnett Shale in Texas showed elevated levels of potential contaminants such as arsenic and selenium closest to natural gas extraction sites.[49]

Range Resources Investigation In December 2010, the EPA determined that natural gas drilling by Range Resources  near homes in Parker County, Texas caused or contributed to the contamination of at least two residential drinking water wells with extremely high levels of methane, as well as benzene. The EPA ordered the company to step in immediately to stop the contamination, provide drinking water to the affected residents, and provide methane gas monitors to the homeowners. EPA also issued an imminent and substantial endangerment order under Section 1431 of the Safe Drinking Water Act. The EPA said it has data showing the presence of natural gas at the two wells, and ordered Range to investigate other nearby properties to determine if their drinking water is at risk.[50] In a hearing called shortly thereafter, the Railroad Commission, which regulates oil and gas drilling in Texas, exonerated Range. One member of the commission called EPA’s action “a frontal assault on domestic natural gas production.” The EPA pressed ahead in federal court, but before the trial court ruled, an element of the case went to the 5th U.S. Circuit Court of Appeals, based in New Orleans.[51] In March 2012, the EPA withdrew its order requiring Range Resources to provide water for the two North Texas families. The agency joined with Range seeking dismissal of the case in the Court of Appeals, stating that

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its decision allowed the agency to shift the focus “away from litigation and toward a joint effort on the science and safety of energy extraction.”[52] In a letter sent as part of the dismissal agreement, Range committed to testing 20 wells in Parker County four times in the next year.[53] In January 2013, the Associated Press reported that it obtained confidential documents showing the EPA asked independent scientist Geoffrey Thyne to analyze samples taken from 32 water wells near Range’s Parker County wells in 2010, and Thyne concluded from chemical testing that gas in the water could have originated from Range’s wells. After the tests, in December 2010, the EPA issued its emergency order, but rescinded the order in March 2011. The Associated Press concludes that its confidential report “and interviews with company representatives show that the EPA had scientific evidence against the driller, Range Resources, but changed course after the company threatened not to cooperate with [the pending fracking] national study.”[54] The EPA also dropped its investigations into water contamination from shale gas drilling in Dimock, PA, and Pavillion, WY.[55] In 2014, it was reported that while Range’s consultants concluded methane levels in Parker County were safe (4.2 milligrams per liter of methane in mid-2012, and 20 milligrams in November 2012), tests by Duke University one month later in December 2012 found potentially explosive levels (54.7 milligrams). Homeowners want the EPA to re-open the case, saying the agency relied on tests conducted by the company itself without adequate oversight.[56] In 2016, Stanford University scientist, Rob Jackson, linked the groundwater contamination to poorly constructed wells. Jackson used the Parker County case as an example. He told Phys.org, “At that site, the company cemented very near the surface and deep underground, but they put no cement for 4,000 feet in between,” he explained. “The gap allowed gases to move up and down freely like a chimney and contaminate the drinkingwater supply.”[57]

Canadian Company Tests Waterless Fracking in Texas In March 2013, The Texas Tribune reported that a new technology, dubbed “waterless fracking,” could perhaps address the problem of water use in fracking operations. It was reported that “a Canadian company called GasFrac is using a combination of gelled propane and butane to conduct fracking, without the use of water. The technology is new and may cost more than conventional hydraulic fracking. But waterless fracking will

Fracking in the USA 681 have its attractions if the water shortage in Texas persists. While the process requires a lot of propane and is said to be less effective than water in deep formations, propane is readily available in south Texas and also has the advantage that it is less likely to damage shale formations than water. In addition to propane, some companies are experimenting with carbon dioxide and nitrogen.”[58] Tremors A 2012 study published in the journal Proceedings of the National Academy of Sciences analyzed 67 earthquakes recorded between November 2009 and September 2011 in a 43.5-mile (70 kilometers) grid covering northern Texas’ Barnett Shale formation. The study found that all 24 of the earthquakes with the most reliably located epicenters originated within 2 miles (3.2 km) of one or more injection wells for wastewater disposal. The study was headed by associate director and senior research scientist Cliff Frohlich at the University of Texas at Austin’s Institute for Geophysics. Before a series of small quakes on Halloween 2008, the Dallas area had never recorded a magnitude-3 earthquake, according to Frohlich. USGS data shows that, since then, there has been at least one quake at or above a magnitude 3 every year except 2010. Frohlich said the intensification in seismic activity in the Dallas area came the year after ground just south of (and thousands of feet below) the Dallas airport began to be inundated with wastewater from hydraulic fracturing. The injection well has been out of use since September 2011, but though water is no longer being added, lingering pressure differences from wastewater injection could still be contributing to the lubrication of long-stuck faults, according to Frohlich. Three unusual earthquakes shook a suburb west of Dallas on September 29 and 30, 2012. The first quake was a magnitude 3.4, hitting a few miles southeast of the Dallas-Fort Worth (DFW) International Airport. It was followed 4 minutes later by a 3.1-magnitude aftershock that originated nearby. A third, magnitude-2.1 quake struck 24 hours later, with an epicenter a couple miles east of the first. No injuries were reported. Frohlich believes they are connected to wastewater disposal.[59] Lawsuits In April 2014, a Wise County couple who sued gas driller Aruba Petroleum won a $2.9 million award from a Dallas jury. The couple claimed that natural gas operations near their 40-acre ranch made them sick, creating a public nuisance and forcing them to move. They presented medical evidence that the family’s health issues began about the time Aruba drilled the wells in 2008. It is believed to be one of the few cases filed by landowners

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claiming harm from Barnett Shale gas operations to have gone to trial most are dismissed or settled.[60] LNG terminals

Corpus Christi LNG Corpus Christi LNG was originally planned as an LNG Import Terminal and 23 miles of 48-inch pipeline, approved by FERC in April 2005.[61] On December 16, 2011,  Cheniere Energy, Inc. announced that its wholly owned subsidiary, Corpus Christi Liquefaction, LLC, was developing an LNG export terminal at the site, which was previously permitted for a regasification terminal. The LNG export terminal site is located on the La Quinta Channel in San Patricio County, Texas, and it is anticipated that the terminal would be primarily supplied by reserves from the Eagle Ford Shale, located approximately sixty miles northwest of Corpus Christi, Texas. The proposed liquefaction project (Corpus Christi Project) is being designed for up to 13.5 million tonnes per annum (mtpa). Cheniere has initiated FERC’s National Environmental Policy Act (NEPA) pre-filing review. The company plans for the first “trains,” or facilities where gas will be liquefied, to be in operation in 2018.[62] On March 25, 2013, UK energy company Centrica agreed to pay £10bn (US $15bn) over 20 years for 89bn cubic feet of gas annually from Cheniere. The first deliveries, by tanker, are expected in 2018.[63]

Freeport LNG Freeport LNG Development, L.P. designed, built and operates the Freeport LNG receiving and regasification terminal in Freeport, Texas. ConocoPhillips has bought two-thirds of the capacity of Freeport LNG and Dow Chemical the remaining third. Construction began in 2005 and was originally planned for LNG import, but is shifting to exports.[64] Freeport LNG filed two DOE applications, each for 511 BCF/year, in December 2010 and 2011, and received approval from DOE to export LNG to Free Trade Agreement countries in February 2011 and 2012. In December 2010, Freeport LNG also submitted a pre-filing request with FERC to begin the environmental review of the liquefaction project.[64] Freeport LNG intends to file its formal application pursuant to Section 3 of the Natural Gas Act (NGA) by August 2012 and will request that FERC

Fracking in the USA 683 authorize by 2013. Freeport LNG anticipates a construction schedule of approximately three to four years, beginning in early 2017.[64] On May 17, 2013, the DOE gave the green light to Freeport LNG Expansion and FLNG Liquefaction’s proposal to send 1.4 billion cubic feet per day of natural gas overseas for 25 years, allowing export to nations that do not have a free-trade agreement with the U.S. The decision came less than 24 hours after the Senate confirmed Energy Secretary Ernest Moniz, author of a 2011 MIT report on natural gas that advocated its export.[65]

Golden Pass LNG In October 2012, Qatar’s Golden Pass Products LLC received permission to export liquefied natural gas from the U.S. Golden Pass is 70% owned by state-run Qatar Petroleum International and 30% by ExxonMobil. The permit allows the company to export gas to nations that have free-trade agreements with the U.S. The partners will make a final decision about the proposed $10-billion export project after receiving regulatory approvals. The investment would pay for liquefaction plants with 15.6 million metric tons of annual capacity to be added to the existing Golden Pass LNG import terminal in Texas. Qatar is the world’s largest producer of LNG, and the project may become the Persian Gulf state’s first venture for selling LNG produced in another country.[66] Legislative issues and regulations

Fracking and Schools In 2011, State Rep. Lon Burnam, D-Fort Worth, filed a bill to prevent drilling within 1,200 feet of public schools statewide. The measure was one of many proposals that died after facing industry opposition. Burnam said he would continue pushing the measure but said publicly that he believes industry-friendly lawmakers will continue thwarting all but “watereddown” laws.[67]

Disclosure Rules Texas in 2011 was among the first states to pass a fracking disclosure law.[68]

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Due to rules that went into effect on February 1, 2012, Texas state law requires the names of products, chemicals, and their CAS numbers (the unique codes that the Chemical Abstracts Service assigns to individual chemical compounds) within 30 days after well completion, although deadlines may vary slightly. Only hazardous chemicals are matched with the products they go into and their concentration amounts. Companies are not required to disclose trade secret information unless the attorney general or court determines the information is not entitled to trade secret protection. A landowner or state agency can challenge trade secret classification. The information cannot be withheld from health care professionals in an emergency.[69] In December 2011, ALEC adopted model legislation based on the Texas law addressing the public disclosure of chemicals in fracking fluids. The disclosure bill provides large loopholes for companies wanting to protect fracking chemical “trade secrets.” The ALEC model legislation has since provided the basis for similar bills submitted in five states: Pennsylvania, Illinois, Indiana, New York, and Ohio. According to the New York Times, the legislation was sponsored by ExxonMobil.[70] A provision in the state law requires the disclosure of chemicals listed as trade secrets to emergency personnel, but not to toxicologists or academics who attempt to study the long-term effects of the chemicals.[71] The Houston Chronicle reported that operators in Texas have invoked the exemption to shield, and partially shield, the chemical identities of more than 170,000 ingredients from when the law took effect in February 2012 through April.[72]

Texas Railroad Commission The Texas Railroad Commission’s regulations related to oil and gas well construction and water protection, while not specifically directed at hydraulic fracturing, is meant to protect surface and ground water.[73]

Texas Agency Seeks to Decrease Industrial Flaring In May 2012, the Texas Railroad Commission announced they wanted to ensure that current rules regarding flaring were being followed. The agency also stated that regulations ought to ensure flaring of fracking gas was a last resort. Industries use “flaring” to burn off excess gases, which helps prevent a build that could cause an explosion, but also pollutes the air. Newer technologies allow industry to reduce or eliminate the use of flaring.[74]

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Buffer Zone in Dallas In August 2013, the Dallas City Plan Commission reaffirmed its intentions to “require a 1500 foot buffer zone, or setback, between gas wells and socalled protected uses, like homes.” The Plan Commission must hold two more public hearings before finalizing the new gas drilling ordinance and sending it to the City Council for a vote.[75] Fracking bans

Denton, Texas In November 2014, voters in Denton, Texas voted to ban fracking. Denton, known for being the birthplace of fracking, became the first city in Texas to ban the practice. The measure was spearheaded by a community group called Frack Free Denton. Reports suggested if the ban passed there would eventually be a legal fight “over a city’s power to regulate for health and safety and the rights of mineral owners to develop their resources.”[76] In October 2014, the City of Denton was sued by a group of “royalty interest owners claiming that the city’s current temporary ban violates their property rights.”[77][78] The day after Denton voters banned fracking, Texas Oil and Gas Association and the state’s General Land Office filed lawsuits in an attempt to stop the city’s effort to prohibit fracking in the city. The lawsuit claimed that the “ordinance exceeds the limited power of home-rule cities and intrudes on the authority of several state agencies, particularly the Texas Railroad Commission, which regulates the oil and gas industry.” The lawsuit also asked for an expedited hearing.[79] Only one week after the ban in Denton passed, state officials notified the city that they would continue to issue drilling permits within Denton city limits, even though the ban is to go into effect on December 2, 2014.[80] Denton city lawyers filed a legal brief on December 1, 2014, one day before the ban was to go into effect, which in part read: “Those activities have caused conditions that are subversive of public order and constitute an obstruction of public rights of the community as a whole ... Such conditions include, but are not limited to, noise, increased heavy truck traffic, liquid spills, vibrations and other offensive results.”[81] On December 2, 2014, the fracking ban in Denton went into effect. Denton Mayor Chris Watts stated that he wasn’t sure what immediate impact the ban would pose to drillers. Watts said the ban did not mean

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operators must “shut down the wells and turn off the lights” on existing wells.[82] On December 4, 2014 environmental groups filed an intervention petition. The petition requested that the groups could enter the two lawsuits filed against the city by the pro-fracking Texas Oil and Gas Association and the Texas General Land Commission.[83] According to research from the Perryman Group, Denton’s fracking ban could cost the city $250 million in economic activity and 2,000 jobs.[84]

Banning Fracking Bans In April 2015, Texas Republican lawmakers moved to ban Texas cities from imposing prohibitions on fracking as well as other potentially harmful oil and gas developments within state boundaries. The Republican-dominated state Senate approved the bill in early May and sent it to Gov. Greg Abbot’s desk, which the Republican governor signed into law.[85][86] Reports In September 2013, the environmental organization Earthworks released a study, which reported on fracking pollution in the state of Texas. Earthworks’ investigation looked at the oil and gas operations and government oversight in Texas’s Eagle Ford Shale. Earthworks reported the following: “Residents requested state regulators provide relief from oil and gas air pollution; Regulators discovered pollution so dangerous they evacuated themselves; Regulators took no subsequent action to warn or otherwise protect the residents at risk; Regulators took no subsequent action to penalize the responsible company; Residents continue to live with exposure to dangerous oil and gas air pollution. Oil and gas operations in shale formations release chemicals to air, water, and soil that are hazardous to human health. Government shares the blame for these releases because rules governing oil and gas development don’t protect the public. Adding insult to injury, state regulators don’t reliably enforce these rules. By failing to deter reckless operator behavior, regulators practically condone it, thereby increasing health risks for residents living near oil and gas development.”[87] Oil spills

Fracking in the USA 687 On October 29, 2013, the Railroad Commission of Texas reported that 17,000 gallons of crude oil spilled from an eight-inch pipeline owned by Koch Pipeline Company.[88]

2012 Oil and Gas Spills In 2012, Texas regulators sought enforcement for 2 percent of the 55,000 oil and gas spill violations identified by drilling inspectors that year, according to state records.[89]

2010-2012 Pollution Violations In 2013, E&E News reported that Texas air regulators fined 11 oil and pipeline companies for pollution violations in the Eagle Ford Shale field in the past three years. An additional 188 operators were allowed to fix their violations without paying a fine, the Texas Commission on Environmental Quality said.[90] Citizen activism

Lewisville Lake Hydraulic fracturing could come to Lewisville Lake in Denton County this spring 2016. An agency within the US Department of Interior, the Bureau of Land Management (BLM), will determine whether to auction off drilling rights for 259 acres in Hickory Creek for the next 10 years. The auction is set for April 20, 2016 at the BLM offices in Santa Fe, New Mexico.[91] Lewisville Lake provides drinking water for millions. It has a high-risk dam. The Army Corps of Engineers has it listed as the nation’s eight most hazardous dams.[92] City councils of several cities including Lewisville and Colony are expected to submit formal letters of protest against the Lewisville Lake drilling project. [93] Denton, Flower Mound, and Hickory Creek city councils are scheduled to discuss the project and potentially join the protest.[94] Jody Puckett, director of Dallas Water Utilities, sent a formal letter of protest to the BLM. Puckett claims the project does not account for the safety of the dam.[95]

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Groups Urge Investigation of EPA Actions in Texas Water Contamination Case On February 11, 2013 more than 80 organizations from 12 states and a New York State Senator called on the inspector general of the EPA to investigate a decision to drop legal action against a drilling company despite evidence that it had polluted residents’ well water near Fort Worth, Texas. In the joint press release, the groups stated, “The organizations sent a letter to EPA Inspector General Arthur A. Elkins, Jr., asking him to broaden an ongoing investigation of a case that made national news last year when the EPA dropped an enforcement action against Range Resources Ltd. after earlier invoking rare emergency authority under the Safe Drinking Water Act. New York State Senator Tony Avella is sending a similar letter later today. Elkins began investigating the case after six U.S. senators asked him last June to determine whether EPA had followed proper procedures.”[96] Citizen groups Argyle Bartonville Communities Alliance Barnett Shale Drilling Activity Bluedaze: Drilling Reform — Texas Sharon Citizens Organizing for Resources and Environment Dallas Area Residents for Responsible Drilling Denton Drilling Awareness Group Downwinders at Risk Earthworks’ Oil and Gas Accountability Project (OGAP) Frac Dallas Go Haynesville Shale North Central Texas Communities Alliance Industry groups Barnett Shale Energy Education Council Companies Devon Energy EOG Resources Gulftex Operating Ranger Resources XTO Energy Reports

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The Environmental Integrity Project Diesel in Fracking From 2010 to July 2014, drillers in the state of Texas reported using 21.96 gallons of diesel injected into 25 wells. The Environmental Integrity Project extensively researched diesel in fracking. The environmental research organization argues that diesel use in fracking is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[97] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[98]

Fracking Pollution The 2012 report by the Environmental Integrity Project,  “Nearly 93,000 Tons of Pollution Released From sets and ‘Emission Events’ at Natural Gas and Petrochemical Plants in Texas,” found that flares, leaking pipelines, and tanks emitted 92,000 tons of toxic chemicals into the air during accidents, break-downs, and maintenance at Texas oil and gas facilities, refineries, and petrochemical plants from 2009 to 2011. The data was collected from the Texas Commission on Environmental Quality and shows that, in addition to the emissions from normal operations, more than 42,000 tons of sulfur dioxide and just over 50,000 tons of smog-forming volatile organic compounds were released from 2009 through 2011. Natural gas operations, including well heads, pipelines, compressors, boosters, and storage systems, accounted for more than 85 percent of total sulfur dioxide and nearly 80 percent of the VOCs released during these emission events. The report shows a pattern of neglect as the pollution from these events drags on for weeks or months.

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Environment Texas Report on External Costs The 2012 Environment Texas report,  “The Costs of Fracking: The Price Tag of Dirty Drilling’s Environmental Damage,”  looked at the external costs of fracking - damage to natural resources, drinking water contamination, economic impacts like home values, health problems, and public infrastructure - and concluded that the overall costs associated with fracking would outweigh the economic benefits for states. The study calls for comprehensively restricting and regulating fracking to reduce its environmental, health, and community impacts, and ensuring -front financial accountability by requiring oil and gas companies to post much higher bonds that reflect the true costs of fracking.

Fort Worth League of Neighborhoods A report by the Fort Worth League of Neighborhoods in February 2011 called for buffers of 1 mile, or 5,280 feet, between gas wells and schools to protect students from air pollution. Industry supporters disputed the factual basis for that recommendation.[99]

Earthworks The 2011 Earthworks report,  “Natural Gas Flowback: the Dark Side of the Boom: How the Texas gas boom affects community health and safety,” examined the data on the health effects of gas drilling and hydraulic fracturing on Texans throughout the Barnett Shale, including issues of water contamination, water depletion, and air pollution. The report recommended that: The Texas Commission on Environmental Quality must enforce emission limits from oil and gas exploration and production equipment; The Texas Railroad Commission should adopt rules that provide the public with full public disclosure of oil and gas drilling and fracking fluids, as well as implement rules requiring closed-loop drilling systems and water-based drilling fluids; The Texas Water Development Board should exercise its authority to evaluate groundwater resources and the impact that hydraulic fracturing withdrawal is having on

Fracking in the USA 691 groundwater resources, and implement rules requiring recycling of flowback water; and Authority to regulate air emissions from drilling and oversee permitting should be overseen by the U.S. Environmental Protection Agency through a federal advisory commission that includes citizen representation. The agency should also identify the sources of methane contaminants in groundwater. The 2013 Earthworks report,  “Reckless Endangerment While Fracking the Eagle Ford Shale: Government fails, public health suffers and industry profits from the shale oil boom,” found that: 1. Residents of Karnes County requested state regulators provide relief from oil and gas air pollution; 2. Regulators discovered pollution (Volatile Organic Compounds at 1,100 ppm) and evacuated themselves; and 3. Regulators took no subsequent action to protect the residents, nor penalize the responsible company. Consequently, residents continue to live with exposure to the pollution.[100]

University of Texas Study In February 2012, a University of Texas study, “Separating Fact from Fiction In Shale Gas Development,” found no evidence of aquifer contamination from hydraulic fracturing chemicals in the subsurface by fracturing operations, and observed no leakage from hydraulic fracturing at depth. Critics say that proponents of hydraulic fracturing have incorrectly reported that the study found no environmental contamination,[101][102]  when the study found that all steps in the process except the actual injection of the fluid (which proponents designated hydraulic fracturing) have resulted in environmental contamination.[103]  It was later reported that the lead researcher Charles Groat was a member of the board of gas producer PXP: company filings indicated that in 2011, he received more than $400,000 in compensation from the gas company, which has fracking operations in Texas.[104] On August 13, 2012, the University of Texas at Austin appointed Norman Augustine to chair a three-member panel charged by the university with independently reviewing the study led by Groat. Yet Augustine also has gas industry ties, serving on the board of Houston-based ConocoPhillips (or its predecessor company) from 1989 to 2008.[105]

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References 1. Bill Powers, Cold, Hungry and in the Dark, New Society Publishers, 2013. 2. Matthew Tresaugue and John MacCormack, “Fracking chemicals disclosures set off few alarms,” The Houston Chronicle, Apr. 1, 2012. 3. Ian Urbina,  Regulation Lax as Gas Wells’ Tainted Water Hits Rivers,  New York Times, Feb. 26, 2011. 4. Peggy Heinkel-Wolfe and Lowell Brown, Stuck in the middle, Denton Record Chronicle, Feb. 11, 2012. 5. Naveena Sadasivam, “California Capped a Massive Methane Leak, but Another is Brewing — Right Here in Texas,”  The Texas Observer, Feb 13, 2016. 6. Barnett Shale Economic Impact Study, May 2007, p.16. 7. Marc Airhart, “Won’t You Be My Neighbor?” Jackson School of Geosciences. Jan. 2007 8. Jack Williams, Shale Gas: The Keys to Unlocking its Full Potential: Speech by XTO President Jack Williams, ExxonMobil Website, Jun. 14, 2011. 9. Charlez (1997). Rock Mechanics, 239. 10. Bill McKibben  (8 Mar. 2012). “Why Not Frack?”.  The New York Review of Books 59 (4). Retrieved on 21 Feb. 2012. 11. Scott R. Reevbasins invigorate U.S. gas shales play, 22 Jan. 1996, p.53-58. 12. The Barnett Shale, Railroad Commission of Texas, accessed Oct. 2013. 13. US Energy Information Administration:  Is U.S. natural gas production increasing?, accessed 20 Mar. 2009. 14. Bill Powers, Cold, Hungry and in the Dark, New Society Publishers, 2013. 15. USGS Estimates 53 Trillion Cubic Feet of Gas Resources in Barnett Shale U.S. Department of the Interior, U.S. Geological Survey, Dec. 17, 2015. 16. Eagle Ford Shale - South Texas - Natural Gas & Oil Field, OilShaleGas.com 17. Naveena Sadasivam, “California Capped a Massive Methane Leak, but Another is Brewing — Right Here in Texas,”  The Texas Observer, Feb 13, 2016. 18. Lobdill, Jerry (2009-10-21). “Leasing Our Lives Away,” Fort Worth Weekly, retrieved on 2009-10-21. 19. McGraw, Dan (2009-04-27).  “Courthouse Gusher,”  Fort Worth Weekly, retrieved on 2010-03-31. 20. Louise S. Durham, “Hot Barnett play creating wealth, AAPG Explorer,” Sept. 2007, p.46–47. 21. Heinkel-Wolfe, Peggy (2008-01-15). Gas drilling’s dirty side effect”, Denton Record Chronicle, Denton Publishing. Retrieved on 2009-12-27. 22. Lee, Mike; San Juan Citizens Alliance (2009-01-27). EPA sued over lack of oil and gas regulations”, Fort Worth Star Telegram, McClatchy. Retrieved on 2009-12-27. 23. Alison Sider, Fracking Firms That Drove Oil Boom Struggle to Survive,  Los Angeles Times, Jan. 26, 2016.

Fracking in the USA 693 24. Alison Sider, Fracking Firms That Drove Oil Boom Struggle to Survive, The Wall Street Journal, Sept. 23, 2015. 25. Alison Sider, Fracking Firms That Drove Oil Boom Struggle to Survive, The Wall Street Journal, Sept. 23, 2015. 26. Alison Sider, Fracking Firms That Drove Oil Boom Struggle to Survive, The Wall Street Journal, Sept. 23, 2015. 27. Peggy Heinkel-Wolfe and Lowell Brown, Stuck in the middle, Denton Record Chronicle, Feb. 11, 2012. 28. Jill E. Johnston, Emily Werder, and Daniel Sebastian, Wastewater Disposal Wells, Fracking, and Environmental Injustice in Southern Texas, American Journal of Public Health, Jan. 2016. 29. Brian Bienkowski, Poor, minorities carry the burden of frack waste in South Texas, Environmental Health News, Feb. 3, 2016. 30. Big Oil, Bad Air, Public Integrity, Feb 18, 2014. 31. Burnett, John, “Health issues follow natural gas drilling in Texas,” NPR, Nov. 3, 2009. 32. Videos, air sampling reveal Denton City’s broken promises to monitor fracking pollution, Vote for the Ban, May 1, 2014. 33. Renee Lewis, Texas jury awards $3M to family for illnesses related to fracking, Al Jazeera America, Apr. 23, 2014. 34. Elena Craft,  Do Shale Gas Activities Play A Role In Rising Ozone Levels? Mom’s Clean Air Force, Jul. 13, 2012. 35. Al Armendariz,  “Emissions from Natural Gas Production in the Barnett Shale Area and Opportunities for Cost- Effective Improvements,”  Jan. 26, 2009 at 1, 7, 8 and 18. 36. Eduardo P. Olaguer,  The potential near-source ozone impacts of stream oil and gas industry emissions,  Journal of the Air & Waste Management Association, Volume 62, Issue 8, 2012. 37. Lisa Song, What›s Behind Surging Ozone Pollution in Texas? Study to Weigh Role of Fracking in Health Hazard, InsideClimate News, Oct 23, 2013. 38. Adam Voge,  Fracking dust alert not shocking in Wyoming, Wyoming Star Tribune, Jul. 30, 2012. 39. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 40. Lee, Mike, “State worried about air pollution near Barnett Shale wells,” StarTelegram (Texas), Nov. 22, 2009. 41. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014. 42. Naveena Sadasivam, “California Capped a Massive Methane Leak, but Another is Brewing — Right Here in Texas,” The Texas Observer, Feb. 13, 2016. 43. John Light, “Methane from fracking is probably more of a problem than EPA thinks,” Grist, Jul. 8, 2015.

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44. Lisa Song, “Texas Fracking Zone Emits 90% More Methane Than EPA Estimated,” Inside Climate News, Dec. 7, 2015. 45. Jean-Philippe Nicot and Bridget R. Scanlon,  Water Use for Shale-Gas Production in Texas, U.S., Environ. Sci. Technol. 2012, 46, 3580−3586. 46. Laura Beans, “Drought-Stricken Texas Fracks Its Way to Water Shortages,” EcoWatch, Aug. 20, 2013. 47. Peyton Fleming, “Insatiable Thirst? The Fracking/Water Collision in South Texas,” National Geographic, Feb. 7, 2015. 48. Water in at least three U.S. states is polluted from FRACKING as hundreds of complaints are reported across the country, Associated Press, Jan. 6, 2014. 49. Brian E Fontenot, Laura R Hunt, Zacariah Louis Hildenbrand, Doug D Carlton, Hyppolite Oka, Jayme L Walton, Dan Hopkins, Alexandra Osorio, Bryan Bjorndal, Qinhong Hu, and Kevin Albert Schug,  An evaluation of water quality in private drinking water wells near natural gas extraction sites in the Barnett Shale Formation, Environ. Sci. Technol., Jul. 25, 2013. 50. EPA Issues an Imminent and Substantial Endangerment Order to Protect Drinking Water in Southern Parker County, EPA, Dec. 2010. 51. Mike Soraghan, EPA›s retreat in Range case is latest score for industry, states, E&E News, Apr. 2, 2012. 52. EPA Backs Down From Fracking Contamination Order, Associated Press, Mar. 30, 2012. 53. Mike Soraghan, EPA›s retreat in Range case is latest score for industry, states, E&E News, Apr. 2, 2012. 54. Ramit Plushnick-Masti, REPORT: The EPA Backtracked On A Tainted Water Finding After A Driller Protested, Associated Press, Jan. 16, 2013. 55. Kate Sinding, Why Would EPA Hide Info on Fracking & Water Contamination in Dimock? NRDC, Jul. 28, 2013. 56. Mark Drajem,  Duke Fracking Tests Reveal Dangers Driller’s Data Missed, Bloomberg, Jan 9, 2014. 57. Does living near an oil or natural gas well affect your drinking water? Phys. org, Feb. 14, 2016. 58. Canadian Company Tests Waterless Fracking in Texas,  Matt Whittington, Yahoo News, Mar. 27, 2013. 59. Eli MacKinnon,  Unusual Dallas Earthquakes Linked to Fracking, Expert Says, Live Science, Oct. 2, 2012. 60. Wise County, Texas, couple win $2.9 million jury award in drilling lawsuit, Fort Worth Star-Telegram, Apr. 23, 2014. 61. North American LNG Import Terminals Status of Proposed and Existing Facilities, Natural Gas Intelligence, accessed Apr. 2012. 62. Cheniere plans Corpus Christi export terminal,  LNG World News, Dec. 16th, 2011. 63. Fiona Harvey,  US shale gas to heat British homes within five years,  The Guardian, Mar. 25, 2013.

Fracking in the USA 695 64. 65. 66. 67. 68.

69. 70. 71.

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73. 74. 75. 76. 77.

78. 79. 80. 81. 82. 83. 84. 85.

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      Freeport: Welcome to our website,  Freeport LNG Development, accessed April 2012.  Zack Colman, DOE gives green light to controversial natural gas export project, The Hill, May 17, 2013. Qatar, Exxon venture wins first U.S. LNG export permit, Bloomberg News, Oct. 4, 2012. Peggy Heinkel-Wolfe and Lowell Brown, Stuck in the middle, Denton Record Chronicle, Feb. 11, 2012. Susan Carroll and Matt Dempsey, “Fracking research hits roadblock with Texas law Proprietary label keeps chemicals confidential,” The Houston Chronicle, Feb. 6, 2016. Fracking Chemical Disclosure Rules, ProPublica, Feb. 16, 2012. Mike McIntire,  Conservative Nonprofit Acts as a Stealth Business Lobbyist, New York Times, Apr. 21, 2012. Susan Carroll and Matt Dempsey, “Fracking research hits roadblock with Texas law Proprietary label keeps chemicals confidential,” The Houston Chronicle, Feb. 6, 2016. Susan Carroll and Matt Dempsey, “Fracking research hits roadblock with Texas law Proprietary label keeps chemicals confidential,” The Houston Chronicle, Feb. 6, 2016. Regulations, GroundWork, accessed Apr. 24, 2012. Texas agency seeks to decrease industrial flaring, Fuel Flex, May 23, 2012 BJ Austin, “Proposed Buffer Zone For Dallas Gas Wells May Shrink Drilling,” KERA News, Aug. 22, 2013. Jim Malewitz, “Denton Fracking Ban Could Spur Wider Legal Clash,” The Texas Tribune, Jul. 25, 2014. Justin Scott, “Suit by Denton, Texas, Royalty Interest Owners Could be Harbinger of More Suits If Proposed Hydraulic Fracturing Ban Passes,” North American Shale Blog, Oct. 14, 2014. Fracking banned in its birthplace: Texas town votes to outlaw hydraulic fracturing RT, Nov. 5, 2014. Max B. Baker, “Energy industry, Texas sue Denton over fracking ban,” StarTelegram, Nov. 5, 2014. Gregg Levine, “Texas messes with Denton,”  Aljazeera America, Nov. 11, 2014. Jim Malewitz, “Fracking a “Nuisance,” Denton Tells Court,” The Texas Tribune, Dec. 1, 2014. Max B. Baker, “Denton defends fracking ban as it hits the books,”  StarTelegram, Dec. 2, 2014. Steve Horn, “Environmental Groups File Motion to Intervene in Defense of Denton Fracking Ban,” DeSmogBlog, Dec. 4, 2014. Chris Faulkner, “Fracking bans prove costly,”  The Detroit News, Jan. 7, 2015. Texas seems on verge of banning fracking bans, CBS News, May 5, 2015.

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86. Wade Goodwyn, “New Texas Law Makes Local Fracking Bans Illegal,” NPR, May 20, 2015. 87. Reckless Endangerment While Fracking the Eagle Ford Shale, Earthworks, Sept. 19, 2013. 88. “17,000 gallons of crude oil spill near Smithville,” KVUE.com, Oct 29, 2013. 89. Mike Soraghan, Many mishaps among drillers, but few fines, E&E News, Jul. 15, 2013. 90. Mike Lee,  Texas regulators issue few fines for Eagle Ford pollution,  E&E News, Sep 30, 2013. 91. Brian Scott, Fracking Could Come to Lewisville Lake, nbcdfw.com, Feb. 6, 2016. 92. Jeff Mosie, “Cities, environmental groups protesting planned gas drilling at Lewisville Lake,” The Dallas Morning News, Feb. 12, 2016. 93. Chris Roark, “The Colony officials to vote on issuing letter protesting gas lease at Lewisville Lake,” The Colony Courier Leader, Feb. 11, 2016. 94. Jeff Mosie, “Cities, environmental groups protesting planned gas drilling at Lewisville Lake,” The Dallas Morning News, Feb. 12, 2016. 95. Jeff Mosie, “Cities, environmental groups protesting planned gas drilling at Lewisville Lake,” The Dallas Morning News, Feb. 12, 2016. 96. Call to investigate the EPA for its withdrawal of legal action against Range Resources, Earthworks, Feb. 11, 2013. 97. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 98. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014. 99. Peggy Heinkel-Wolfe and Lowell Brown, Stuck in the middle, Denton Record Chronicle, Feb. 11, 2012. 100. Sharon Wilson, Lisa Sumi, and Wilma Subra, Reckless Endangerment While Fracking the Eagle Ford Shale: Government fails, public health suffers and industry profits from the shale oil boom, Earthworks, Sept. 19, 2013. 101. Vicki Vaughan, (16 Feb. 2012), “Fracturing ‘has no direct’ link to water pollution, UT study finds,” retrieved on 3 Mar. 2012. 102. Margaret Munro (17 Feb. 2012), “Fracking does not contaminate groundwater: study released in Vancouver, retrieved on 3 Mar. 2012. 103. Fact-Based Regulation for Environmental Protection in Shale Gas Development. Retrieved on 29 Feb. 2012. 104. Jim Efstathiou Jr.,  Frackers Fund University Research That Proves Their Case, Bloomberg, Jul. 22, 2012. 105. Vicki Vaughan,  Panelist reviewing fracturing study has his own industry ties, The Houston Chronicle, Aug. 16, 2012.

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Utah Utah’s 10-year Strategic Energy Plan, unveiled in 2011 by Utah Gov. Gary Herbert, calls for tapping the state’s oil sands and oil shale reserves while continuing to develop fossil fuels such as coal, oil, and natural gas. The plan also calls for putting together an energy-efficiency plan, but concludes that wind and solar power are not likely to have a major impact on the state›s energy portfolio over the coming decade.[1] Over the past decade hydraulic fracturing has increased in Utah’s Uinta Basin. Natural gas production in the area has steadily increased and reached an all-time high of 226 billion cubic feet (BCF) in 2006.[2]  2011 Utah natural gas rates were the lowest in the continental United States at $8.98 per thousand cubic feet.[3] Environmental impacts

Methane Leakage In September 2012, researchers at the National Oceanic and Atmospheric Administration (NOAA) and the University of Colorado in Boulder reported preliminary results from a field study in the Uinta Basin of Utah suggesting methane leakage of up to 9% of total gas production, nearly double the cumulative loss rates estimated from industry data. The NOAA researchers collected their data in February 2012 as part of a broader analysis of air pollution in the Uinta Basin, using ground-based equipment and an aircraft to make detailed measurements of various pollutants, including methane concentrations.[4] The research was published in 2013, and reported a methane leakage rate of 6.2 to 11.7% in the Basin.[5] The report vastly overshot the EPA’s estimate of .88 percent.[6]

Wastewater Ponds In 2007, 14 fracking wastewater ponds were built by Danish Flats Environmental Services, in Clark County, near the Colorado border. The ponds are filled with oil and gas wastewater from fracking operations taking place in Colorado. Since that time the company has allowed the wastewater to evaporate into the air without acquiring an air quality permit. However, regulators have found that the company, by allowing the water to

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simply evaporate, was releasing methanol and other volatile organic compounds directly into the air. As a result the company was fined $50,0000 in early August 2014. State regulators are now looking at dozens of other wastewater sites around the state. Currently, Utah does not require for groundwater monitoring by companies operating wastewater facilities.[7]

Ozone Pollution In 2010 and 2011, ozone levels in Utah’s Uintah Basin soared. The peak value in 2011 was 139 parts per billion, according to Utah officials - 85 percent higher than the federal health standard of 75 ppb, and above the 99 ppb peak for 2011 in the bustling New York metropolitan area. In response, the oil and gas industry made more than $100 million in investments to curb emissions and set up a system to cut activity on days when ozone is likely to form. Even with the reductions and investments, in March 2011, there was a 124 ppb ozone reading. In winter 2012, NOAA and University of Colorado at Boulder researchers began fanning out across the Uintah Basin to determine the link between the area’s 10,000 oil and gas wells and high levels of winter ozone.[8] The multi-agency study found that 98 to 99 percent of the  volatile organic compounds  and 57 to 61 percent of the  nitrogen oxides  in the region came from oil and gas operations.[9] In February 2013, a government study reported that Utah’s oil and gas industry operations were the primary source of wintertime ozone-producing pollution in northeastern Utah.[10]

Diesel in Fracking From 2010 to July 2014, drillers in the state of Utah reported using 496.91 gallons of diesel injected into one single well. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains  benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of

Fracking in the USA 699 diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[11] Due to the Halliburton loophole, the Safe Drinking Act regulates benzene containing diesel-based fluids but no other petroleum products with much higher levels of benzene.[12]

Environmental Working Group Study In January 2010, a report released by the environmental watchdog Environmental Working Group highlighted problems posed to drinkingwater supplies by fracking, including contamination by cancer-causing chemicals. The report, titled “Drilling Around the Law,” details a study that tracked six months’ worth of chemical-disclosure records filed by several of the largest drilling corporations and includes information provided by some state and federal regulators, who concede they do not track fluids used in the process.[13] Studies

University of Texas Study A study released in February 2012 by the Energy Institute of the University of Texas at Austin (“Fact-Based Regulation for Environmental Protection in Shale Gas Development”) was reported by various media as determining that many reports of contamination are actually the result of above-ground spills or other mishandling of wastewater from shale-gas drilling, rather than the fracking process itself, and that many problems ascribed to fracking actually have other causes, such as “casing failures or poor cement jobs” (which was regarded as part of the drilling rather than the actual “well simulation,” fracking process).[14] Critics say that proponents of hydraulic fracturing have erroneously reported in the press and other media that the University of Texas Study found that hydraulic fracturing caused no environmental contamination,[15][16]  when the study found that all steps in the process except the actual injection of the fluid (which proponents artificially separated from the rest of the process and designated hydraulic fracturing) have resulted in environmental contamination.[17] The radioactivity of the injected fluid itself was not assessed in the University of Texas study.[17] Statoil announced a $5m research agreement (part of which will focus on oil shale) with UT’s Bureau of Economic Geology in September 2011,

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whose program director, Ian Duncan, was the senior contributor for the parts of the Texas study having to do with the environmental impacts of shale gas development.[18][17][19] Bureau of Land Management Auctions On February 16, 2016, over 100 locals at a Bureau of Land Management (BLM) oil and gas lease auction in Utah. Before the February auction have protested outside BLM fossil fuel auctions.[20] Author Terry Tempest Williams, and her husband purchased hundreds acres near their Castle Valley home at the auction to keep from getting drilled. The Williamses launch Tempest Exploration that will manage this lease and others they intend to acquire.[21] Proposed projects On March 16, 2012, the Obama administration authorized the Gasco development project: nearly 1,300 new natural gas wells, including more than 200 new wells in the Desolation Canyon proposed wilderness and gateway areas in Utah. The Department of the Interior also rejected calls by the U.S. Environmental Protection Agency (EPA) and tens of thousands of citizens to approve an alternative to Gasco’s proposal, which would have allowed for drilling while protecting the department’s plan to designate Desolation Canyon as wilderness and reduced the overall footprint and impact of the project. According to EcoWatch, the Desolation Canyon region is a $4 billion industry that generates approximately $300 million annually in state tax revenue and supports 65,000 jobs. Gasco is a Colorado-based natural gas company.[22] In December 2013, it was reported that Denver energy developer James K. Munn was interested in leasing land for natural gas exploration in Escalante, Utah, a small town with a population of 800. Escalante is located “at the heart” (but not within the actual borders) of the Grand StaircaseEscalante National Monument. Residents of the town were approached by employees of Front Runner Seismic, a Pennsylvania company that said they were representing Munn and seeking to lease their private property.[23]

References 1. Scott Streater, “Utah governor to push development across the West as WGA chairman,” Energywire, Jun. 14, 2012. 2. Drilling Boom Tied to Spike in Utah Air Pollution, Water Contamination From Shale, accessed Feb. 29, 2012.

Fracking in the USA 701 3. Jasen Lee, “Utah natural gas rates lowest in U.S.,”  Deseret News, Nov. 10, 2011. 4. Jeff Tollefson,  Methane leaks erode green credentials of natural gas, Nature 493, 12, Jan. 2, 2013. 5. Anna Karion et al., Methane emissions estimate from airborne measurements over a western United States natural gas field, Geophysical Research Letters, 2013. 6. Lindsay Abrams, “Huge amounts of methane are leaking from a Utah gas field,” Salon, Aug. 7, 2013. 7. Peter Moskowitz, “Utah fracking fine highlights wastewater pond threat,” Al Jazeera, Aug. 31, 2014. 8. Mark Jaffe,  Like Wyoming, Utah finds high wintertime ozone pollution near oil, gas wells, The Denver Post, Feb. 26, 2012. 9. 2012 Uinta Basin Winter Ozone and Air Quality Study, Utah Department of Environmental Quality; EPA; the Bureau of Land Management; the National Oceanic and Atmospheric Administration; Utah State University; the University of California; the University of Colorado, Boulder; and the Western Energy Alliance, Feb 1, 2013. 10. Kriz Hobson, “UTAH: Drilling is primary cause of ozone pollution,” Energywire, Feb. 20, 2013. 11. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014. 12. Fracking›s Toxic Loophole Thanks to the Halliburton Loophole Hydraulic Fracturing Companies Are Injecting Chemicals More Toxic than Diesel, The Environmental Integrity Project, Oct. 22, 2014. 13. Amy Joi O’Donoghue, “’Fracking’ pollutes our drinking water, study says,” Deseret News, Jan. 20, 2012. 14. UT study finds no direct link between fracking and groundwater contamination Jack Z. Smith, Star-Telegram, Feb. 16, 2012. 15. Vicki Vaughan (16 Feb. 2012). “Fracturing ‘has no direct’ link to water pollution, UT study finds,” retrieved on 3 Mar. 2012. 16. Margaret Munro (17 Feb. 2012). “Fracking does not contaminate groundwater: study released in Vancouver,” retrieved on 3 Mar. 2012. 17. 17.0  17.1  17.2 Fact-Based Regulation for Environmental Protection in Shale Gas Development. Retrieved on 29 Feb. 2012. 18. Mark Scott, “Norway’s Statoil to Acquire Brigham Exploration for $4.4 Billion,” New York Times, Oct. 17, 2011. 19. Barry Harrell (19 Sept. 2011), “Norway-based energy company, UT agree on $5 million research program,” retrieved on 5 Mar. 2012. 20. As Part of BLM Fossil Fuel Auction Protest, Author Terry Tempest Williams Buys Parcels, Great Old Broads, Feb. 16, 2016. 21. Brian Maffly, Auction of Utah oil & gas leases spurs author Terry Tempest Williams to (legally) buy lease, The Salt Lake Tribune, Feb. 16, 2016.

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22. Stefanie Penn Spear,  Obama Administration Greenlights Disastrous Gas Development Project in Pristine Wilderness, EcoWatch, Mar. 16, 2012. 23. Jana Richman, “Fracking in Utah’s Escalante canyons?”  High Country News, Dec. 4, 2013.

Vermont On April 12, 2012, the Vermont Senate Natural Resources and Energy Committee voted unanimously for a bill that would ban hydraulic fracturing for natural gas in the state, as well as prohibit collection, storage, or treatment of fracking wastewater in the state. The bill needed to be reconciled with the House before becoming law.[1] On May 4, 2012, the Vermont House of Representatives voted 103-36 in favor of banning hydraulic fracturing.[2] The ban was signed into law on May 17, 2012, making Vermont the first state in the nation to ban fracking.[3] Citizen groups Vermont Natural Resource Council

References 1. Carl Etnier, “Vermont Senate committee passes ban on fracking,” VT Digger, Apr. 12, 2012. 2. Vermont first state in nation to ban fracking for oil and gas VT Digger, May 4, 2012. 3. Vt. becomes 1st state to ban hydraulic fracturing, Associated Press, May 17, 2012.

Virginia Texas-based energy company Shore Exploration and Production Corp plans to frack for oil and gas by 2015 in Virginia’s Taylorsville basin, a geological formation running through parts of the Northern Neck and Middle Peninsula.[1] As of September 2013, the U.S. Forest Service is debating whether to restrict horizontal drilling in Virginia’s portion of the George Washington National Forest.[2]

Fracking in the USA 703 A 2012 U.S. Geological Survey assessment released in June 2012 suggests there could be more than 1 trillion cubic feet of natural gas in the Taylorsville basin, a geological formation running through parts of the Northern Neck and Middle Peninsula. The Taylorsville basin dates back about 210 million years to the Mesozoic Era. It’s among several basins extending from offshore, through Virginia’s Coastal Plain, west to the Appalachian Mountains.[1] In the 1980s, Texas-based energy company Shore Exploration and Production Corp partnered with Exxon and Texaco to drill 15 exploratory wells in the Bason by 1989.[1] Since 2011 and after the advent of fracking, Shore has been securing leases from landowners for mineral rights on more than 80,000 acres in King George, Westmoreland, Caroline, Essex, and King and Queen counties. Shore plans to begin drilling for gas and oil before 2015. Any drilling in the Taylorsville basin would first require state review and permits, and would have added scrutiny because the work would be first of its type along Virginia’s coast, according to the Virginia Gas and Oil Board. Since the work would be in the Chesapeake Bay watershed, an environmental assessment would also be required. Shore said they expect to receive the permits to drill.[1] Taylorsville Basin It’s been reported that “geologists say the Taylorsville Basin, which stretches from east of Richmond up through Prince George’s County (Maryland), could hold up to 1 trillion cubic feet of natural gas. A Dallas energy company plans to tap into that basin by drilling on tens of thousands of leased acres south and east of Fredericksburg. Some local officials have expressed concerns about some of the chemicals used in fracking being injected into an area near the Chesapeake Bay.”[3] Offshore Drilling In January 2014, 300 residents of Kure Beach, North Carolina protested Mayor Dean Lambeth’s decision to sign a letter, written by America’s Energy Forum part of the American Petroleum Institute, supporting seismic testing for future offshore oil and gas drilling. The seismic testing is part of a plan to open an area 50 miles off the East Coast from Virginia to Georgia to oil and gas drilling by 2022. [4] Citizen activism Legislative issues and regulations

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George Washington National Forest As of September 2013, a proposal to restrict horizontal drilling in the George Washington National Forest is being debated by the U.S. Forest Service. A natural gas deposit - an extension of the  Marcellus Shale  - is believed to underlie approximately half of the national forest, much of it in Virginia. The headwaters within it contribute to the drinking water of at least 30 communities from Washington to Richmond, Virginia, according to the Forest Service.[5] The Forest Service, part of the U.S. Department of Agriculture, proposed drilling limits in 2011 to protect water supplies. The Environmental Protection Agency and the National Park Service also supported the prohibition on horizontal drilling. However, the Forest Service is now reconsidering after gas companies said the ban was unwarranted and would set a bad precedent. The Forest Service is expected to issue a new decision by November 2013.[6] In November 2014, it was announced that a compromise was reached, in which oil and gas drilling would be allowed in the areas in the George Washington National Forest that are privately controlled. The deal means that 90% of land in the George Washington National Forest will be off limits to fracking. The New York Times reported, “The plan will allow drilling on 10,000 acres in the forest now leased for energy development and on 167,000 acres whose mineral rights are privately owned. Currently, there are no active gas wells in the forest or in surrounding private tracts.”[7] Land leases It was reported in October 2013 that Texas energy company Shore Exploration and Production Corp., based in Dallas, which leased tens of thousands of acres east of Fredericksburg, Virginia was planning to begin fracking for gas and oil within 18 months. Since 2011, the company has been securing leases from landowners for mineral rights on more than 80,000 acres in King George, Westmoreland, Caroline, Essex and King and Queen counties.[8]

References 1.

1.0 1.1 1.2 1.3

       Rusty Dennen and Cathy Dyson, Drilling for oil, gas planned east of Fredericksburg, Fredericksburg.com, Oct. 12, 2013. 2. Mark Drajem, “Fracking Limits for Virginia Forest Spark Debate on Water,” Bloomberg, Sept. 5, 2013.

Fracking in the USA 705 3. Environmentalists urge Va. to begin crafting fracking rules, WTOP, Dec. 5, 2014. 4. NC town called ‹ground zero› in offshore drilling fight shows political cost of backing Big Oil over local jobs, Facing South, Jan. 2016. 5. Mark Drajem, “Fracking Limits for Virginia Forest Spark Debate on Water,” Bloomberg, Sept. 5, 2013. 6. Jessica Goad,  The Oil And Gas Industry Wants To Start Fracking At The Source Of D.C.’s Water Supply, Climate Progress, Oct 21, 2013. 7. Trip Gabriel, “In Compromise Plan, Limited Fracking Is Approved for National Forest in Virginia,” New York Times, Nov. 18, 2014. 8. Rusty Dennen and Cathy Dyson, “Drilling for oil, gas planned east of Fredericksburg,”  Fredericksburg.com, Oct. 12, 2013.

Washington In June 2012, Comet Ridge Ltd., Brisbane, said its US subsidiaries plan to spud an exploratory well in the Grays Harbor area of coastal Washington state in late June to drill for gas. The site of the Yeti well is 22 miles east of an abandoned Ocean City oil field, and 50 miles northwest of Jackson Prairie gas storage field in Lewis County.[1] Geothermal A large tract of federal land in the Cascades could be the site of geothermal development. In Washington, geothermal hot spots appear to be surrounding volcanoes like Rainier and Baker. Geothermal projects inject some chemicals into the ground along with pressurized water that will break open cracks in underground rock.[2]

References 1. Alan Petzet, Washington Grays Harbor exploratory well to spud, Oil & Gas Journal, Jun. 13, 2012. 2. NW Forestland Could Be Leased For Geothermal Development,  Jefferson Public Radio, Apr. 12, 2015.

West Virginia This map to the right shows the number of Marcellus Shale permits granted by county in West Virginia from 2006 - 2011.

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Photo courtesy of FracTracker

Data released by DrillingInfo in late 2015 reported that permits issued for the Marcellus region was 68 in October, down from 76 in September 2015. Additionally, there were 160 permits issued in June 2015. At the same period in 2010, during the fracking boom in the region, 600 permits were issued a month. The steady decrease in global oil prices was said to be responsible for the decline in the number of fracking permits.[1] Environmental and health impacts

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Wastewater In February 2011, the New York Times reported that a never-released study by the EPA and a confidential study by the drilling industry concluded that radioactivity in drilling waste cannot be fully diluted in rivers and other waterways, yet federal and state regulators are allowing most sewage treatment plants that accept drilling waste not to test for radioactivity. In West Virginia, a plant in Wheeling discharged gas-drilling wastewater into the Ohio River. Pennsylvania has sent some of its fracking waste to West Virginia for disposal.[2] The New York Times also reported “a 1987  report  to Congress by the Environmental Protection Agency that deals with waste from the exploration, development and production of oil, natural gas and geothermal energy ... states that hydraulic fracturing, also called fracking, can cause groundwater contamination. It cites as an example a case in which hydraulic fracturing fluids contaminated a water well in West Virginia. The report also describes the difficulties that sealed court settlements created for investigators. The report concluded that hydraulic fracturing fluids or gel used by Kaiser Exploration and Mining Company contaminated a well roughly 600 feet away on the property of James Parsons in Jackson County, West Virginia. The report contradicts prior statements by the oil and gas industry that there had never been a documented case of contamination, helping the industry avoid federal regulations.[3] A study released in January 2015 in Environmental Science & Technology, authored by Avner Vengosh and Gary Dwyer of Duke University, found that high levels of two potentially hazardous contaminants, ammonium and iodide, were being discharged or spilled into streams and rivers from oil and gas operations in Pennsylvania and West Virginia. The authors found that the levels of contamination were as high in fracking wastewater as those coming from conventional oil and gas wells. “Wastewater from both conventional and unconventional oil and gas operations is exempted from the Clean Water Act, which allows their disposal to the environment. This practice is clearly damaging the environment and increases the health risks of people living in these areas, and thus should be stopped,” Vengosh said.[4]

Wastewater Pits As reported in The Columbus Dispatch, fracking wastewater impoundment lots as big as football fields already dot heavily fracked landscapes in

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Pennsylvania and West Virginia. The impoundments store millions of gallons of water with fracking chemicals, toxic metals, and radium that come up from shale wells. Companies clean the water of pollutants so it can be recycled to frack new wells.[5] In Pennsylvania, wastewater must be removed within nine months of competed drilling at a site, according to the DEP. The state has permits for 23 such lagoons.[5] A West Virginia University study of 15 waste and freshwater lagoons in that state found that eight were built to contain more water than permitted, or had structural problems that threatened leaks.[5]

Wastewater and Landfills A new state rule passed quietly in 2013 specifies that landfills can accept unlimited amounts of solid waste from horizontal gas drilling, carving out an exception to a decades-old state law that limited landfills’ intake to only 10,000 or 30,000 tons a month (depending on their classification). The drilling waste is a sludgy mix of dirt, water, sand, and chemicals dredged up in the drilling process.[6] In 2013, West Virginia landfills accepted 721,000 tons of drilling waste.[7]

Wastewater Reuse Almost one-half of flowback fluid recovered in West Virginia is transported out of state. Between 2010 and 2012, 22% of recovered flowback fluid was sent to Pennsylvania, primarily to be reused in other Marcellus operations, and 21% was sent to Ohio, primarily for disposal via underground injection control wells.[8]

Water Use The volume of water removed from the hydrologic cycle per unit of gas produced in West Virginia wells ranges from 1.6 to 2.2 gallons per thousand cubic feet. Gas producers in West Virginia used an average of 5 million gallons of fresh water for each well, according to publicly available numbers for 2010-2012.[8] A 2015 Stanford study found that West Virginia, Arkansas, Louisiana, and  Pennsylvania  had the highest average water use per each  hydraulic fracturing job.[9]

Fracking in the USA 709

Water Contamination From 2010-2014, West Virginia had 122 complaints that drilling contaminated water wells in the state. Four of those cases were strong enough to force drillers to take corrective action.[10] A January 2015 Environmental Science & Technology study reported that two hazardous chemicals associated with fracking—ammonium and iodide—were being released and spilled into Pennsylvania and West Virginia waterways. The chemicals could have devastating impacts on the environment and wildlife, the study noted. The fracking related chemicals were “making their way into streams and rivers, both accidentally and through deliberate release from treatment plants that were never designed to handle these contaminants.” Both of these chemicals are not currently regulated in oil and gas wastewater.[11] Drilling permits In 2009, 426 Marcellus wells were permitted and 125 were drilled in West Virginia. The following year, 433 were permitted and 58 drilled in the state.[12]

Fracking under Ohio River In December 2014, state officials in West Virginia announced they would permit fracking under the Ohio River. Critics contended that fracking near a freshwater supply like the Ohio River could contaminate drinking water supplies for thousands of people.[13] Citizen activism

2012 In September 2012, environmental groups in West Virginia called for a moratorium on new drilling for natural gas in the state citing environmental concerns. The groups, including Sierra Club and the Ohio Valley Environmental Coalition, called for the ban at a state capitol press conference in Charleston. The groups made a similar plea one year earlier.[14] Lawsuits In April 2013, a judge recognized that a company could be trespassing on one’s property by hydraulic fracturing. In West Virginia, U.S. District

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Judge John Preston Bailey denied a motion summary judgment filed by oil and gas producer defendants Chesapeake Appalachia, LLC, Statoil USA Onshore Properties, Inc. and Jamestown Resources, Inc. It was reported that in the case, “Chesapeake Appalachia drilled a horizontal Marcellus Shale well with a vertical well bore within 200 feet of the plaintiffs’ property and a horizontal well bore within “tens of feet” of the plaintiffs’ property. Although Chesapeake Appalachia maintains a lease for the oil and gas underlying the plaintiffs’ property, plaintiffs’ lease does not authorize pooling or unitization of the Marcellus formation.”[15] Legislative issues and regulations On March 1, 2012, the Department of Justice said it was investigating possible environmental violations by Chesapeake Energy at three of its well sites in West Virginia, including possible criminal violations and other liabilities under the Clean Water Act’s prohibition against the filling or damming of wetlands, rivers, and streams without a federal permit. Penalties under the Clean Water Act could be as high as $37,500 per day, per violation. Criminal penalties could range from $2,500 to $25,000 per day, per misdemeanor, and between $5,000 and $50,000 per day for a felony. Chesapeake’s March 1, 2012 filing with the  Securities and Exchange Commission stated that the West Virginia Department of Environmental Protection had issued orders for compliance related to alleged violations of the state›s Dam Control and Safety Act at four structures constructed for Chesapeake.[16] U.S. federal regulators fined Chesapeake Energy Corp $3.2 million to settle the company’s Clean Water Act violations in West Virginia, issued on December 19, 2013. Chesapeake will also pay an estimated $6.5 million to restore streams and wetlands.[17] According to a 2015 NRDC report West Virginia has less than 40 inspectors for 56,814 active wells.[18] Citizen groups SkyTruth West Virginia Citizen Action Group West Virginia Surface Owners’ Rights Organization Wetzel County Action Group Ohio Valley Environmental Coalition Liberty and Justice West Virginia West Virginia Rivers Coalition WV Host Farms Program Reports

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2015 Bacteria Creates Methane in Well Some of the natural gas harvested by  hydraulic fracturing  operations may be of biological origin, but created by microorganisms inadvertently injected underground into shale by drillers during fracking.[19] Ohio State University and West Virginia University scientists tested fluids taken from a well operated by Northeast Natural Energy in West Virginia. They measured the genes, enzymes and chemical isotopes in used fracturing fluid drawn from the well for more than a year. Bacteria eat the fracking fluid and produce new chemicals, which other bacteria eat. Those bacteria then produce other chemicals, and then again other bacteria eat. The last metabolic step ends with a species of archaea producing methane. Researchers have long known about the microbes present inside hydraulic fracturing wells and drillers inject commercially available biocides to keep microbes from clogging the equipment. Where the bacteria came from was unknown. The biocides kill some types of bacteria, thereby enabling other bacteria and archaea to prosper. These survive in water that can be four times saltier than the ocean, and under pressures that are typically hundreds of times higher than on the surface of the earth. These microorganisms adapt by eating chemicals found in the fracking fluid and producing methane. Northeast Natural Energy drilling manager claimed shale rock is packed so tight he was not sure much could be living there.[20] The research found that pores inside shale may give microorganisms room to grow and access food. This is the first detailed genomic analysis of bacteria and archaea microbes living in deep fractured shales.[21]

2015 Fracking May Lead Decline Visitation in Public Park According to a study by researchers from the University of Florida, North Carolina State University, and Florida State University in August 2015,  hydraulic fracturing  in, or near public park lands could prompt tourists to stay away. The study of 225 park users in Pennsylvania, Ohio, West Virginia, Kentucky, and Tennessee found more than a third say they would be unwilling to participate in recreational activities near hydraulic fracturing. Fifty eight percent of the study’s participants claim they would support legislation prohibiting fracking near their favorite park.[22]

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2013 report on wastewater Evan Hansen, Dustin Mulvaney, and Meghan Betcher, “Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania,” Downstream Strategies and Earthworks, Oct 30, 2013.

2012 study compares West Virginia vs. Wyoming Coal and Gas Tax Rate The 2012 West Virginia Center for Budget Policy report,  “Major Tax Responsibilities of Coal and Natural Gas Producers in Wyoming and West Virginia,” compared the coal and natural gas state tax policies of Wyoming and West Virginia in 2008 and found that: Wyoming collected approximately $2.1 billion in taxes from coal and natural gas producers, compared to $787 million in West Virginia. Wyoming’s average effective tax rate on coal producers was 10.6 percent, compared to 6.5 percent in West Virginia. The average effective tax rate on natural gas producers was 10.2 percent in Wyoming and 8.2 percent in West Virginia. The average property tax rate for coal and natural producers in Wyoming was 4.8 percent for each industry, while the average property tax rate for natural gas was three percent and one percent for coal in West Virginia. If West Virginia replaced its real and personal property tax scheme with Wyoming’s county groups production tax, it would have raised an additional $115 million in 2008. Resources

References 1. Gas Slump Hits America›s Biggest Fracking Field, Reuters, Dec. 2, 2015. 2. Ian Urbina,  Regulation Lax as Gas Wells’ Tainted Water Hits Rivers,  New York Times, Feb. 26, 2011. 3. Ian Urbina, A Tainted Water Well, and Concern There May Be More, New York Times, Aug. 3, 2011. 4. New Contaminants Found In Oil And Gas Wastewater, Duke Environment, Jan. 14, 2015.

Fracking in the USA 713 5. 6. 7. 8.

9.

10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22.

5.0 5.1 5.2

      Spencer Hunt,  Big lagoons could hold Ohio fracking waste,  The Columbus Dispatch, Oct 11, 2013. Fracking waste fills WV landfills under new rule, Associated Press, Dec. 7, 2013. Alex Nussbaum, “Radioactive Waste Booms With Fracking as New Rules Mulled,” Bloomberg, Aug. 16, 2014. 8.0 8.1    Evan Hansen, Dustin Mulvaney, and Meghan Betcher, Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania, Downstream Strategies and Earthworks, Oct 30, 2013. Evan Hansen, Dustin Mulvaney, and Meghan Betcher,  The Depths of Hydraulic Fracturing and Accompanying Water Use Across the United States, Environmental Science & Technology, Jul. 2015. Water in at least three U.S. states is polluted from FRACKING as hundreds of complaints are reported across the country, Associated Press, Jan. 6, 2014. Marianne Lavelle, “Fracking Brings Ammonium and Iodide to Local Waterways,” Scientific American, Jan. 14, 2015. What is Fracking? FrackCheckWV, accessed Aug. 5, 2015. Laura Arenschield, “W.Va. OKs fracking under Ohio River; critics leery,” The Columbus Dispatch, Dec. 8, 2014 West Virginia Gas Drilling Opponents Call For Halt To New Development, Huffington Post, Sept. 11, 2012. West Virginia judge recognizes trespass by hydraulic fracturing ACC, Apr. 23, 2013. Chesapeake Energy facing DOJ investigation, Associated Press, Mar. 1, 2012. Nick Snow, Chesapeake Appalachia settles federal water pollution charges, Oil & Gas Journal, Dec. 19, 2013. Amy Mall, Fracking›s Most Wanted: Lifting the Veil on Oil and Gas Company Spills and Violations, NDRC, Apr. 2015. Pam Frost Gorder, “Some gas produced by hydraulic fracturing comes from surprise source,” Phys.org, Dec. 14, 2015. Sean Cockerham, “Could deep-Earth microbes help us frack for oil?” Mcclatchy Washington Bureau, Phys.org, Aug. 3, 2015. Pam Frost Gorder, “Some gas produced by hydraulic fracturing comes from surprise source,” Phys.org, Dec. 14, 2015. Tim Kellison, “Fracking may lead to decline in visitation in public parks,”  UF News, Aug. 27, 2015.

Wisconsin In 2009, a sand rush started in Wisconsin, to provide the silica particles used in the  hydraulic fracturing  process. Much of Wisconsin›s sand is considered the ideal shape and strength by the oil and gas industry, and the state›s geologic profile has made it more accessible than in other parts of the country.[1]

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According to The Capital Times, frac sand is a $1 billion industry in Wisconsin, and the state’s frac sand is used in oil and gas operations across the globe.[2] Mining firms can get $50[3] to $200 a ton for the sand.[4] Sandland According to PR Watch, sand mining corporations have expanded operations in Wisconsin, “taking advantage of the lax regulations of non-metallic mining in the state ... Wisconsin communities have been caught off-guard as corporations have swooped in to set up shop and begin extracting and processing the sand, without very much oversight to protect the health of neighbors or to protect the natural environment ... Regions of Wisconsin and Minnesota where frac sand mining have already started have seen complaints about air quality, water degradation, and the destruction of the natural landscape.”[5] Mining for frac sand in Wisconsin took off in 2009. In May 2012, E&E News reported 60 frac sand mines operating in Wisconsin,[6]  with PR Watch reporting about 40 more attempting to gain permits.[7] In July 2012, E&E News said Wisconsin had doubled its frac sand industry since 2011, with 87 mines operating or under construction, and another 20 in the proposal stage.[8] It was reported in October 2013 that Wisconsin’s sand-mining boom could help fuel fracking abroad, noting that the sand used in fracking is found in great quantities in the state.[9] Citizen activism Much of the state is unzoned and sand mining companies can therefore negotiate directly with property owners on licenses, at terms later seen by many residents as unfavorable to them economically and carrying unknown environmental and health risks.[10] In December 2011, Wisconsin’s Farmers’ Union and its Towns Association organized a day-long conference to help people deal more effectively with the sand mining industry. According to TomDispatch: “[T] owns, alarmed by the explosion of frac-sand mining, were beginning to pass licensing ordinances to regulate the industry. In Wisconsin, counties can challenge zoning but not licensing ordinances, which fall under town police powers. These, according to Wisconsin law, cannot be overruled by counties or the state. Becky Glass, a Prairie Farm resident and an organizer with Labor Network for Sustainability, calls Wisconsin’s town police powers ‘the strongest tools towns have to fight or regulate frac-sand mining.’”[10] In April 2012, the town of Prairie Farm voted 2 to 1 to pass an ordinance to regulate any future mining effort in the town. Mining company Procore of multinational oil and gas corporation Sanjel pulled out the area because

Fracking in the USA 715 of the resistance, but has since returned with different personnel to try opening new mines in the area.[10] Regulations The state Department of Natural Resources issues permits for wastewater and stormwater disposals, but there are no regulations regarding air pollution from the dust drifting off sand trains heading to oil and gas fields. According to The Baltimore Examiner, sand mining companies seem to be targeting townships and unincorporated communities because they lack zoning rules that could contain sand mines.[11] In 2011, some Wisconsin residents filed petitions with the state government to impose new air standards in response to concerns about increased silica dust emissions. The Wisconsin Department of Natural Resources rejected the petition, saying that existing state regulations addressed the residents’ health concerns, but regulators said in a 2011 report that a lack of data on emissions has stymied a conclusive finding on the health effects of sand mining.[12]

Reclamation When companies apply to counties for mining permits, including sand, they must file “reclamation” plans. But there are reports that lands inevitable lose much of their biodiversity and fertility.[13] Legislative issues In March 2012, the Wisconsin state Senate considered legislation (SB 504) aimed at “limiting the authority” of Wisconsin cities, villages or towns to enact a “development moratorium ordinance” -- a mechanism used by several local governments across the state to delay mining until they can investigate the effects on their community. A moratorium gives citizens and local elected officials time to discuss adopting ordinances, like zoning or licensing, but cannot be used to permanently or indefinitely delay the creation or expansion of a frac sand mining operation. The Wisconsin Realtors Association and the Wisconsin Builder’s Association are reportedly behind the push for the passage of the bill, to prevent what they consider unnecessary moratoriums in the state. Dane County, the League of Wisconsin Municipalities and the Wisconsin Farmer’s Union have lobbied against the bill. The bill sets several hurdles for local governments in enacting a moratorium, including obtaining a written report from a certified engineer or health professional which would “prove” that a moratorium is

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“essential” in addressing public infrastructure or safety concerns. Sen. and ALEC member Frank Lasee (R-DePere) introduced the bill.[14] Environmental and health issues Sand dust created from hydraulic fracturing has been found to be a threat to health. About four out of five air samples from well sites in five states from 2010 to 2011 exceeded recommended limits for silica particles, according to industrial hygienist Eric Esswein at the National Institute for Occupational Safety and Health. The particles in sand dust created during fracking can lodge in the lungs and cause potentially fatal silicosis, and “there’s really no inherent protection” at well sites, according to Esswein.[15] Frack Sand The rise of hydraulic fracturing to enhance oil and natural gas production also boosted the demand for sand to prop open shale formations. The rise of hydraulic fracturing to enhance oil and natural gas production also boosted the demand for sand to prop open shale formations. The fall of oil prices in 2015 has prompted layoffs in several frac sand companies. Pennsylvania based Preferred Sands, which owns frac sand plants in Wisconsin and Nebraska did a number of lay-offs in fall of 2015.[16] Companies Canadian Sand and Proppant EOG Resources Procore Unimin

References 1. Sara Jerving, Wisconsin Legislation May Strip Towns of Authority to Stop Fracking, PR Watch, Mar. 14, 2012. 2. Mike Ivey, Wisconsin at ‹global epicenter› of frac sand mining industry, The Capital Times, Oct. 10, 2013. 3. MINING: Fracking fuels sand boom in the Midwest, E&E News, May 15, 2012. 4. Doug Hissom, Sand mining coming to a town near you, Post-Examiner, May 13, 2012. 5. Sara Jerving, Wisconsin Legislation May Strip Towns of Authority to Stop Fracking, PR Watch, Mar. 14, 2012. 6. MINING: Fracking fuels sand boom in the Midwest, E&E News, May 15, 2012.

Fracking in the USA 717 7. Sara Jerving, Wisconsin Legislation May Strip Towns of Authority to Stop Fracking, PR Watch, Mar. 14, 2012. 8. [Wis. doubles size of its frac sand industry,] E&E Publishing, Jul. 25, 2012. 9. John Upton,  Wisconsin’s sand-mining boom could fuel fracking abroad, Grist, Oct. 14, 2013. 10. 10.0  10.1  10.2  Ellen Cantarow,  Tomgram: Ellen Cantarow, The New EcoDevastation in Rural America, TomDispatch, May 20, 2012. 11. Doug Hissom, Sand mining coming to a town near you, Post-Examiner, May 13, 2012. 12. MINING: Fracking fuels sand boom in the Midwest, E&E News, May 15, 2012. 13. Ellen Cantarow, Tomgram: Ellen Cantarow, The New Eco-Devastation in Rural America, TomDispatch, May 20, 2012. 14. Sara Jerving, Wisconsin Legislation May Strip Towns of Authority to Stop Fracking, PR Watch, Mar. 14, 2012. 15. Alex Wayne,  Fracking Sand Threatens Gas Well Workers, Researcher Says, Bloomberg, Apr. 30, 2012. 16. Cole Epley, “Sand industry — including Nebraska plant — feels the pain as oil prices drop,” World-Herald, Oct. 23, 2015.

Wyoming Natural gas, coal and oil have created a ten-year long economic boom in Wyoming that has resulted in doubling the state’s budget. However, as natural gas prices drop, so does the state’s revenue.[1] Fracking, growing  coalbed methane  production, and the build-out of Rocky Mountain pipeline capacity helped Wyoming gas production grow from 1.84 BCF/day in 1995 to 6.4 BCF/day by 2009. In 2007, Wyoming produced a record-setting 436.3 billion standard feet of gas. Since the 2009 peak, however, gas production fell by more than 10% by mid-2012.[2] The Atlantic Rim in south-central Wyoming supports nearly 500 natural gas wells,[3] and Wyoming is proposing approximately 21,000 new wells at the same time natural gas prices are still declining. With the completion of the Wyoming-to-Oregon Ruby Pipeline this summer, Wyoming will have more export capacity than production. Coalbed methane (CBM) is natural gas found in coal beds.[4] The Powder River Basin accounts for nearly all CBM produced in the state. More than 26,000 CBM wells have been drilled in the PRB, and it has produced 4.73 TCF since commercial development began in 1997. The PRB is the second largest producer of CBM in the U.S., after the San Juan Basin in New Mexico.[5] Citizen activism

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Opposition to Leasing In Protected Forest Oil-lease rush The potential of oil production in the niobrara formation has set off a scramble for mineral leases along the front range, with more than 8,100 leases filed in six counties in the 12 months ending. 30.

Location of gas leases in the Niobrara formation in Wyoming and Colorado.

Fracking in the USA 719 Too Special to Drill The Noble Basin sits in the shadow of the Wyoming Range, most of which was protected from energy development by Congress in 2009, but previous leases bought by energy companies can still be developed, including one proposal for 136 wells to be drilled by Plains Exploration and Production (PXP). In 2012 the Citizens for the Wyoming Range were opposing PXP’s plans to drill 136 natural gas wells in the upper Hoback Basin, south of Jackson. Called the Eagle Prospect and Noble Basin Master Development Plan (MDP), it could be developed in a pristine area of the Bridger-Teton National Forest with 29 miles of new or graded roads and 17 well pads. The group is concerned about impacts on wildlife and local biodiversity. In 2011, the U.S. Forest Service released a draft of its environmental analysis of the proposed project, recommending against leasing of 44,720 acres for natural gas exploration.[6] As of 2012, the U.S. Forest Service is conducting a final environmental review of the project. If officials decide that tighter restrictions on drilling near existing roads apply, it’s possible that the PXP leases would be less valuable and could be bought out by those who want the Noble Basin preserved in its current wild state.[7]

Groups Sue Over Fracking Fluids In March 2012, environmental groups sued the Wyoming Oil and Gas Conservation Commission, stating that the agency has not done enough to justify honoring requests by companies to keep the public from reviewing ingredients in hydraulic fracturing fluids. The groups included Powder River Basin Resource Council, Wyoming Outdoor Council, Earthworks and OMB Watch. The groups alleged the commission denied their state open records requests to review fracking fluid ingredients. Laura Veaton of Earth Justice, who represents the groups, said that nearly all of the company requests to withhold trade secrets had been granted (50 out of 52 requests). Veaton said some were granted even though some companies did not comply with state requirements.[8][9] Legislative issues and regulations

Disclosure of Chemicals Fracking: Lessons from Wyoming.

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The Wyoming Oil and Gas Conservation Commission (WOGCC) requires disclosure of the types and amounts of chemicals used in the state’s fracking operations. Natural gas operators must submit data to the WOGCC prior to stimulation. The WOGCC catalogs the data while maintaining the confidentiality of any proprietary information. The WOGCC also restricts the use of diesel and volatile organic compounds (VOCs) in hydraulic fracturing. Finally, the WOGCC requires a poststimulation report, which must include information about the fracking conducted, including the amount of fluids used and several well parameters.[10] However, the disclosure measure allows trade secret exemptions meant to protect companies from being forced to reveal proprietary information. In 2010 and 2011, the state granted 50 chemical secrecy requests by oil and gas service companies, including  Halliburton, Weatherford International, and NALCO. Environmental groups discovered the information was being shielded from disclosure after seeking access to records on hydraulic fracturing chemicals used in the state; WOGCC provided some of the requested information in January 2012, but refused to turn over any chemical formulations that had been designated as “trade secrets.”[11] In March 2012, community groups mounted a legal challenge against the Wyoming regulators, saying they were improperly approving oil and gas companies’ “overly broad,” “boilerplate requests” to shield information about the chemicals used.[12] The outcome of the lawsuit could have implications for similar measures in other states, as Wyoming’s chemical disclosure requirement has been used as a model for other states.[11] On March 25, 2013, the Natrona County District sided with the state of  Wyoming, saying the lists of the fracking chemicals used are trade secrets that may be withheld from the public under Wyoming’s open records law.[13]

Regulators In June 2012, it was reported that the Petroleum Association of Wyoming was spending up to hundreds of thousands of dollars to pay federal regulators’ wages and overtime in an effort to speedup the permitting process for new wells, as permit requests have more than doubled from about 100 to nearly 250 at the Bureau of Land Management’s field office in Casper, which is short-staffed.[14]

Fracking in the USA 721 In January 2013, State Sen. Floyd Esquibel, a Democrat from Cheyenne, introduced a bill, Senate File 157, which would require initial groundwater sampling before drilling begins. The Sen. said he wants to avoid a situation like what is playing out in Pavillion, Wyo., where the EPA has found pollutants used in fracking chemicals in local water supplies.[15] In September 2014, Wyoming Oil and Gas Conservation Commission proposed setting a minimum of “500 feet between occupied buildings and vertical rigs and 750 feet for horizontal rigs -- up from 350 feet for both.” The proposal came in response to the public concern over increasing oil production near communities.[16]

Wyoming Draft Regulations for Drilling On Jun. 13, 2013, Wyoming Governor Matt Mead unveiled draft regulations that would establish a groundwater testing program for oil and gas operations in the state. It’s been reported that these draft rules, if accepted, would require oil and gas operators to conduct tests establishing the quality of groundwater around sites before drilling begins and to follow up later with tests to monitor for potential impacts. The proposed regulations were met with applause by Environmental Defense Fund.[17]

Regulatory Violations In 2012, the Wyoming Department of Environmental Quality recorded 204 oil and gas production spills, and pursued water quality fines against 10 producers.[18] Citizen groups Citizens for the Wyoming Range Powder River Basin Resource Council Industry groups Petroleum Association of Wyoming Environmental impacts

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EPA Finds Fracking Chemical in Pavillion In November 2011, the EPA released raw data that indicated groundwater supplies in Pavillion, Wyoming contained high-levels of cancer causing compounds and at least one chemical commonly used in hydraulic fracturing -- 2-butoxyethanol (2-BE). The findings were consistent with water samples the EPA collected from at least 42 homes in the area since 2008. This is the first time that the federal agency has drawn these conclusions. “Gasland” Director Josh Fox was arrested while trying to film a House Science Committee hearing on the EPA’s investigation of this possible water contamination in Pavillion.[19][20][21]  The EPA concluded that contamination from “constituents associated with hydraulic fracturing” is in the “drinking water aquifer,” around 800 feet down.[22] The EPA is to release a comprehensive study about the effects of “fracking” on water resources, initial results are not expected until late 2012. The study is currently continuing.[23][24] Later, Wyoming Governor Matt Mead disputed the EPA’s findings, stating, “Somewhere along the line EPA seems to have abandoned a reasonable approach in favor of an effort resulting in a delay of further sampling and information development until the completion of the peer review process. This seems entirely backward.”[25] A report by Earthworks Oil and Gas Accountability Project stated that four out of five people who returned a health survey reported symptoms that could be linked to Natural Gas Drilling operations in and around Pavillion, Wyoming. In the past, residents of the central Wyoming town have reported that fracking polluted their well water.[26] In May 2012, the EPA’s initial findings in Pavillion were validated by an independent expert.[27] On April 30, 2012, independent hydrologist Tom Myers submitted his review of the EPA’s draft report, stating, “It is clear that hydraulic fracturing has caused pollution of the Wind River formation and aquifer.” Myers was commissioned by the NRDC, the Wyoming Outdoor Council, Sierra Club, and the Oil and Gas Accountability Project. It was reported by the Associated Press in May 2012 that Wyoming’s governor persuaded the head of the EPA to postpone an announcement linking fracking to groundwater contamination, giving state officials — whom the EPA had privately briefed on the study — time to change the finding in the Pavillion, Wyoming area.[28] E&E News noted that while the finding challenges the industry talking point that fracturing has never contaminated groundwater, the fracking done in Pavillion was much closer to the surface and groundwater than the fracking in deeper shale formations like Pennsylvania’s Marcellus. The EPA report will be subject to peer-review and “if EPA’s findings are accurate,

Fracking in the USA 723 they point to some very basic problems in Pavillion. Oil and gas operators dumped their waste into unlined pits, which was legal at the time. They also did not seal their wells off from drinking water by encasing them in concrete all the way through the drinking water zone, a basic drilling practice laid out in the American Petroleum Institute’s standards,” according to E&E News.[29] In October 2012, the American Petroleum Institute criticized the EPA’s study at Pavillion, stating the agency used too small a sample size to determine whether fracking contributed to groundwater contamination. The group also said that the EPA’s study could have far-reaching implications for they conduct their national study on that issue.[30] In 2016, Stanford University scientist, Rob Jackson, cited the Pavillion case where the EPA found that shallow hydraulic fracturing had released natural gas and other toxic compounds into freshwater aquifers. At Pavillion, they were fracking less than 1,000 feet deep, while people were getting drinking water at 750 feet, Jackson said to Phys.org. Contamination is more likely to occur when there isn›t enough separation between the hydraulic fracturing activity and the drinking-water sources.[31]

USGS also Finds Contamination After Wyoming state officials criticized the EPA’s conclusions on contamination in Pavillion, the EPA agreed to retest the wells, and call in the U.S. Geological Survey (USGS) to conduct parallel tests. The USGS 2012 retest of one Pavillion, Wyoming well found evidence of many of the same gases and compounds the EPA found in 2011 - methane, ethane, diesel compounds, and phenol. The USGS provided the raw data of its retest but no interpretation, although a spokeswoman for the EPA said that the results are consistent with the agency’s findings, and a later analysis by Sierra Club, Earthworks, and the Natural Resources Defense Council confirmed the EPA and USGS results. If the EPA’s own retest and final report hold the initial findings, driller Encana could be forced to address the homeowners’ water complaints. The company is still making periodic water deliveries to about 20 area households, who have been advised not to cook or drink our water,” according to local farmer John Fenton.[32]

EPA Cedes Pavillion Study to State In June 2013, the EPA dropped plans to have outside experts review its draft report suggesting fracking played a role in groundwater pollution in Pavillion, and the agency no longer plans to write a final report

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on its research. Instead, the EPA said state officials would lead further investigation into pollution in the Pavillion area, including ways to make sure people there have clean drinking water. The state will issue a final report in late 2014.[33] The EPA also dropped its investigations into water contamination from shale gas drilling in Dimock, PA, and Parker County, TX.[34] It was reported in October 2013 that a top Obama aide Heather Zichal, worked the Pavillion fracking investigation. Zichal took a significant interest in the community’s water supply in late 2011 and early 2012. As it was reported, “Documents show that Zichal, deputy assistant to the president for energy and climate change, monitored and managed developments behind the scenes as U.S. EPA prepared to release its findings that hydraulic fracturing had contaminated groundwater in Pavillion. Emails obtained by Energywire through the Freedom of Information Act show that Zichal got briefings from top EPA officials as they prepared to release the report, was informed the afternoon before the report was rolled out in December 2011 and sought to manage the fallout when it came under criticism. ‘Can we get some talking points on this asap?’ Zichal wrote to then-Deputy EPA Administrator Bob Perciasepe on January 3, 2012, above a news story on flaws in EPA’s handling of the sampling process. The FOIA documents also show that Zichal emailed with then-EPA Administrator Lisa Jackson on the Pavillion investigation. Jackson herself showed considerable interest in the case, sending nearly 100 emails involving Pavillion between November 2010 and April 2011, including a few from her personal email account.”[35]

Ground-Level Ozone In March 2011, it was reported that as a result of natural gas drilling operations, ozone levels in the western part of Wyoming were far exceeding EPA limits. Preliminary data showed ozone levels reached high as 124 parts per billion, or two-thirds higher than the Environmental Protection Agency’s maximum healthy limit of 75 parts per billion. In 2010, Wyoming’s gasdrilling area had days when its ozone levels exceeded Los Angeles’ worst for 2009.[36][37] In May 2012, Wyoming’s southwestern region was found to have an unsafe level of smog-causing ozone for the first time, a designation the EPA linked to a boom in oil and gas drilling in the state.[38] The U.S. EPA has determined that southwest Wyoming›s per Green River Basin no longer met federal ground-level ozone pollution standards.[39]

Fracking in the USA 725

Water Use The 2013 Western Organization of Resource Councils report,  “Gone for good: Fracking and water loss in the West,” found that fracking is using 7 billion gallons of water a year in four western states: Wyoming, Colorado, Montana, and North Dakota.

Water Contamination Since the 1970s there has been an exemption to allow wastewater from oil and gas operations to be given to livestock in western states and reservations: “In the 1970s, when the Environmental Protection Agency was banning oil companies from dumping their wastewater, ranchers, especially in Wyoming, made a fuss. They argued that their livestock needs water, even dirty water,” according to NPR. “So the EPA made an exception, a loophole, for the arid West. If oil companies demonstrate that ranchers or wildlife use the water, the companies can release it.... [O]ver time, states’ rules have become stricter than the EPA’s. Some states have all but outlawed dumping.”[40] Wastewater for livestock on Native reservations is determined by the EPA on a case-by-case basis. In August 2013, NPR reported that the EPA is proposing to let oil companies continue to dump polluted wastewater on the Wind River Reservation in Wyoming.[41]  The wastewater contains toxic chemicals, including known carcinogens and radioactive material, according to documents obtained by NPR through Freedom of Information Act requests.[40] In 2015, the Environmental Protection Agency renewed permits to dump in Wind River.[42] Accidents

April 2012: Residents Evacuate After Gas Leaks from Wyo. Well On April 25, 2012, an oil well blowout in Wyoming prompted 50 residents to evacuate their homes amid concern that a spewing cloud of natural gas could explode. Gas continued to erupt from the ground after the blowout near the Wyoming town of Douglas. Witnesses told local television station KCWY-TV they could hear the roaring gas from six miles away.[43]

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Reports “A Seven Point Plan to Protect Groundwater: Unconventional Oil & Gas Development Requires Wyoming State Action,” Powder River Basin Resource Council, Jan. 2013. Fracking “Beyond The Law Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” The Environmental Integrity Project. [1] From 2010 to July 2014, drillers in the state of Wyoming reported using 1,310.32 gallons of diesel injected into three wells. The Environmental Integrity Project extensively researched diesel in fracking. The organization argues that diesel use is widely under reported. The Environmental Integrity Project 2014 study “Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing,” found that hydraulic fracturing with diesel fuel can pose a risk to drinking water and human health because diesel contains benzene, toluene, xylene, and other chemicals that have been linked to cancer and other health problems. The Environmental Integrity Project identified numerous fracking fluids with high amounts of diesel, including additives, friction reducers, emulsifiers, and solvents sold by Halliburton.[44]

References 1. Bob Beck, “Natural Gas Prices Plunge, Hurting Wyoming’s Budget,”  NPR, Feb. 13, 2012. 2. Bill Powers, Cold, Hungry and in the Dark, New Society Publishers, 2013. 3. Dustin Bleizeffer, “Wyoming’s next wave of natural gas drilling,” WyoFile, May 17, 2011. 4. Wyoming Coalbed Natural Gas, Wyoming Geological Survey, accessed Oct 2013. 5. Bill Powers, Cold, Hungry and in the Dark, New Society Publishers, 2013. 6. Quick facts about PXP drilling plan for the upper Hoback,  Citizens for Wyoming on the Range, accessed on Mar. 23, 2012. 7. Documentary Short: Natural Gas Drilling Threatens The Wild Heart Of Wyoming’s Bridger-Teton National Forest, Think Progress, Jul. 12, 2012. 8. Mead Gruver,  Wyoming: Environmentalists Sue Over Fracking Fluid, Associated Press, Mar. 27, 2012. 9. Bob Beck, “Conservation Groups Ask Court To Release Fracking Chemical Secrets,” Wyoming Public Media, Mar. 26, 2012.

Fracking in the USA 727 10. Wyoming and Hydraulic Fracturing,  Intermountain Oil and Gas BMP Project, accessed Feb. 15, 2012. 11. 11.0  11.1 Jennifer A. Dlouhy, Environmentalists challenge trade secret protections for hydraulic fracturing, Fuel Fix, Mar. 26, 2012. 12. Environmentalists challenge trade secret protections for hydraulic fracturing, FuelFix, Mar. 26, 2012. 13. Mead Gruver, Judge sides with Wyoming in fracking chemical suit, Associated Press, Mar. 25, 2013. 14. Jeremy Fugleberg, To speed Wyoming drilling, industry pays for federal staff additions, Star-Tribune, Jun. 22, 2012. 15. Bill calls for mandatory groundwater testing before fracking in Wyoming Adam Voge, Star-Tribune, Jan. 23, 2013. 16. Benjamin Starrow, “Wyoming Oil and Gas Conservation Commission proposes increase in drilling setbacks,” Sept. 7, 2014. 17. Bob Downing, “EDF supports Wyoming draft regulations for drilling,”  Jun. 13, 2013. 18. Mike Soraghan, Many mishaps among drillers, but few fines, E&E News, Jul. 15, 2013. 19. Gasland Director Josh Fox Arrested at Congressional Hearing on Natural Gas Fracking, Democracy Now, Feb. 2, 2012. 20. EPA: Fracking may cause groundwater pollution Associated Press, Dec. 8, 2011. 21. Abrahm Lustgarten, “EPA Finds Fracking Chemical in Wyoming Gas Drilling Town’s Aquifer,” ProPublica, Nov. 11, 2011. 22. Mike Soraghan,What EPA really said about Wyo. fracking pollution,  E&E News, Jan. 23, 2012. 23. Pavillion, WY, fracking study to continue Pam Kasey, State Journal, Mar. 9, 2012. 24. Neela Banerjee, “EPA says ‘fracking’ probably contaminated well water in Wyoming,” Los Angeles Times, Dec. 8, 2011. 25. Wyoming governor disputes EPA study on fracking, groundwater,  Platts, Dec. 22, 2011. 26. Residents of Wyoming Fracking Community Report Illnesses,  Water Contamination From Shale, accessed Apr. 6, 2012. 27. Jessica Goad, “Independent Analysis Confirms That Hydraulic Fracturing Caused Drinking Water Contamination In Wyoming” ThinkProgress, May 1, 2012. 28. AP Exclusive: Wyo. got EPA to delay frack finding, Associated Press, May 3, 2012. 29. Mike Soraghan,What EPA really said about Wyo. fracking pollution,  E&E News, Jan. 23, 2012. 30. Zack Coleman, “Oil-and-gas group questions EPA fracking study,” The Hill, Oct. 18, 2012. 31. Does living near an oil or natural gas well affect your drinking water? Phys. org, Feb. 14, 2016.

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32. Mark Drajem, Diesel in Water Near Fracking Confirms EPA Tests Wyoming Disputes, Bloomberg, Sep 27, 2012. 33. Mead Gruver and Ben Neary,  Some Residents Oppose Wyo.-EPA Frack Study Deal, Associated Press, Jun. 20, 2013. 34. Kate Sinding, Why Would EPA Hide Info on Fracking & Water Contamination in Dimock? NRDC, Jul. 28, 2013. 35. Top Obama aide worked the Pavillion fracking investigation Mike Soraghan, E&E News, Sept. 11, 2013. 36. Mead Gruver, “Wyoming’s natural gas boom comes with smog attached,” Associated Press, Mar. 9, 2011. 37. Wyoming›s smog exceeds Los Angeles› due to gas drilling, USA Today, Mar. 9, 2011. 38. Wyoming Area Found With Unsafe Ozone Level As Fracking Booms,  FA Mag, May 1, 2012. 39. Scott Streater, “EPA gives heavily drilled Wyo. area 3 years to improve air quality,” E&E News, May 7, 2012. 40. 40.0  40.1 Elizabeth Shogren, Loophole Lets Toxic Oil Water Flow Over Indian Land, NPR, Nov. 15, 2012. 41. Elizabeth Shogren, EPA Wants To Allow Continued Wastewater Dumping In Wyoming, NPR, Aug. 7, 2013. 42. Elizabeth Shogren, “Environmentalists challenge permits that result in dumping of toxic chemicals on tribal land,” High Country, Apr. 14, 2015. 43. Mead Gruver, “Residents evacuate after gas leaks from Wyo. Well,” Associated Press, Apr. 25, 2012. 44. Fracking Beyond The Law, Despite Industry Denials Investigation Reveals Continued Use of Diesel Fuels in Hydraulic Fracturing, The Environmental Integrity Project, Aug. 13, 2014.

Fracking: Further Investigations into the Environmental Consideration and Operations of Hydraulic Fracturing, 2nd Edition. Michael D. Holloway. © 2018 Scrivener Publishing LLC. Published 2018 by John Wiley & Sons, Inc.

Appendix A Chemicals Used in Fracking

The following is a list of the common chemicals used at a fracking site. One of the problems associated with identifying chemicals is that some chemicals have multiple names. For example, Ethylene Glycol (Antifreeze) is also known by the names Ethylene alcohol; Glycol; Glycol alcohol; Lutrol 9; Macrogol 400 BPC; Monoethylene glycol; Ramp; Tescol; 1,2-Dihydroxyethane; 2-Hydroxyethanol; HOCH2CH2OH; Dihydroxyethane; Ethanediol; Ethylene gycol; Glygen; Athylenglykol; Ethane-1,2-diol; Fridex; M.e.g.; 1,2-Ethandiol; Ucar 17; Dowtherm SR 1; Norkool; Zerex; Aliphatic diol; Ilexan E; Ethane-1,2-diol 1,2-Ethanedio. This multiplicity of names can make a search for chemicals somewhat difficult and frustrating. However, if you search for a chemical by the CAS number, it will return the correct chemical even if the name on the fracturing record does not match. For example, if the fracturing record listed the chemical Hydrogen chloride and one searched for it by name using a chemical search site, you may not get a result. But if a search for CAS # 007647-01-0, it might return Hydrochloric acid, which is another name of Hydrogen chloride. Therefore, by using the CAS number, one can avoid the issue of multiple names for the same chemical. The following are the Safety Data Sheets for the typical chemicals found at a fracing site. 729

CAS

007647-01-0

000111-30-8

012125-02-9

061789-71-1

055566-30-8

007727-54-0

007647-14-5

014452-57-4

001309-48-4

010043-52-4

000067-48-1

000075-57-0

Chemical name

Hydrochloric Acid

Glutaraldehyde

Quaternary Ammonium Chloride

Quaternary Ammonium Chloride

Tetrakis HydroxymethylPhosphonium Sulfate

Ammonium Persulfate

Sodium Chloride

Magnesium Peroxide

Magnesium Oxide

Calcium Chloride

Choline Chloride

Tetramethyl ammonium chloride

Prevents clays from swelling or shifting

Prevents clays from swelling or shifting

Product Stabilizer

Allows a delayed break down the gel 

Allows a delayed break down the gel 

Product Stabilizer

Allows a delayed break down of the gel

Eliminates bacteria in the water that produces corrosive by-products

Eliminates bacteria in the water that produces corrosive by-products

Eliminates bacteria in the water that produces corrosive by-products

Eliminates bacteria in the water that produces corrosive by-products

Helps dissolve minerals and initiate cracks in the rock

Chemical purpose

Clay Stabilizer

Clay Stabilizer

Breaker

Breaker

Breaker

Breaker

Breaker

Biocide

Biocide

Biocide

Biocide

Acid

Product function

730 Appendix A

CAS

007647-14-5

000067-63-0

000067-56-1

000064-18-6

000075-07-0

064741-85-1

064742-47-8

013709-94-9

101033-44-7

001303-96-4

001333-73-9

Chemical name

Sodium Chloride

Isopropanol

Methanol

Formic Acid

Acetaldehyde

Petroleum Distillate

Hydrotreated Light Petroleum Distillate

Potassium Metaborate

Triethanolamine Zirconate

Sodium Tetraborate

Boric Acid

Maintains fluid viscosity as temperature increases

Maintains fluid viscosity as temperature increases

Maintains fluid viscosity as temperature increases

Maintains fluid viscosity as temperature increases

Carrier fluid for borate or zirconate crosslinker

Carrier fluid for borate or zirconate crosslinker

Prevents the corrosion of the pipe

Prevents the corrosion of the pipe

Product stabilizer and / or winterizing agent

Product stabilizer and / or winterizing agent

Prevents clays from swelling or shifting

Chemical purpose

(Continued)

Crosslinker

Crosslinker

Crosslinker

Crosslinker

Crosslinker

Crosslinker

Corrosion Inhibitor

Corrosion Inhibitor

Corrosion Inhibitor

Corrosion Inhibitor

Clay Stabilizer

Product function

Appendix A 731

CAS

113184-20-6

N/A

000107-21-1

000067-56-1

009003-05-8

064741-85-1

064742-47-8

000067-56-1

000107-21-1

009000-30-0

064741-85-1

064742-47-8

Chemical name

Zirconium Complex

Borate Salts

Ethylene Glycol

Methanol

Polyacrylamide

Petroleum Distillate

Hydrotreated Light Petroleum Distillate

Methanol

Ethylene Glycol

Guar Gum

Petroleum Distillate

Hydrotreated Light Petroleum Distillate

Carrier fluid for guar gum in liquid gels

Carrier fluid for guar gum in liquid gels

Thickens the water in order to suspend the sand

Product stabilizer and / or winterizing agent.

Product stabilizer and / or winterizing agent.

Carrier fluid for polyacrylamide friction reducer

Carrier fluid for polyacrylamide friction reducer

“Slicks” the water to minimize friction 

Product stabilizer and / or winterizing agent.

Product stabilizer and / or winterizing agent.

Maintains fluid viscosity as temperature increases

Maintains fluid viscosity as temperature increases

Chemical purpose

Gelling Agent

Gelling Agent

Gelling Agent

Friction Reducer

Friction Reducer

Friction Reducer

Friction Reducer

Friction Reducer

Crosslinker

Crosslinker

Crosslinker

Crosslinker

Product function

732 Appendix A

CAS

000067-56-1

068130-15-4

000107-21-1

000077-92-9

000064-19-7

000068-11-1

006381-77-7

000151-21-3

000067-63-0

000107-21-1

001310-73-2

Chemical name

Methanol

Polysaccharide Blend

Ethylene Glycol

Citric Acid

Acetic Acid

Thioglycolic Acid

Sodium Erythorbate

Lauryl Sulfate

Isopropanol

Ethylene Glycol

Sodium Hydroxide

Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers 

Product stabilizer and / or winterizing agent.

Product stabilizer and / or winterizing agent.

Used to prevent the formation of emulsions in the fracture fluid

Prevents precipitation of metal oxides

Prevents precipitation of metal oxides

Prevents precipitation of metal oxides

Prevents precipitation of metal oxides

Product stabilizer and / or winterizing agent.

Thickens the water in order to suspend the sand

Product stabilizer and / or winterizing agent.

Chemical purpose

(Continued)

pH Adjusting Agent

Non-Emulsifier

Non-Emulsifier

Non-Emulsifier

Iron Control

Iron Control

Iron Control

Iron Control

Gelling Agent

Gelling Agent

Gelling Agent

Product function

Appendix A 733

CAS

001310-58-3

000064-19-7

000497-19-8

000584-08-7

025987-30-8

N/A

N/A

Chemical name

Potassium Hydroxide

Acetic Acid

Sodium Carbonate

Potassium Carbonate

Copolymer of Acrylamide and Sodium Acrylate

Sodium Polycarboxylate

Phosphonic Acid Salt

Prevents scale deposits in the pipe

Prevents scale deposits in the pipe

Prevents scale deposits in the pipe

Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers 

Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers 

Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers 

Adjusts the pH of fluid to maintains the effectiveness of other components, such as crosslinkers 

Chemical purpose

Scale Inhibitor

Scale Inhibitor

Scale Inhibitor

pH Adjusting Agent

pH Adjusting Agent

pH Adjusting Agent

pH Adjusting Agent

Product function

734 Appendix A

CAS

000151-21-3

000064-17-5

000091-20-3

000067-56-1

000067-63-0

000111-76-2

Chemical name

Lauryl Sulfate

Ethanol

Naphthalene

Methanol

Isopropyl Alcohol

2-Butoxyethanol

Product stabilizer

Product stabilizer and / or winterizing agent.

Product stabilizer and / or winterizing agent.

Carrier fluid for the active surfactant ingredients

Product stabilizer and / or winterizing agent.

Used to increase the viscosity of the fracture fluid

Chemical purpose

Surfactant

Surfactant

Surfactant

Surfactant

Surfactant

Surfactant

Product function

Appendix A 735

736

Appendix A

Acetaldehyde Ethyl aldehyde Acetic aldehyde Ethanal Acetylhydride Aldehyde AAD Formula

CH3CHO

Structure H3C

H C O

Description

Highly volatile, colorless liquid with a penetrating, pungent, suffocating odor that is somewhat fruity and quite pleasant in low concentrations.

Uses

Acetaldehyde is used mainly as a chemical intermediate in the production of acetic acid. It is also used to produce many other chemicals. It is used in the manufacture of paraldehyde, metaldehyde, other polymers, plastics, synthetic rubber and resins, cosmetics, perfumes, pesticides and pharmaceuticals; in the silvering of mirrors; in leather tanning; in the hardening of gelatin fibres; as a denaturant for alcohols; in fuel compositions; in glue and casein products; as a preservative for fish and fruit; as a synthetic flavouring agent; as a food additive; in the paper industry; and as a laboratory chemical.

Appendix A Registry numbers and inventories CAS

75-07-0

NIH PubChem CID

177

EC (EINECS/ELINCS)

200-836-8

EC Index Number

605-003-00-6

EC Class

F+; R12, Carc. Cat. 3; R40, Xi; R36/37

RTECS

AB1925000

RTECS class

Tumorigen; Mutagen; Reproductive Effector; Human Data; Primary Irritant

UN (DOT)

1089

Merck

12,37

Beilstein/Gmelin

505984

Beilstein Reference

4-01-00-03094

RCRA

U001

EPA OPP

202300

FEMA

2003

Swiss Giftliste 1

G-1024

Canada DSL/NDSL

DSL

US TSCA

Listed

Austrailia AICS

Listed

New Zealand

Listed

Japan ENCS (MITI)

Listed

Korea ECL

Listed

Philippiens PICCS

Listed

737

738

Appendix A

Properties Formula

C2H4O

Formula mass

44.05

Melting point, C

-123

Boiling point, C

20.1

Vapor pressure, mmHg

965 (25 C)

Vapor density (air=1)

1.52

Saturation Concentration

Extremely high; gas at room temperature.

Odor threshold

Recognition 0.21 ppm

Critical temperature

193

Critical pressure

54.8

Density

0.780 g/cm3 (20 C)

Solubility in water

Miscible

Viscosity

0.2456 cp at 15C

Surface tension

21.2 g/s2 at 20 C

Refractive index

1.3316 (20 C)

Partition coefficient, pKow

-0.16

Thermal expansion

0.0021/K at 20 C

Heat of vaporization

25.7 kJ/mol

Heat of combustion

-1169 kJ/mol

Appendix A

739

Hazards and Protection Storage

Keep away from heat, sparks, and flame. Keep away from sources of ignition. Keep from freezing. Store in a tightly closed container. Keep from contact with oxidizing materials. Keep away from strong acids. Refrigerator/flammables. Keep away from reducing agents. Do not expose to air. After opening, purge container with nitrogen before reclosing. Periodically test for peroxide formation on long-term storage. Addition of water or appropriate reducing materials will lessen peroxide formation. Store under an inert atmosphere.

WHMIS

B2 D2A

Handling

Use only in a well ventilated area. Ground and bond containers when transferring material. Do not breathe dust, vapor, mist, or gas. Do not get in eyes, on skin, or on clothing. Empty containers retain product residue, (liquid and/or vapor), and can be dangerous. Keep container tightly closed. Avoid contact with heat, sparks and flame. Do not ingest or inhale. Handle under an inert atmosphere. Store protected from air. This product may be under pressure; cool before opening. If peroxide formation is suspected, do not open or move container. Do not pressurize, cut, weld, braze, solder, drill, grind, or expose empty containers to heat, sparks or open flames.

Protection

Eyes: Wear appropriate protective eyeglasses or chemical safety goggles as described by OSHA’s eye and face protection regulations in 29 CFR 1910.133 or European Standard EN166. Skin: Wear appropriate protective gloves to prevent skin exposure. Clothing: Wear appropriate protective clothing to minimize contact with skin. (Continued)

740

Appendix A

Hazards and Protection Respirators

Follow the OSHA respirator regulations found in 29CFR 1910.134 or European Standard EN 149. Always use a NIOSH or European Standard EN 149 approved respirator when necessary.

Small spills/leaks

Absorb spill with inert material, (e.g., dry sand or earth), then place into a chemical waste container. Use water spray to dilute spill to a non-flammable mixture. Avoid runoff into storm sewers and ditches which lead to waterways. Use water spray to disperse the gas/vapor. Remove all sources of ignition. Use a sparkproof tool. Place under an inert atmosphere.

Disposal code

7

Stability

Unstable in air. May undergo autopolymerization. Forms explosive peroxides on prolonged storage and exposure to air.

Incompatibilities

Air, acid anhydrides, alcohols, ketones, phenols, ammonia, hydrogen cyanide, hydrogen sulfide, halogens, phosphorus, isocyanates, stong alkalies, amines, cobalt chloride, mercury (II) chlorate, mercury (II) perchlorate, trace metals, acids, acetic acid, sulfuric acid, strong oxidizing agents, strong reducing agents, strong bases, strong acids.

Decomposition

Carbon monoxide, carbon dioxide, methane.

Fire Flash Point, C

–38

Autoignition, C

140

Upper exp. limit, %

57

Lower exp. limit, %

4

Appendix A

741

Fire fighting

Wear a self-contained breathing apparatus in pressure-demand, MSHA/NIOSH (approved or equivalent), and full protective gear. Water runoff can cause environmental damage. Dike and collect water used to fight fire. Use water spray to keep fire-exposed containers cool. Wear appropriate protective clothing to prevent contact with skin and eyes. Wear a selfcontained breathing apparatus (SCBA) to prevent contact with thermal decomposition products. Extremely flammable liquid. Vapor may cause flash fire. Forms peroxides of unknown stability. Containers may explode in the heat of a fire. Will be easily ignited by heat, sparks or flame. Extinguishing media: For small fires, use dry chemical, carbon dioxide, water spray or alcoholresistant foam. For large fires, use water spray, fog, or alcohol-resistant foam. Use water spray to cool fire-exposed containers.

Fire potential

Very flammable, combustion imminent.

Hazards

Vapors are heavier than air and may travel a considerable distance to a source of ignition and flash back.

Combustion products

Produces irritating vapor when heated. Vapors are heavier than air and may travel a considerable distance to a source of ignition and flash back.

NFPA

Health

2

Flammability

4

Reactivity

2

Health Exposure limit(s)

OSHA PEL: TWA 200 ppm (360 mg/m3) NIOSH REL: Ca See Appendix A See Appendix C (Aldehydes) NIOSH IDLH: Potential occupational carcinogen 2000 ppm

(Continued)

742

Appendix A

Health Carcinogen

G-A3, I-2B, N-2, CP65

Poison Class

4

Exposure effects

Prolonged or repeated skin contact may cause dermatitis. Prolonged or repeated eye contact may cause conjunctivitis. May cause cancer according to animal studies. May cause reproductive and fetal effects. Laboratory experiments have resulted in mutagenic effects. Prolonged skin contact may cause erythema and burns.

Ingestion

Harmful if swallowed. May cause gastrointestinal irritation with nausea, vomiting and diarrhea. May cause central nervous system depression.

Inhalation

Causes respiratory tract irritation. May cause narcotic effects in high concentration. Exposure produces central nervous system depression. Vapors may cause dizziness or suffocation. Can produce delayed pulmonary edema. Inhalation of large amounts may cause respiratory stimulation, followed by respiratory depression, convulsions and possible death due to respiratory paralysis. May cause respiratory sensitization.

Skin

May cause skin sensitization, an allergic reaction, which becomes evident upon re-exposure to this material. Causes skin irritation and possible burns.

Eyes

Lachrymator. Causes severe eye irritation and possible burns.

First aid Ingestion

Do NOT induce vomiting. If victim is conscious and alert, give 2-4 cupfuls of milk or water. Never give anything by mouth to an unconscious person. Get medical aid immediately.

Appendix A

743

First aid Inhalation

Get medical aid immediately. Remove from exposure to fresh air immediately. If breathing is difficult, give oxygen. DO NOT use mouth-to-mouth respiration. If breathing has ceased apply artificial respiration using oxygen and a suitable mechanical device such as a bag and a mask.

Skin

Get medical aid immediately. Immediately flush skin with plenty of soap and water for at least 15 minutes while removing contaminated clothing and shoes. Discard contaminated clothing in a manner which limits further exposure. Destroy contaminated shoes.

Eyes

Get medical aid immediately. Do NOT allow victim to rub or keep eyes closed. Extensive irrigation is required (at least 30 minutes).

Transportation UN number

1089

Response guide

129

Hazard class

3.1

Packing Group

I

USCG CHRIS Code

AAD

USCG Compatatibility Group

19 Aldehydes

HS Code

2912 12 00

Std. Transport #

4907210

IMO Pollution Category

C

IMO Gas Code

B

744

Appendix A

OPPT Chemical Fact Sheet EPA 749-F-94-003 CHEMICALS IN THE ENVIRONMENT: ACETALDEHYDE (CAS NO. 75-07-0) prepared by OFFICE OF POLLUTION PREVENTION AND TOXICS U.S. ENVIRONMENTAL PROTECTION AGENCY August 1994 Chemicals can be released to the environment as a result of their manufacture, processing, and use. EPA has developed information summaries on selected chemicals to describe how you might be exposed to these chemicals, how exposure to them might affect you and the environment, what happens to them in the environment, who regulates them, and whom to contact for additional information. EPA is committed to reducing environmental releases of chemicals through source reduction and other practices that reduce creation of pollutants.

WHAT IS ACETALDEHYDE, HOW IS IT USED, AND HOW MIGHT I BE EXPOSED? Acetaldehyde is a colorless, flammable liquid. It occurs naturally in certain foods, such as ripe fruits and coffee, and in cigarette smoke. Green plants produce acetaldehyde as they break down food. It is produced in large amounts (740 million pounds in 1989) by two companies in the United States. US production of acetaldehyde may decline in the near future as Mexico increases its production of the chemical. US demand for acetaldehyde increased slightly from 1987 to 1989, but is likely to remain steady at its current level. The largest users of acetaldehyde are companies that make acetic acid and related chemicals. Companies also use acetaldehyde to make other chemicals such as pyridine, pentaerythritol, and peracetic acid. Exposure to acetaldehyde can occur in the workplace or in the environment following releases to air, water, land, or groundwater. Exposure can also occur when people eat fruit, drink coffee, or smoke cigarettes. Acetaldehyde enters the body when breathed in with contaminated air or when consumed with contaminated food or water. It does not remain

Appendix A

745

in the body due to its breakdown, mainly to a chemical that is normally present in the human body. WHAT HAPPENS TO ACETALDEHYDE IN THE ENVIRONMENT? Acetaldehyde evaporates when exposed to air. It dissolves completely when mixed with water. Most direct releases of acetaldehyde to the environment are to air or to underground sites. It also evaporates from water and soil exposed to air. Once in air, it breaks down to other chemicals. Microorganisms that live in water and in soil can also break down acetaldehyde. Because it is a liquid that does not bind well to soil, acetaldehyde that makes its way into the ground can move through the ground and enter groundwater. Plants and animals are not likely to store acetaldehyde. HOW DOES ACETALDEHYDE AFFECT HUMAN HEALTH AND THE ENVIRONMENT? Effects of acetaldehyde on human health and the environment depend on the amount of acetaldehyde present and the length and frequency of exposure. Effects also depend on the health of a person or the condition of the environment when exposure occurs. Breathing acetaldehyde for short periods of time can irritate the human respiratory system. Acetaldehyde can also adversely affect the cardiovascular system. Contact with acetaldehyde liquid or vapor irritates the skin and the eyes. These effects are not likely to occur at levels of acetaldehyde that are normally found in the environment. Human health effects associated with breathing or otherwise consuming small amounts of acetaldehyde over long periods of time are not known. Limited evidence from animal studies shows that acetaldehyde can adversely affect the developing fetus. Laboratory studies also show that acetaldehyde can severely damage the respiratory tract and cause cancer in animals exposed repeatedly by inhalation. Repeat exposure to acetaldehyde in air may likewise cause cancer in humans. Acetaldehyde by itself is not likely to cause environmental harm at levels normally found in the environment. Acetaldehyde can contribute to the formation of photochemical smog when it reacts with other volatile organic carbon substances in air.

746

Appendix A

CHEMICAL SUMMARY FOR ACETALDEHYDE

EPA 749-F-94-003a

prepared by OFFICE OF POLLUTION PREVENTION AND TOXICS U.S. ENVIRONMENTAL PROTECTION AGENCY August 1994 This summary is based on information retrieved from a systematic search limited to secondary sources (see Appendix A). These sources include online databases, unpublished EPA information, government publications, review documents, and standard reference materials. No attempt has been made to verify information in these databases and secondary sources.

I. CHEMICAL IDENTITY AND PHYSICAL/ CHEMICAL PROPERTIES The chemical identity and physical/chemical properties of acetaldehyde are summarized in Table 1.

II. PRODUCTION, USE, AND TRENDS A.

Production

There are two producers of acetaldehyde in the United States,Eastman and Hoechst Celanese. In 1989, US production of acetaldehyde was estimated

Table 1 Chemical Identity And Chemical/Physical Properties Of Acetaldehyde. Characteristic/property

Data

CAS No.

75-07-0

Common Synonyms acetic

aldehyde; ethanal;

ethyl aldehyde

HSDB 1994

Reference

Appendix A Characteristic/property

Data

Molecular Formula

C2H4O

Chemical Structure

CH3-CHO

Reference

Physical State colorless liquid

Verschueren 1983

Molecular Weight 44.05

Budavari et al. 1989

Melting Point -123.5 C

Budavari et al. 1989

Boiling Point 21 C at 760 mm Hg

Budavari et al. 1989

Water Solubility miscible

Budavari et al. 1989

Density d16/4, 0.788

Budavari et al. 1989

Vapor Density (air = 1)

1.52

KOC

ACGIH 1991 not available

Log KOW

-0.22 (estimated)

CHEMFATE 1994

Vapor Pressure

740 mm Hg @ 20 C

Verschueren 1983

Reactivity

highly reactive; flammable

Budavari et al. 1989; Verschueren 1983

Flash Point

-36 F (-38 C) (closed cup)

Henry’s Law Constant

Budavari et al. 1989

7.89 x 10-5 atm-m3/ mol at 25 C

CHEMFATE 1994

Factor