External Review Draft | EPA/600/R-15/047a | June 2015 | www.epa.gov/hfstudy
United States
Environmental Protection
Agency
Assessment of the Potential
Impacts of Hydraulic Fracturing
or Oil and Gas on Drinking
Water Resources
Office of Research and Development
Washington, D.C.
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DRAFT- DO NOT CITE OR QUOTE EPA/600/R-15/047a
External Review Draft
United States
Environmental Protection WWW.epa.
Agency
Assessment of the Potential Impacts of Hydraulic
Fracturing for Oil and Gas on Drinking Water
Resources
NOTICE
THIS DOCUMENT IS AN EXTERNAL REVIEW DRAFT, for review purposes only. It has not
been formally disseminated by EPA. It does not represent and should not be construed to
represent any Agency determination or policy.
Office of Research and Development
U.S. Environmental Protection Agency
Washington, DC 20460
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Hydraulic Fracturing Drinking Water Assessment
DISCLAIMER
This document is an external review draft. This information is distributed solely for the purpose of
pre-dissemination peer review under applicable information quality guidelines. It has not been
formally disseminated by EPA. It does not represent and should not be construed to represent any
Agency determination or policy. Mention of trade names or commercial products does not
constitute endorsement or recommendation for use.
This document is a draft for review purposes only and does not constitute Agency policy.
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Contents
Contents iii
List of Tables x
List of Figures xii
List of Acronyms/Abbreviations xvi
Preface xx
Authors, Contributors, and Reviewers xxi
Authors xxi
Contributors xxii
Reviewers xxiii
Acknowledgements xxiv
Executive Summary ES-1
What is Hydraulic Fracturing? ES-1
Scope of the Assessment ES-3
Approach ES-5
Proximity of Current Activity and Drinking Water Resources ES-5
Major Findings ES-6
Water Acquisition ES-6
Chemical Mixing ES-10
Well Injection ES-13
Flowback and Produced Water 16
Wastewater Management and Waste Disposal ES-19
Key Data Limitations and Uncertainties ES-22
Limitations in Monitoring Data and Chemical Information ES-22
Other Contributing Limitations ES-23
Conclusions ES-23
References for Executive Summary ES-24
1. Introduction 1-1
1.1. Background 1-1
1.2. Scope 1-1
1.3. Approach 1-6
1.3.1. EPA Hydraulic Fracturing Study Publications 1-6
1.3.2. Literature and Data Search Strategy 1-6
1.3.3. Literature and Data Evaluation Strategy 1-7
1.3.4. Quality Assurance and Peer Review 1-8
1.4. Organization 1-9
1.5. Intended Use 1-11
1.6. References for Chapter 1 1-12
2. Hydraulic Fracturing, Oil and Gas Production, and the U.S. Energy Sector 2-1
2.1. What is Hydraulic Fracturing? 2-1
2.1. Hydraulic Fracturing and the Life of a Well 2-8
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2.1.1. Site and Well Development 2-9
2.1.1. Hydraulic Fracturing 2-12
2.1.2. Fluid Recovery, Management, and Disposal 2-17
2.1.3. Oil and Gas Production 2-18
2.1.4. Site and Well Closure 2-19
2.2. How Widespread is Hydraulic Fracturing? 2-20
2.2.1. Number of Wells Fractured per Year 2-25
2.2.2. Hydraulic Fracturing Rates 2-27
2.3. Trends and Outlook for the Future 2-28
2.3.1. Natural Gas (Including Coalbed Methane) 2-28
2.3.2. Oil 2-31
2.4. Conclusion 2-32
2.5. References for Chapter 2 2-33
3. Drinking Water Resources in the United States 3-1
3.1. Current and Future Drinking Water Resources 3-1
3.2. The Proximity of Drinking Water Resources to Hydraulic Fracturing Activity 3-3
3.3. Conclusion 3-11
3.4. References for Chapter 3 3-12
4. Water Acquisition 4-1
4.1. Introduction 4-1
4.2. Types of Water Used 4-2
4.2.1. Source 4-2
4.2.2. Quality 4-4
4.2.3. Provisioning 4-5
4.3. Water Use Per Well 4-6
4.3.1. Hydraulic Fracturing Water Use in the Life Cycle of Oil and Gas 4-6
4.3.2. National Patterns of Water Use Per Well for Fracturing 4-6
4.3.3 Factors Affecting Water Use Per Well 4-7
4.4. Cumulative Water Use and Consumption 4-8
4.4.1. National and State Scale 4-8
4.4.2. County Scale 4-9
4.5. Potential for Water Use Impacts by State 4-15
4.5.1. Texas 4-17
4.5.2. Colorado and Wyoming 4-28
4.5.3. Pennsylvania, West Virginia, and Ohio 4-32
4.5.4. North Dakota and Montana 4-36
4.5.5. Oklahoma and Kansas 4-39
4.5.6. Arkansas and Louisiana 4-41
4.5.7. Utah, New Mexico, and California 4.44
4.6. Chapter Synthesis 4-47
4.6.1. Major Findings 4-47
4.6.2. Factors Affecting Frequency or Severity of Impacts 4-49
4.6.3. Uncertainties 4-50
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4.6.4. Conclusions 4-51
4.7. References for Chapter 4 4-54
5. Chemical Mixing 5-1
5.1. Introduction 5-1
5.2. Chemical Mixing Process 5-3
5.3. Overview of Hydraulic Fracturing Fluids 5-6
5.3.1. Water-Based Fracturing Fluids 5-11
5.3.2. Alternative Fracturing Fluids 5-11
5.3.3. Proppants 5-13
5.4. Frequency and Volume of Hydraulic Fracturing Chemical Use 5-13
5.4.1. National Frequency of Use of Hydraulic Fracturing Chemicals 5-15
5.4.2. Nationwide Oil versus Gas 5-19
5.4.3. State-by-State Frequency of Use of Hydraulic Fracturing Chemicals 5-19
5.4.4. Volumes of Chemicals Used 5-24
5.5. Chemical Management and Spill Potential 5-28
5.5.1. Storage 5-30
5.5.2. Hoses and Lines 5-34
5.5.3. Blender 5-36
5.5.4. Manifold 5-36
5.5.5. High-Pressure Fracturing Pumps 5-37
5.5.6. Surface Wellhead for Fracture Stimulation 5-39
5.6. Spill Prevention, Containment, and Mitigation 5-41
5.7. Overview of Chemical Spills Data 5-42
5.7.1. EPA Analysis of Spills Associated with Hydraulic Fracturing 5-42
5.7.2. Other Spill Reports 5-47
5.8. Fate and Transport of Chemicals 5-50
5.8.1. Potential Paths 5-52
5.8.2. Physicochemical Properties 5-53
5.8.3. Mobility of Chemicals 5-55
5.8.4. Transformation Processes 5-64
5.8.5. Fate and Transport of Chemical Mixtures 5-64
5.8.6. Site and Environmental Conditions 5-65
5.8.7. Peer-Reviewed Literature on the Fate and Transport of Hydraulic Fracturing Fluid Spills5-66
5.8.8. Potential and Documented Fate and Transport of Documented Spills 5-66
5.9. Trends in Chemicals Use in Hydraulic Fracturing 5-70
5.10. Synthesis 5-71
5.10.1. Summary of Findings 5-71
5.10.2. Factors Affecting the Frequency or Severity of Impacts 5-72
5.10.3. Uncertainties 5-73
5.10.4. Conclusions 5-74
5.11. References for Chapter 5 5-77
6. Well Injection 6-1
6.1. Introduction 6-1
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6.2. Fluid Migration Pathways Within and Along the Production Well 6-3
6.2.1. Overview of Well Construction 6-3
6.2.2. Evidence of the Existence of Fluid Movement Pathways or of Fluid Movement 6-11
6.3. Fluid Migration Associated with Induced Fractures within Subsurface Formations 6-27
6.3.1. Overview of Subsurface Fracture Growth 6-28
6.3.2. Migration of Fluids through Pathways Related to Fractures/Formations 6-31
6.4. Synthesis 6-50
6.4.1. Summary of Findings 6-51
6.4.2. Factors Affecting Frequency and Severity of Impacts 6-53
6.4.3. Uncertainties 6-55
6.4.4. Conclusions 6-57
6.5. References for Chapter 6 6-58
7. Flowback and Produced Water 7-1
7.1. Introduction 7-1
7.1.1. Definitions 7-2
7.1. Volume of Hydraulic Fracturing Flowback and Produced Water 7-2
7.1.1. Flowback of Injected Hydraulic Fracturing Fluid 7-3
7.1.2. Produced Water 7-10
7.2. Flowback and Produced Water Data Sources 7-13
7.3. Background on Formation Characteristics 7-15
7.4. Flowback Composition 7-16
7.4.1. General Characteristics 7-16
7.4.2. Temporal Changes in Flowback Composition 7-16
7.4.3. Total Dissolved Solids Enrichment 7-17
7.4.4. Radionuclide Enrichment 7-18
7.4.5. Leaching and Biotransformation of Naturally Occurring Organic Compounds 7-19
7.5. Produced Water Composition 7-22
7.5.1. Similarity of Produced Water from Conventional and Unconventional Formations 7-22
7.5.2. Variability in Produced Water Composition Among Unconventional Formation Types.7-22
7.5.3. General Water Quality Parameters 7-25
7.5.4. Salinity and Inorganics 7-25
7.5.5. Metals 7-26
7.5.6. Naturally Occurring Radioactive Material (NORM) and Technologically Enhanced Naturally
Occurring Radioactive Material (TENORM) 7-27
7.5.7. Organics 7-28
7.5.8. Reactions within Formations 7-28
7.6. Spatial Trends 7-29
7.7. Spill Impacts on Drinking Water Resources 7-30
7.7.1. Produced Water Management and Spill Potential 7-30
7.7.2. Spills of Hydraulic Fracturing Flowback and Produced Water from Unconventional Oil and Gas
Production 7-31
7.7.3. Case Studies of Potentially Impacted Sites 7-36
7.7.4. Roadway Transport of Produced Water 7-39
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7.7.5. Studies of Environmental Transport of Released Produced Water 7-40
7.7.6. Coalbed Methane 7-41
7.7.7. Transport Properties 7-42
7.8. Synthesis 7-43
7.8.1. Summary of Findings 7-44
7.8.2. Factors Affecting the Frequency or Severity of Impacts 7-44
7.8.3. Uncertainties 7-45
7.8.4. Conclusions 7-46
7.9. References for Chapter 7 7-48
8. Wastewater Treatment and Waste Disposal 8-1
8.1. Introduction 8-1
8.2. Volumes of Hydraulic Fracturing Wastewater 8-2
8.2.1. National Level Estimate 8-4
8.2.2. Regional/State and Formation Level Estimates 8-4
8.2.3. Estimation Methodologies and Challenges 8-9
8.3. Wastewater Characteristics 8-10
8.3.1. Wastewater 8-10
8.3.2. Constituents in Residuals 8-12
8.4. Wastewater Management Practices 8-12
8.4.1. Underground Injection 8-20
8.4.2. Centralized Waste Treatment Facilities 8-23
8.4.3. Water Reuse for Hydraulic Fracturing 8-27
8.4.4. Evaporation 8-31
8.4.5. Publicly Owned Treatment Works 8-33
8.4.6. Other Management Practices and Issues 8-35
8.5. Summary and Analysis of Wastewater Treatment 8-38
8.5.1. Overview of Treatment Processes for Hydraulic Fracturing Wastewater 8-38
8.5.2. Treatment of Hydraulic Fracturing Waste Constituents of Concern 8-38
8.5.3. Design of Treatment Trains for CWTs 8-49
8.6. Potential Impacts on Drinking Water Resources 8-58
8.6.1. Bromide and Chloride 8-59
8.6.2. Radionuclides 8-62
8.6.3. Metals 8-65
8.6.4. Volatile Organic Compounds 8-66
8.6.5. Semi-Volatile Organic Compounds 8-67
8.6.6. Oil and Grease 8-67
8.7. Synthesis 8-67
8.7.1. Summary of Findings 8-68
8.7.2. Factors Affecting the Frequency or Severity of Impacts 8-71
8.7.3. Uncertainties 8-72
8.7.4. Conclusions 8-73
8.8. References for Chapter 8 8-75
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9. Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle
9-1
9.1. Introduction 9-1
9.2. Identification of Chemicals Associated with the Hydraulic Fracturing Water Cycle 9-3
9.2.1. Chemicals Used in Hydraulic Fracturing Fluids 9-4
9.2.2. Chemicals Detected in Flowback and Produced Water 9-4
9.3. Toxicological and Physicochemical Properties of Hydraulic Fracturing Chemicals 9-4
9.3.1. Selection of Toxicity Values: Reference Values (RfVs) and Oral Slope Factors (OSFs) 9-5
9.3.2. Physicochemical Properties 9-7
9.3.3. Summary of Selected Toxicological and Physicochemical Property Data for Hydraulic
Fracturing Chemicals 9-7
9.3.4. Additional Sources of Toxicity Information 9-8
9.4. Hazard Identification of Reported Hydraulic Fracturing Chemicals 9-10
9.4.1. Selection of Additional Chemicals for Hazard Identification 9-11
9.4.2. Hazard Identification Results 9-11
9.5. Hazard Identification and Hazard Evaluation of Selected Subsets of Hydraulic Fracturing Chemicals
9-16
9.5.1. Selection of Chemicals for Hazard Evaluation 9-16
9.5.2. Multi Criteria Decision Analysis (MCDA) Framework for Hazard Evaluation: Integrating
Toxicity, Occurrence, and Physicochemical Data 9-19
9.5.3. Hazard Evaluation Results 9-23
9.5.4. Summary of Chemicals Detected in Multiple Stages of the Hydraulic Fracturing Water Cycle
9-33
9.6. Synthesis 9-35
9.6.1. Summary of Findings 9-35
9.6.2. Factors Affecting the Frequency or Severity of Impacts 9-37
9.6.3. Uncertainties 9-37
9.6.4. Conclusions 9-39
9.7. References for Chapter 9 9-41
9.8. Annex 9-43
9.8.1. Calculation of Physicochemical Property Scores (MCDA Hazard Evaluation) 9-43
9.8.2. Example of MCDA Score Calculation 9-44
10. Synthesis 10-1
10.1. Major Findings 10-1
10.1.1. Water Acquisition (Chapter 4) 10-2
10.1.2. Chemical Mixing (Chapter 5) 10-5
10.1.3. Well Injection (Chapter 6) 10-8
10.1.4. Flowback and Produced Water (Chapter 7) 10-11
10.1.5. Wastewater Management and Waste Disposal (Chapter 8) 10-14
10.2. Key Data Limitations and Uncertainties 10-17
10.2.1. Limitations in monitoring data and chemical information 10-17
10.2.2. Other Contributing Limitations 10-19
10.3. Conclusions 10-19
10.4. Use of the Assessment 10-20
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10.5. References for Chapter 10 10-21
See Separate Supplemental Document for Appendices
Appendix A. Chemicals Identified in Hydraulic Fracturing Fluids and/or Flowback and Produced
Water A-l
Appendix B. Water Acquisition Tables B-l
Appendix C. Chemical Mixing Supplemental Tables and Information C-l
Appendix D. Designing, Constructing, and Testing Wells for Integrity D-l
Appendix E. Flowback and Produced Water Supplemental Tables and Information E-l
Appendix F. Wastewater Treatment and Waste Disposal Supplemental Information F-l
Appendix G. Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing
Water Cycle Supplemental Tables and Information G-l
Appendix H. Description of EPA Hydraulic Fracturing Study Publications Cited in This Assessment
H-l
Appendix I. Unit Conversions 1-1
Appendix J. Glossary J-l
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List of Tables
Table 1-1. Stages of the hydraulic fracturing water cycle have various potential effects on drinking water
resources 1-4
Table 1-2. Criteria developed for the five factors used to evaluate literature and data cited in this assessment.
1-8
Table 1-3. Research questions addressed by this assessment 1-9
Table 4-1. Percentage of injected water volume that comes from reused hydraulic fracturing wastewater in
various states, basins, and plays 4-3
Table 4-2. Annual average hydraulic fracturing water use and consumption in 2011 and 2012 compared to
total annual water use and consumption in 2010, by county 4-11
Table 4-3. Estimated proportions of hydraulic fracturing source water from surface and ground water.4-19
Table 4-4. Brackish water use as a percentage of total hydraulic fracturing water use in Texas' main hydraulic
fracturing areas, 2011 4-20
Table 5-1. Examples of common additives, their function, and the most frequently used chemicals reported to
FracFocus for these additives 5-9
Table 5-2. Chemicals reported to FracFocus 1.0 from January 1, 2011 to February 28, 2013 in 10% or more
disclosures, with the percent of disclosures for which each chemical is reported and the top four
reported additives for the chemical 5-16
Table 5-3. The percentage of disclosures of the 20 most commonly reported chemical by state, where a
chemical is reported in at least three states 5-21
Table 5-4. Example list of chemicals and volumes used in hydraulic fracturing 5-24
Table 5-5. Examples of typical hydraulic fracturing equipment and their functions 5-29
Table 5-6. Estimations of spill rates 5-49
Table 5-7. Ranking of the 20 most mobile organic chemicals, as determined by the largest log Kov/, with
CASRN, percent of wells where the chemical is reported from January 1,2011 to February 28,
2013 (U.S. EPA, 2015b), and physicochemical properties (log Kov/, solubility, and Henry's Law
constant) as estimated by EPI Suite™ 5-56
Table 5-8. Ranking of the 20 least mobile organic chemicals, as determined by the largest log Kov/, with CASRN,
percent of wells where the chemical is reported from January 1,2011 to February 28, 2013 (U.S.
EPA, 2015b), and physicochemical properties (log Kov/, solubility, and Henry's Law constant) as
estimated by EPI Suite™ 5-59
Table 5-9. The 20 chemicals reported most frequently nationwide for hydraulic fracturing based on reported
FracFocus 1.0 disclosures (U.S. EPA, 2015b), with EPI Suite™ physicochemical parameters where
available, and estimated mean and median volumes of those chemicals, where density was
available 5-62
Table 6-1. Results of studies of PA DEP violations data that examined well failure rates 6-21
Table 6-2. Comparing the approximate depth and thickness of selected U.S. shale gas plays and coalbed
methane basins 6-33
Table 6-3. Modeling parameters and scenarios investigated by Reagan et al. (2015) 6-41
Table 7-1. Data from one company's operations indicating approximate total water use and approximate
produced water volumes within 10 days after completion of wells (Mantell, 2013b) 7-4
Table 7-2. Additional short-, medium-, and long-term produced water estimates 7-5
Table 7-3. Flowback and long-term produced water characteristics for wells in unconventional formations
(U.S. EPA, 2015e) 7-6
Table 7-4. Compiled minimum and maximum concentrations for various geochemical constituents in
unconventional shale gas, tight gas, andCBM produced water (Alley et al., 2011) 7-23
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Table 7-5. Concentration ranges (mg/L) of several classes of naturally occurring organic chemicals in
conventional produced water worldwide (reported in Neff, 2002) 7-28
Table 8-1. Estimated volumes (millions of gallons) of wastewater based on state data for selected years and
numbers of wells producing fluid 8-7
Table 8-2. Hydraulic fracturing wastewater management practices in recent years 8-14
Table 8-3. Distribution of active Class IID wells across the United States 8-21
Table 8-4. Number, by state, of CWT facilities that have accepted or plan to accept wastewater from hydraulic
fracturing activities 8-25
Table 8-5. Estimated percentages of reuse of hydraulic fracturing wastewater 8-29
Table 8-6. Studies of removal efficiencies and influent/effluent data for various processes and facilities.8-40
Table 8-7. Examples of centralized waste treatment facilities 8-51
Table 9-1. Sources of selected toxicityRfVs and OSFs 9-5
Table 9-2. List of the most frequently used chemicals in hydraulic fracturing fluids, with their respective
federal chronic RfVs where available 9-11
Table 9-3. List of the 20 most mobile chemicals used in hydraulic fracturing fluid, with their respective federal
chronic RfVs where available 9-13
Table 9-4. List of the 20 least mobile chemicals used in hydraulic fracturing fluid, with their respective federal
chronic RfVs where available 9-14
Table 9-5. Thresholds used for developing the toxicity score, occurrence score, and physicochemical
properties score in this MCDA framework 9-22
Table 9-6. Toxicological properties of the 37 chemicals used in hydraulic fracturing fluid that were identified
for hazard evaluation and MCDA analysis 9-24
Table 9-7. MCDA results for 37 chemicals used in hydraulic fracturing fluid 9-27
Table 9-8. Toxicological properties of the 23 chemicals detected in flowback and produced water that were
identified for hazard evaluation and MCDA analysis 9-30
Table 9-9. MCDA results for 23 chemicals in hydraulic fracturing flowback and produced water 9-31
Table 9-10. List of the 23 chemicals with federal chronic RfVs identified to be used in hydraulic fracturing
fluids and detected in the flowback/produced water stage of the hydraulic fracturing water cycle.
9-34
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List of Figures
Figure ES-1. Schematic cross-section of general types of oil and gas resources and the orientations of
production wells used in hydraulic fracturing ES-2
Figure ES-2. The stages of the hydraulic fracturing water cycle ES-4
Figure ES-3. Water budgets representative of practices in the Marcellus Shale in the Susquehanna River Basin
in Pennsylvania (a) and the Barnett Shale in Texas (b) ES-8
Figure 1-1. Conceptualized view of the stages of the hydraulic fracturing water cycle 1-3
Figure 2-1. Schematic cross-section of general types of oil and gas resources and the orientations of
production wells used in hydraulic fracturing 2-3
Figure 2-2. Shale gas and oil plays in the lower 48 United States 2-6
Figure 2-3. Tight gas plays in the lower 48 United States 2-7
Figure 2-4. Coalbed methane fields in the lower 48 United States 2-7
Figure 2-5. Generalized timeline and summary of activities that take place during the operational phases of an
oil or gas well site operation in which hydraulic fracturing is used 2-8
Figure 2-6. Pulling drill pipe onto the drilling platform 2-11
Figure 2-7. Sections of surface casing lined up and being prepared for installation at a well site in Colorado.
2-12
Figure 2-8. Hydraulic fracturing operation in Troy, PA 2-13
Figure 2-9. Two wellheads side-by-side being prepared for hydraulic fracturing at a well site in Pennsylvania.
2-14
Figure 2-10. Water tanks (blue, foreground) lined up for hydraulic fracturing at a well site in central
Arkansas 2-16
Figure 2-11. Impoundment on the site of a hydraulic fracturing operation in central Arkansas 2-18
Figure 2-12. Aerial photograph of a well pad and service road in Springville Township, Pennsylvania. 2-21
Figure 2-13. Aerial photograph of hydraulic fracturing activities near Williston, North Dakota 2-21
Figure 2-14. Landsat photo showing hydraulic fracturing well sites near Frierson, Louisiana 2-22
Figure 2-15. Landsat photo showing hydraulic fracturing well sites near Pinedale, Wyoming 2-23
Figure 2-16. Location of horizontal wells that began producing oil or natural gas in 2000,2005, and 2012,
based on data from Drillinglnfo (2014a) 2-24
Figure 2-17. Trends in U.S. oil and gas production 2-29
Figure 2-18. Historic and projected natural gas production by source (trillion cubic feet) 2-29
Figure 2-19. Natural gas prices and oil and gas drilling activity, 2008-2012 2-30
Figure 2-20. (a) Production from U.S. shale gas plays, 2000-2014, in billion cubic feet per day; (b) Production
from U.S. tight oil plays, 2000-2014 2-31
Figure 2-21. U.S. petroleum and other liquid fuels supply by source, past and projected future trends (million
barrels per day) 2-32
Figure 3-1. Geographic variability in drinking water sources for public water systems 3-2
Figure 3-2. Proximity of hydraulically fractured wells relative to populated areas 3-5
Figure 3-3. Temporal trends (2000-2013) in the number and percent of hydraulically fractured wells located
within populated areas 3-6
Figure 3-4. Location and number of public water system (PWS) sources located within 1 mile of a
hydraulically fractured well 3-8
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Figure 3-5. The location of public water system sources within 1 mile of hydraulically fractured wells.. 3-9
Figure 3-6. Co-occurrence of hydraulic fracturing activity and populations supplied by private water systems.
3-10
Figure 4-1. Annual average hydraulic fracturing water use in 2011 and 2012 by county (U.S. EPA, 2015b).4-13
Figure 4-2. (a) Annual average hydraulic fracturing water use in 2011 and 2012 compared to total annual
water use in 2010, by county, expressed as a percentage; (b) Annual average hydraulic fracturing
water consumption in 2011 and 2012 compared to total annual water consumption in 2010, by
county, expressed as a percentage 4-14
Figure 4-3. Locations of wells in the EPA FracFocus project database, with respect to U.S. EIA shale plays and
basins (EIA, 2015; US. EPA, 2015b) 4-17
Figure 4-4. Major U.S. EIA shale plays and basins for Texas (EIA, 2015) 4-18
Figure 4-5. Annual average hydraulic fracturing water use in 2011 and 2012 compared to (a) fresh water
available and (b) total water (fresh, brackish, and wastewater) available, by county, expressed as
a percentage 4-23
Figure 4-6. (a) Estimated annual surface water runoff from the USGS; (b) Reliance on ground water as
indicated by the ratio of ground water pumping to stream flow and pumping 4-25
Figure 4-7. Major U.S. EIA shale plays and basins for Colorado and Wyoming (EIA, 2015) 4-28
Figure 4-8. Major U.S. EIA shale plays and basins for Pennsylvania, West Virginia, and Ohio (EIA, 2015).4-32
Figure 4-9. Major U.S. EIA shale plays and basins for North Dakota and Montana (EIA, 2015b) 4-36
Figure 4-10. Major U.S. EIA shale plays and basins for Oklahoma and Kansas (EIA, 2015) 4-40
Figure 4-11. Major U.S. EIA shale plays and basins for Arkansas and Louisiana (EIA, 2015b) 4-43
Figure 4-12. Major U.S. EIA shale plays and basins for Utah, New Mexico, and California (EIA, 2015). ...4-45
Figure 5-1. Factors governing potential impact to drinking water resources 5-1
Figure 5-2. Hydraulic fracturing site showing equipment used on-site during the chemical mixing process.5-3
Figure 5-3. Overview of a chemical mixing process of the hydraulic fracturing water cycle 5-4
Figure 5-4. Example fracturing fluid decision tree for gas and oil wells 5-8
Figure 5-5. Estimated median volumes for chemicals reported in at least 100 FracFocus disclosures by
February 28, 2013 for use in hydraulic fracturing from January 1, 2011 to February 28, 2013.5-27
Figure 5-6. Typical hydraulic fracturing equipment layout 5-30
Figure 5-7. Metal and high-density polyethylene (HOPE) chemical additive units 5-32
Figure 5-8. A worker adjusts hoses at a hydraulic fracturing site near Mead, Colorado 5-35
Figure 5-9. Manifold (pointed to by the white arrow) 5-37
Figure 5-10. High-pressure pumps on either side of the manifold 5-38
Figure 5-11. Multiple fracture heads 5-39
Figure 5-12. Distribution of the causes of 151 hydraulic fracturing-related spills of chemicals and fracturing
fluid 5-44
Figure 5-13. Percent distribution of sources of 151 hydraulic fracturing-related spills of chemicals or
fracturing fluid 5-45
Figure 5-14. Total volume of fluids spilled for 151 hydraulic fracturing-related spills of chemicals and
fracturing fluid, by spill source 5-46
Figure 5-15. Number of hydraulic fracturing-related spills of chemicals or fracturing fluid that reported
whether an environmental receptor was reached 5-47
Figure 5-16. Fate and transport schematic for a spilled hydraulic fracturing fluid 5-51
Figure 5-17. Histograms of physicochemical properties of chemicals used in the hydraulic fracturing process.
5-54
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Figure 5-18. Histograms of physicochemical properties of confidential chemicals used in the hydraulic
fracturing process 5-55
Figure 5-19. Fate and Transport Spill Example: Case 1 5-67
Figure 5-20. Fate and Transport Spill Example: Case 2 5-68
Figure 5-21. Fate and Transport Spill Example: Case 3 5-69
Figure 6-1. Overview of well construction 6-5
Figure 6-2. The various stresses to which the casing will be exposed 6-7
Figure 6-3. Potential pathways for fluid movement in a cemented wellbore 6-12
Figure 6-4. Hydraulic fracture planes (represented as ovals), with respect to the principal subsurface
compressive stresses: 5V [the vertical stress), SH [the maximum horizontal stress), and Sh (the
minimum horizontal stress) 6-29
Figure 6-5. Conceptualized depiction of potential pathways for fluid movement out of the production zone:
(a) induced fracture overgrowth into over- or underlying formations; (b) induced fractures
intersecting natural fractures; and (c) induced fractures intersecting a transmissive fault. 6-37
Figure 6-6. Induced fractures intersecting an offset well (in a production zone, as shown, or in overlying
formations into which fracture growth may have occurred) 6-43
Figure 6-7. Well communication (a frac hit) via induced fractures intersecting another well or its fracture
network 6-43
Figure 7-1. Fraction of injected hydraulic fracturing fluid recovered from six vertical (top) and eight
horizontal (bottom) wells completed in the Marcellus Shale 7-8
Figure 7-2. Example of flowback and produced water from the Marcellus Shale, illustrating rapid decline in
water production and cumulative return of approximately 30% of the volume of injected fluid.
7-9
Figure 7-3. Percent of injected fluid recovered for Marcellus Shale wells in West Virginia (2010-2012).7-10
Figure 7-4. Barnett Shale monthly water-production percentiles (5th, 30th, 50th, 70th, and 90th) and number of
wells with data (dashed line) 7-12
Figure 7-5. Barnett Shale production data for approximately 72 months 7-12
Figure 7-6. TDS concentrations measured through time for injected fluid (at 0 days), flowback, and produced
water samples from four Marcellus Shale gas wells in three southwestern Pennsylvanian counties.
7-18
Figure 7-7. Total radium and TDS concentrations measured through time for injected (day 0), flowback, and
produced water samples from mutually exclusive Greene County, PA, Marcellus Shale gas wells.
7-19
Figure 7-8. (a) Chloride (Cl) and (b) DOC concentrations measured through time for injected (day 0),
flowback, and produced water samples obtained from three Marcellus Shale gas wells from a
single well pad in Greene County, PA used for hydraulic fracturing 7-21
Figure 7-9. Histograms of physicochemical properties of 86 organic chemicals identified in produced water
(physicochemical properties estimated by EPI Suite™) 7-43
Figure 8-1. Produced and flowback water volumes and produced gas volumes from unconventional wells in
Pennsylvania from July of 2009 through June of 2014 8-3
Figure 8-2. Wastewater quantities in the western United States (billions of gallons per year) 8-5
Figure 8-3. Schematic of wastewater management strategies 8-13
Figure 8-4. Percentages of Marcellus Shale wastewater managed via various practices for (top) the second
half of 2009 and first half of 2010 (total estimated volume of 216 Mgal), and (bottom) 2013 (total
estimated volume of 1.3 billion gallons) 8-18
Figure 8-5. Management of wastewater in Colorado in regions where hydraulic fracturing is being performed.
8-19
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Figure 8-6. Lined evaporation pit in the Battle Creek Field (Montana) 8-32
Figure 8-7. Oil and gas wastewater volumes discharged to POTWs from 2001-2011 in the Marcellus Shale.
8-34
Figure 8-8. Full discharge water process used in the Pinedale Anticline field 8-50
Figure 9-1. Overall representation of the selected RfVs and OSFs, occurrence data, and physicochemical data
available for the 1,173 hydraulic fracturing chemicals identified by the EPA 9-7
Figure 9-2. Fraction of chemicals with at least one data point in each ACToR data class 9-10
Figure 9-3. The two subsets of chemicals selected for hazard evaluation included 37 chemicals used in
hydraulic fracturing fluid, and 23 chemicals detected in flowback or produced water 9-18
Figure 9-4. Overview of the MCDA framework applied to the hazard evaluations 9-20
Figure 10-1. Water budgets representative of practices in the Marcellus Shale in the Susquehanna River Basin
in Pennsylvania (a) and the Barnett Shale in Texas (b) 10-3
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List of Acronyms/Abbreviations
Acronym Definition
2BE 2-butoxyethanol
ACToR Aggregated Computational
Toxicology Resource
database
AMEC AMEC Environment &
Infrastructure, Inc.
ANRC Arkansas Natural Resources
Commission
AO administrative order
AOGC Arkansas Oil and Gas
Commission
API American Petroleum
Institute
ATSDR Agency for Toxic Substance
and Disease Registry
AWWA American Water Works
Association
BLM Bureau of Land Management
BTEX benzene, toluene,
ethylbenzene, and xylenes
CARES Casella Altela Regional
Environmental Services
CASRN chemical abstract services
registration number
CBI confidential business
information
CBM coalbed methane
CCST California Council on Science
and Technology
CDWR Colorado Division of Water
Resources
CFR Code of Federal Regulations
CICAD Concise International
Chemical Assessment
Document
Acronym
CM
COGCC
CWCB
CWT
CWTF
DBNM
DBF
DecaBDE
DfE
DI
DMR
DNR
DO
DOC
DOE
DOGGR
DOJ
DOT
DRO
EERC
EIA
EPA
Definition
chemical mixing
Colorado Oil and Gas
Conservation Commission
Colorado Water
Conservation Board
centralized waste treatment
centralized water treatment
facility
dibromochloronitromethane
disinfection by-products
decabromodipheyl ether
Design for the Environment
Drilling Info, Inc.
Discharge Monitoring Report
Department of Natural
Resources
dissolved oxygen
dissolved organic carbon
U.S. Department of Energy
California Department of
Conservation's Division of
Oil, Gas & Geothermal
Resources
U.S. Department of Justice
U.S. Department of
Transportation
diesel range organics
Energy and Environmental
Research Center, University
of North Dakota
U.S. Energy Information
Administration
U.S. Environmental
Protection Agency
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Acronym Definition
EPAOW U.S. Environmental
Protection Agency's Office of
Water
EPI estimation programs
interface
ERCB Energy Resource
Conservation Board
ERG Eastern Research Group
ESN Environmental Services
Network
FRS fluids recovery services
GES Groundwater &
Environmental Services, Inc.
GNB Government of New
Brunswick
GRO gasoline range organics
GTI Gas Technology Institute
GWPC Ground Water Protection
Council
HBCD hexabromocyclododecane
HOPE high-density polyethylene
HF hydraulic fracturing
HHBP Human Health Benchmarks
for Pesticides
HISA Highly Influential Scientific
Assessment
HUG hydrological unit code
IAEA International Atomic Energy
Agency
IARC International Agency for
Research on Cancer
IOGCC Interstate Oil and Gas
Compact Commission
IPCC Intergovernmental Panel on
Climate Change
IPCS International Programme on
Chemical Safety
Acronym Definition
IRIS Integrated Risk Information
System
IUPAC International Union of Pure
and Applied Chemistry
KWO Kansas Water Office
LOAEL lowest observed adverse
effect level
MCDA multicriteria decision
analysis
MCL maximum contaminant level
MC LG maximum containment level
goal
MCOR Marcellus Center for
Outreach and Research
MIT mechanical integrity test
MRL minimum risk level
MSC Marcellus shale coalition
MT GWIC Montana Ground Water
Information Center
MTBE methyl tert-butyl ether
MVR mechanical vapor
recompression
NAS National Academy of
Sciences
NDDMR North Dakota Department of
Mineral Resources
NDDOH North Dakota Department of
Health
NDSWC North Dakota State Water
Commission
NETL National Energy Technology
Laboratory
NGO non-governmental
organization
NM OCD New Mexico Oil
Conservation Division
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Acronym Definition
NM OSE New Mexico Office of the
State Engineer
NOAEL no observed adverse effect
level
NORM naturally occurring
radioactive material
NPC National Petroleum Council
NPDES National Pollution Discharge
Elimination System
NRC National Resource Council
NTP U.S. National Toxicology
Program
NYSDEC New York State Department
of Environmental
Conservation
O&G oil and gas
ODNR Ohio Department of Natural
Resources
ODNR, Ohio Department of Natural
DMRM Resources, Division of
Mineral Resources
Management
OEPA Ohio Environmental
Protection Agency
ORD Office of Research and
Development
OSF oral slope factor
OSHA Occupational Safety & Health
Administration
OSWER Office of Solid Water and
Emergency Response
OWRB Oklahoma Water Resources
Board
PA DCNR Pennsylvania Department of
Conservation and Natural
Resources
PA DEP Pennsylvania Department of
Environmental Protection
Acronym Definition
PAH polycyclic aromatic
hydrocarbon
PFBC Pennsylvania Fish and Boat
Commission
PDL positive determination letter
PMF Positive Matrix Factorization
POD point-of-departure
POTW publicly owned treatment
work
PPRTV provisional peer-reviewed
toxicity value
QA quality assurance
QAPP quality assurance project
plan
QC quality control
QSAR Quantitative Structure
Activity Relationship
RfD reference dose
RfV reference value
RO reverse osmosis
SAB Science Advisory Board
SAIC Science Applications
International Corporation
SDWA Safe Drinking Water Act
SDWIS safe drinking water
information system
SEECO Southern Electrical
Equipment Company
SGEIS supplemented generic
environmental impact
statement
SHS MSC statewide health standards
for medium-specific
concentrations
SMCL secondary maximum
contaminant level
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Acronym Definition
SPE Society of Petroleum
Engineers
SRB Susquehanna River basin
SRBC Susquehanna River Basin
Commission
STO Statoil
STRONGER State review of oil and
natural gas environmental
regulations
SVOC semi-volatile organic
compounds
SWE Southwestern Energy
TARM TerrAqua Resource
Management
TEA tert-butyl alcohol
TDS total dissolved solids
TENORM technologically enhanced
naturally occurring
radioactive material
THM trihalomethane
TIPRO Texas Independent
Producers and Royalty
Owners Association
TMDL total maximum daily load
TOC total organic carbon
TPH total petroleum
hydrocarbons
TSS total suspended solids
TTHM total trihalomethane
TWDB Texas Water Development
Board
TXRRC Texas Railroad Commission
UCRB Upper Colorado River basin
UIC underground injection
control
UOG unconventional oil and gas
Acronym Definition
USGAO U.S. Government
Accountability Office
USGS U.S. Geological Survey
UWS Universal Well Services
VOC volatile organic compounds
WAWSA Western Area Water Supply
Authority
WFR Well File Review
WHO World Health Organization
WRF Water Research Foundation
WVDEP West Virginia Department of
Environmental Protection
WWTP wastewater treatment plant
WYOGCC Wyoming Oil and Gas
Conservation Commission
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Preface
1 The U.S. Environmental Protection Agency (EPA) is conducting a study of the potential impacts of
2 hydraulic fracturing for oil and gas on drinking water resources. This study was initiated in Fiscal
3 Year 2010 when Congress urged the EPA to examine the relationship between hydraulic fracturing
4 and drinking water resources in the United States. In response, EPA developed a research plan
5 (Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources] that was
6 reviewed by the Agency's Science Advisory Board (SAB) and issued in 2011. A progress report on
7 the study (Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources:
8 Progress Report), detailing the EPA's research approaches and next steps, was released in late 2012
9 and was followed by a consultation with individual experts convened under the auspices of the SAB.
10 The EPA's study includes the development of several research projects, extensive review of the
11 literature and technical input from state, industry, and non-governmental organizations as well as
12 the public and other stakeholders. A series of technical roundtables and in-depth technical
13 workshops were held to help address specific research questions and to inform the work of the
14 study. The study is designed to address research questions posed for each stage of the hydraulic
15 fracturing water cycle:
16 • Water Acquisition: What are the possible impacts of large volume water withdrawals
17 from ground and surface waters on drinking water resources?
18 • Chemical Mixing: What are the possible impacts of surface spills of hydraulic fracturing
19 fluid on or near well pads on drinking water resources?
20 • Well Injection: What are the possible impacts of the injection and fracturing process on
21 drinking water resources?
22 • Flowback and Produced Water: What are the possible impacts of surface spills of flowback
23 and produced water on or near well pads on drinking water resources?
24 • Wastewater Treatment and Waste Disposal: What are the possible impacts of
25 inadequate treatment of hydraulic fracturing wastewaters on drinking water resources?
2 6 This report, Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking
27 Water Resources, includes both the literature review and results from the research projects
28 conducted as part of the EPA's study. It will undergo independent, external peer review in
29 accordance with Agency policy and all of the peer review comments received will be considered in
3 0 the development of the final report.
31 The EPA's study will contribute to the understanding of the potential impacts of hydraulic
3 2 fracturing activities for oil and gas on drinking water resources and the factors that may influence
33 those impacts. The study will help facilitate and inform dialogue among interested stakeholders,
34 including Congress, other Federal agencies, states, tribal government, the international community,
35 industry, non-governmental organizations, academia, and the general public.
This document is a draft for review purposes only and does not constitute Agency policy.
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Authors, Contributors, and Reviewers
Authors
William Bates, USEPA-Office of Water, Washington, DC
Glen Boyd, The Cadmus Group, Inc., Seattle, WA
Susan Burden, USEPA-Office of Research and Development, Washington, DC
Lyle Burgoon, USEPA- Office of Research and Development, Research Triangle Park, NC
Christopher M. Clark, USEPA-Office of Research and Development, Washington, DC
Maryam Cluff, Student Services Contractor to USEPA under contract EP-13-H-000438-Office of
Research and Development, Washington, DC
Rebecca Daiss, USEPA-Office of Research and Development, Washington, DC
Jill Dean, USEPA-Office of Research and Development, Washington, DC
Deniz Inci Demirkanli, The Cadmus Group, Inc., Arlington, VA
Megan M. Fleming, USEPA-Office of Research and Development, Washington, DC
Jeffrey Frithsen, USEPA-Office of Research and Development, Washington, DC
Kenneth Klewicki, The Cadmus Group, Inc., Arlington, VA
Christopher D. Knightes, USEPA-Office of Research and Development, Athens, GA
Sandie Koenig, The Cadmus Group, Inc., Helena, MT
Jonathan Koplos, The Cadmus Group, Inc., Waltham, MA
Stephen D. LeDuc, USEPA-Office of Research and Development, Washington, DC
Claudia Meza-Cuadra, Student Services Contractor to USEPA under contract EP-13-H-000054-Office
of Research and Development, Washington, DC
Brent Ranalli, The Cadmus Group, Inc., Waltham, MA
Caroline E. Ridley, USEPA-Office of Research and Development, Washington, DC
Shari Ring, The Cadmus Group, Inc., Arlington, VA
Alison Singer, Student Services Contractor to USEPA under contract EP-13-H-000474-Office of
Research and Development, Washington, DC
John Stanek, USEPA- Office of Research and Development, Research Triangle Park, NC
M. Jason Todd, USEPA-Office of Research and Development, Washington, DC
Mary Ellen Tuccillo, The Cadmus Group, Inc., Waltham, MA
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Jim Weaver, USEPA-Office of Research and Development, Ada, OK
Anna Weber, The Cadmus Group, Inc., Arlington, VA
Larke Williams, USEPA-Office of Research and Development, Washington, DC
Liabeth Yohannes, Student Services Contractor to USEPA under contract EP-14-H-000455-Office of
Research and Development, Washington, DC
Erin Yost, ORISE Fellow to USEPA under interagency agreement DW8992 2983 with US DOE - Office
of Research and Development, Research Triangle Park, NC
Contributors
Natalie Auer, The Cadmus Group, Inc., Arlington, VA
Kevin Blackwood, Student Services Contractor to USEPA under contract EP-13-C-000133-Office of
Research and Development, Ada, OK
Jeanne Briskin, USEPA-Office of Research and Development, Washington, DC
Rob Dewoskin, USEPA- Office of Research and Development, Research Triangle Park, NC
Linda Hills, The Cadmus Group, Inc., Helena, MT
Christopher Impellitteri, USEPA-Office of Research and Development, Cincinnati, OH
Richard Judson, USEPA- Office of Research and Development, Research Triangle Park, NC
Matt Landis, USEPA- Office of Research and Development, Research Triangle Park, NC
Ralph Ludwig, USEPA-Office of Research and Development, Ada, OK
John Martin, The Cadmus Group, Inc., Waltham, MA
Ashley McElmury, Student Services Contractor to USEPA under contract EP-12-C-000025-Office of
Research and Development, Ada, OK
Gary Norris, USEPA- Office of Research and Development, Research Triangle Park, NC
Kay Pinley, Senior Environmental Employment Program under agreement CQ-835363 with NCCBA,
USEPA-Office of Research and Development, Ada, OK
Susan Sharkey, USEPA-Office of Research and Development, Washington, DC
Sarah Solomon, Student Services Contractor to USEPA under contract EP-D-15-003-Office of
Research and Development, Washington, DC
Holly Wooten, The Cadmus Group, Inc., Arlington, VA
Jie Xu, Student Services Contractor to USEPA under contract EP-13-C-00120-Office of Research and
Development, Ada, OK
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Reviewers
USEPA internal technical reviewers
Lisa Biddle, Office of Water, Washington, DC
Frank Brock, Region 2, New York, NY
Kyle Carey, Office of Water, Washington, DC
Brian D'Amico, Office of Water, Washington, DC
Tim Elkins, Region 5, Chicago, IL
Malcolm Field, Office of Research and Development, Washington, DC
Greg Fritz, Office of Chemical Safety and Pollution Prevention, Washington, DC
Mohamed Hantush, Office of Research and Development, Cincinnati, OH
Jana Harvill, Region 6, Dallas, TX
Charles Hillenbrand, Region 2, New York, NY
Mark W. Howard, Office of Solid Waste and Emergency Response, Washington, DC
Junqi Huang, Office of Research and Development, Ada, OK
Thomas Johnson, Office of Research and Development, Washington, DC
Jeff Jollie, Office of Water, Washington, DC
James Kenney, Office of Enforcement and Compliance Assurance, Washington, DC
Kristin Keteles, Region 8, Denver, CO
Bruce Kobelski, Office of Water, Washington, DC
Stephen Kraemer, Office of Research and Development, Athens, GA
Paul Lewis, Office of Chemical Safety and Pollution Prevention, Washington, DC
Chris Lister, Region 6, Dallas, TX
Barbara Martinez, ORISE Fellow to USEPA- Office of Research and Development, Washington, DC
Damon McElroy, Region 6, Dallas, TX
Keara Moore, Office of Water, Washington, DC
Nathan Mottl, Office of Chemical Safety and Pollution Prevention, Washington, DC
Greg Oberley, Region 8, Denver, CO
Mike Overbay, Region 6, Dallas, TX
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Steve Platt, Region 3, Philadelphia, PA
Dave Rectenwald, Region 3, Philadelphia, PA
Meredith Russell, Office of Water, Washington, DC
Greg Schweer, Office of Chemical Safety and Pollution Prevention, Washington, DC
Steve Souders, Office of Solid Waste and Emergency Response, Washington, DC
Kate Sullivan, Office of Research and Development, Athens, GA
Scott Wilson, Office of Water, Washington, DC
Nathan Wiser, Office of Research and Development, Denver, CO
Acknowledgements
Contract support was provided by The Cadmus Group, Inc. under contract EP-C-08-015.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Executive Summary
Executive Summary
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Hydraulic Fracturing Drinking Water Assessment Executive Summary
Executive Summary
1 Since the early 2000s, oil and natural gas production in the United States has been transformed
2 through technological innovation. Hydraulic fracturing, combined with advanced directional
3 drilling techniques, made it possible to economically extract oil and gas resources previously
4 inaccessible. The resulting surge in production increased domestic energy supplies and brought
5 economic benefits to many areas of the United States.
6 The growth in domestic oil and gas production also raised concerns about potential impacts to
7 human health and the environment, including potential effects on the quality and quantity of
8 drinking water resources. Some residents living close to oil and gas production wells have reported
9 changes in the quality of drinking water and assert that hydraulic fracturing is responsible for these
10 changes. Other concerns include competition for water between hydraulic fracturing activities and
11 other water users, especially in areas of the country experiencing drought, and the disposal of
12 wastewater generated from hydraulic fracturing.
13 The U.S. Congress urged the U.S. Environmental Protection Agency (EPA) to study the relationship
14 between hydraulic fracturing and drinking water. This report synthesizes available scientific
15 literature and data to assess the potential for hydraulic fracturing for oil and gas to change the
16 quality or quantity of drinking water resources, and identifies factors affecting the frequency or
17 severity of any potential changes. This report can be used by federal, tribal, state, and local officials;
18 industry; and the public to better understand and address any vulnerabilities of drinking water
19 resources to hydraulic fracturing activities.
What is Hydraulic Fracturing?
20 Hydraulic fracturing is a stimulation technique used to increase oil and gas production from
21 underground rock formations. Hydraulic fracturing involves the injection of fluids under pressures
22 great enough to fracture the oil- and gas-producing formations. The fluid generally consists of
23 water, chemicals, and proppant (commonly sand). The proppant holds open the newly created
24 fractures after the injection pressure is released. Oil and gas flow through the fractures and up the
25 production well to the surface.
26 Hydraulic fracturing has been used since the late 1940s and, for the first 50 years, was mostly used
27 in vertical wells in conventional formations.l Hydraulic fracturing is still used in these settings, but
28 the process has evolved; technological developments (including horizontal and directional drilling)
29 have led to the use of hydraulic fracturing in unconventional hydrocarbon formations that could not
30 otherwise be profitably produced (see Figure ES-1). These formations include:
1 Conventional formations often allow oil and natural gas to flow to the wellbore without hydraulic fracturing and
typically contain trapped oil and natural gas that migrated from other subsurface locations. Hydraulic fracturing can be
used to enhance oil and gas production from these formations. In unconventional formations, hydraulic fracturing is
needed to extract economical quantities of oil and gas.
This document is a draft for review purposes only and does not constitute Agency policy.
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Executive Summary
1
2
3
4
5
6
7
8
9
10
11
12
Shales. Organic-rich, black shales are the source rocks in which oil and gas form on
geological timescales. Oil and gas are contained in the pore space of the shale. Some shales
contain predominantly gas or oil; many shale formations contain both.
Tight formations. "Tight" formations are relatively low permeability, non-shale,
sedimentary formations that can contain oil and gas. Like in shales, oil and gas are
contained in the pore space of the formation. Tight formations can include sandstones,
siltstone, and carbonates, among others.
Coalbeds. In coalbeds, methane (the primary component of natural gas) is generally
adsorbed to the coal rather than contained in the pore space or structurally trapped in the
formation. Pumping the injected and native water out of the coalbeds after fracturing
serves to depressurize the coal, thereby allowing the methane to desorb and flow into the
well and to the surface.
Figure ES-1. Schematic cross-section of general types of oil and gas resources and the
orientations of production wells used in hydraulic fracturing.
Shown are conceptual illustrations of types of oil and gas wells. A vertical well is producing from a
conventional oil and gas deposit (right). In this case, a gray confining layer serves to "trap" oil (green)
or gas (red). Also shown are wells producing from unconventional formations: a vertical coalbed
methane well (second from right); a horizontal well producing from a shale formation (center); and a
well producing from a tight sand formation (left). Note: Figure not to scale. Modified from USGS
(2002) and Newell (2011).
This document is a draft for review purposes only and does not constitute Agency policy.
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1 The combined use of hydraulic fracturing with horizontal (or more generically, directional) drilling
2 has led to an increase in oil and gas activities in areas of the country with historical oil and gas
3 production, and an expansion of oil and gas activities to new regions of the country.
Scope of the Assessment
4 We defined the scope of this assessment by the following activities involving water that support
5 hydraulic fracturing (i.e., the hydraulic fracturing water cycle; see Figure ES-2):1
6 • Water acquisition: the withdrawal of ground or surface water needed for hydraulic
7 fracturing fluids;
8 • Chemical mixing: the mixing of water, chemicals, and proppant on the well pad to create
9 the hydraulic fracturing fluid;
10 • Well injection: the injection of hydraulic fracturing fluids into the well to fracture the
11 geologic formation;
12 • Flowback and produced water: the return of injected fluid and water produced from the
13 formation (collectively referred to as produced water in this report) to the surface, and
14 subsequent transport for reuse, treatment, or disposal; and
15 • Wastewater treatment and waste disposal: the reuse, treatment and release, or
16 disposal of wastewater generated at the well pad, including produced water.
17 This assessment reviews, analyzes, and synthesizes information relevant to the potential impacts of
18 hydraulic fracturing on drinking water resources at each stage of the hydraulic fracturing water
19 cycle. Impacts are defined as any change in the quality or quantity of drinking water resources.
20 Where possible, we identify the mechanisms responsible or potentially responsible for any impacts.
21 For example, a spill of hydraulic fracturing fluid is a mechanism by which drinking water resources
22 could be impacted.
2 3 Drinking water resources are defined within this report as any body of ground water or surface
24 water that now serves, or in the future could serve, as a source of drinking water for public or
25 private use. This is broader than most federal and state regulatory definitions of drinking water and
26 encompasses both fresh and non-fresh bodies of water. Trends indicate that both types of water
27 bodies are currently being used, and will continue to be used in the future, as sources of drinking
28 water.
29 This assessment focuses on the potential impacts from activities in the hydraulic fracturing water
30 cycle on drinking water resources. We do this so federal, tribal, state, and local officials; industry;
31 and the public can better understand and address any vulnerabilities of drinking water resources to
32 hydraulic fracturing activities. We do not address other concerns raised about hydraulic fracturing
33 specifically or about oil and gas exploration and production activities more generally. Activities that
1 In this assessment, we refer to the "EPA" when referencing other EPA studies. If a conclusion or analysis was done
specifically by the authors of this assessment, we refer to it and its findings in the first person.
This document is a draft for review purposes only and does not constitute Agency policy.
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Executive Summary
1 are not considered include: acquisition and transport of constituents of hydraulic fracturing fluids
2 besides water (e.g., sand mining and chemical production) outside of the stated water cycle; site
3 selection and well pad development; other infrastructure development (e.g., roads, pipelines,
4 compressor stations); site reclamation; and well closure. A summary and evaluation of current or
5 proposed regulations and policies is beyond the scope of this report. Additionally, this report does
6 not discuss the potential impacts of hydraulic fracturing on other water users (e.g., agriculture or
7 industry), other aspects of the environment (e.g., seismicity, air quality, or ecosystems), worker
8 health or safety, or communities. Furthermore, this report is not a human health risk assessment. It
9 does not identify populations that are exposed to chemicals, estimate the extent of exposure, or
10 estimate the incidence of human health impacts.
Well Injection
Chemical Mixing
Flow/back and Produced Water
Wastewater Treatment and Waste Disposa
Water Acquisition
Figure ES-2, The stages of the hydraulic fracturing water cycle.
Shown here is a generalized landscape depicting the activities of the hydraulic fracturing water cycle
and their relationship to each other, as well as their relationship to drinking water resources. Arrows
depict the movement of water and chemicals. Specific activities in the "Wastewater Treatment and
Waste Disposal" inset are (a)underground injection control (UIC) well disposal, (b) wastewater
treatment and reuse, and (c) wastewater treatment and discharge at a centralized waste treatment
(CWT) facility. Note: Figure not to scale.
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Approach
1 This assessment relies on relevant scientific literature and data. Literature evaluated included
2 articles published in science and engineering journals, federal and state government reports, non-
3 governmental organization (NGO) reports, and industry publications. Data sources examined
4 included federal- and state-collected data sets, databases maintained by federal and state
5 government agencies, other publicly-avail able data and information, and data, including
6 confidential and non-confidential business information, submitted by industry to the EPA.: The
7 relevant literature and data complement research conducted by the EPA under its Plan to Study the
8 Potential Impacts of Hydraulic Fracturing on Drinking Water Resources (hereafter referred to as the
9 "Study Plan") and published by scientific journals or as peer-reviewed EPA reports; those articles
10 and reports are cited throughout this assessment The research topic areas and projects described
11 in the Study Plan were designed to meet the data and information needs of this assessment and
12 were developed with substantial expert and public input
Proximity of Current Activity and Drinking Water Resources
13 Thousands of wells are drilled and fractured every year in the United States, with activities
14 concentrated in specific locations. We estimate 25,000-30,000 new wells were drilled and
15 hydraulically fractured annually in the United States between 2011 and 2014. Additional, pre-
16 existing wells (wells more than one year old that may or may not have been hydraulically fractured
17 in the past) were also likely fractured. Hydraulic fracturing took place in at least 25 states between
18 1990 and 2013. The EPA's analysis of disclosures made to FracFocus 1.0 (hereafter "FracFocus")
19 contained wells from 20 of these states.2 Almost half of these wells were in Texas. Colorado was a
20 distant second, while Pennsylvania and North Dakota were third and fourth, respectively. Hydraulic
21 fracturing activities were further localized within the 20 states. Of the approximately 1,500
22 counties or county equivalents in these 20 states, slightly over 400 contained all of the wells
23 disclosed to FracFocus during this time period. In Colorado, over 85% of the hydraulically fractured
24 wells disclosed were located in two counties. The price of gas and oil may cause short term
25 volatility in the number of wells drilled and fractured per year, yet hydraulic fracturing is expected
26 to continue to expand and drive an increase in domestic oil and gas production in coming decades.
27 Hydraulically fractured wells can be located near residences and drinking water resources.
28 Between 2000 and 2013, approximately 9.4 million people lived within one mile of a hydraulically
1 Some information provided to the EPA in response to two separate information requests to service companies and well
operators was claimed as confidential business information.
FracFocus is a publicly accessible website fwww.fracfocus.org) managed by the Ground Water Protection Council and
the Interstate Oil and Gas Compact Commission where oil and gas production well operators may disclose information
voluntarily or pursuant to state requirements about the ingredients used in hydraulic fracturing fluids at individual
wells. The EPA analyzed disclosures from FracFocus 1.0 for over 38,000 oil and gas production wells hydraulically
fractured between January 1,2011 and February 28,2013. A disclosure refers to data submitted for a specific oil and gas
production well for a specific fracture date. Most wells had only one disclosure, but a small number of wells (876 wells)
had multiple disclosures. For the purposes of this Executive Summary, we equate disclosures with wells when discussing
this study.
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1 fractured well. Approximately 6,800 sources of drinking water for public water systems were
2 located within one mile of at least one hydraulically fractured well during the same period. These
3 drinking water sources served more than 8.6 million people year-round in 2013.
4 Although proximity of hydraulic fracturing activities to a drinking water resource is not in of itself
5 sufficient for an impact to occur,, it does increase the potential for impacts. Residents and drinking
6 water resources in areas experiencing hydraulic fracturing activities are most likely to be affected
7 by any potential impacts, should they occur. However, hydraulic fracturing can also affect drinking
8 water resources outside the immediate vicinity of a hydraulically fractured well; a truck carrying
9 wastewater could spill or a release of inadequately treated wastewater could have downstream
10 effects.
Major Findings
11 From our assessment, we conclude there are above and below ground mechanisms by which
12 hydraulic fracturing activities have the potential to impact drinking water resources. These
13 mechanisms include water withdrawals in times of, or in areas with, low water availability; spills of
14 hydraulic fracturing fluids and produced water; fracturing directly into underground drinking
15 water resources; below ground migration of liquids and gases; and inadequate treatment and
16 discharge of wastewater.
17 We did not find evidence that these mechanisms have led to widespread, systemic impacts on
18 drinking water resources in the United States. Of the potential mechanisms identified in this report,
19 we found specific instances where one or more mechanisms led to impacts on drinking water
2 0 resources, including contamination of drinking water wells. The number of identified cases,
21 however, was small compared to the number of hydraulically fractured wells.
22 This finding could reflect a rarity of effects on drinking water resources, but may also be due to
23 other limiting factors. These factors include: insufficient pre- and post-fracturing data on the quality
24 of drinking water resources; the paucity of long-term systematic studies; the presence of other
25 sources of contamination precluding a definitive link between hydraulic fracturing activities and an
26 impact; and the inaccessibility of some information on hydraulic fracturing activities and potential
27 impacts.
28 Below, we provide a synopsis of the assessment's key findings, organized by each stage of the
29 hydraulic fracturing water cycle. We provide answers to the research questions presented in the
30 Study Plan and Chapter 1. While come citations are provided here, individual chapters should be
31 consulted for additional detail and citations.
Water Acquisition
32 Water is a major component of nearly all hydraulic fracturing operations. It typically makes up
33 almost 90% or more of the fluid volume injected into a well, and each hydraulically fractured well
34 requires thousands to millions of gallons of water. Cumulatively, hydraulic fracturing activities in
35 the United States used on average 44 billion gal of water a year in 2011 and 2012, according to the
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1 EPA's analysis of FracFocus disclosures. Although this represents less than 1% of total annual water
2 use and consumption at this scale, water withdrawals could potentially impact the quantity and
3 quality of drinking water resources at more local scales.:
Research Questions: Water Acquisition
• What are the types of water used for hydraulic fracturing?
4 Water for hydraulic fracturing typically comes from surface water, ground water, or reused
5 hydraulic fracturing wastewater. Hydraulic fracturing operations in the eastern United States
6 generally rely on surface water, while operations in the more semi-arid to arid western states
7 generally use mixed supplies of surface and ground water. In the Marcellus Shale in Pennsylvania,
8 for example, most water used for hydraulic fracturing originates from surface water, whereas
9 surface and ground water are used in approximately equal proportions in the Barnett Shale in
10 Texas (see Figure ES-3a,b). In areas that lack available surface water (e.g., western Texas), ground
11 water supplies most of the water needed for hydraulic fracturing.
12 Across the United States, the vast majority of water used in hydraulic fracturing is fresh, although
13 operators also make use of lower-quality water, including reused hydraulic fracturing wastewater.2
14 Based on available data, the median reuse of wastewater as a percentage of injected volumes is 5%
15 nationally, with the percentage varying by location.3 Available data on reuse trends indicate
16 increased reuse of wastewater over time in both Pennsylvania and West Virginia. Reuse as a
17 percentage of injected volumes is lower in other areas, including regions with more water stress,
18 likely because of the availability of disposal wells. For example, reused wastewater is
19 approximately 18% of injected volumes in the Marcellus Shale in Pennsylvania's Susquehanna
20 River Basin, whereas it is approximately 5% in the Barnett Shale in Texas (see Figure ES-3a,b).
1 Water use is water withdrawn from ground- or surface water for a specific purpose, part or all of which may be returned
to the local hydrologic cycle. If no water is returned, water use equals water consumption. Water consumption is water
that is removed from the local hydrologic cycle following its use (e.g., via evaporation, transpiration, incorporation into
products or crops, consumption by humans or livestock) and is therefore unavailable to other water users (Maupin etal..
2014). In the case of hydraulic fracturing, water can be consumed by the loss of injected water to subsurface zones or via
underground disposal of wastewaters, among other means.
2 In this assessment, hydraulic fracturing "wastewater" refers to both produced water and any other water generated as a
hydraulic fracturing site. As used in this assessment, the term "wastewater" is not intended to constitute a term of art for
legal or regulatory purposes.
3 Reused wastewater as a percentage of injected water differs from the percentage of wastewater that is managed through
reuse, as opposed to other wastewater management options. For example, in the Marcellus in Pennsylvania,
approximately 18% of injected water is reused produced water, while approximately 70% of wastewater or more is
managed through reuse (Figure ES-3a).
This document is a draft for review purposes only and does not constitute Agency policy.
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Water Source
Well Wastewater Management
420,000 -1.3 million gal produced
Reuse CWT • UIC disposal well
Most of the injected fluid is retained
in the subsurface: Produced water
volumes over 10 years are
approximately 10-30% of the original
injected fluid volume
I Surf ace Water Reused Water Ground Water
Water Source
Well
Wastewater Management
3.9 - 4.5 million gal produced
Produced
water volumes
overs
years are
approximately
the same as
the original
injected fluid
volume
5%
• Surface Water Reused Water Ground Water
Reuse • UIC disposal well
Figure ES-3. Water budgets representative of practices in the Marcellus Shale in the
Susquehanna River Basin in Pennsylvania (a) and the Barnett Shale in Texas (b).
Pie size and arrow thickness represent the relative volume of water as it flows through the hydraulic
fracturing water cycle. Wastewater going to a centralized waste treatment (CWT) facility may be
either discharged to surface water or reused. Wastewater going to an underground injection control
(UIC) well is disposed of below ground. These examples represent typical water management practices
as depicted for the most recent time period reviewed by this assessment. They do not represent any
specific well. Note: Values for Marcellus Shale are specific to the Susquenhanna River Basin, except for
the produced water volumes. The longest-term measurement available was from the West Virginia
portion of the the Marcellus Shale.
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• How much water is used per well?
1 The national median volume of water used per hydraulically fractured well is approximately 1.5
2 million gal (5.7 million L), according to the EPA's analysis of FracFocus disclosures. This estimate
3 likely represents a wide variety of fractured well types, including vertical wells that generally use
4 much less water per well than horizontal wells. Thus, published estimates for horizontal shale gas
5 wells are typically higher (e.g., approximately 4 million gallons (Vengosh etal.. 2014]]. There is also
6 wide variation within and among states and basins in the median water volumes used per well,
7 from more than 5 million gal (19 million L] in Arkansas, Louisiana and West Virginia to less than 1
8 million gal (3.8 million L] in California, New Mexico, and Utah, among others. This variation results
9 from several factors, including well length, formation geology, and fracturing fluid formulation.
• How might cumulative water withdrawals for hydraulic fracturing affect drinking water
quantity?
10 Cumulatively, hydraulic fracturing uses billions of gallons of water each year at the national and
11 state scales, and even in some counties. As noted above, hydraulic fracturing water use and
12 consumption are generally less than 1% of total annual water use and consumption at these scales.
13 However, there are a few counties in the United States where these percentages are higher. For
14 2011 and 2012, annual hydraulic fracturing water use was 10% or more compared to 2010 total
15 annual water use in 6.5% of counties with FracFocus disclosures analyzed by the EPA, 30% or more
16 in 2.2% of counties, and 50% or more in 1.0% of counties. Consumption estimates followed the
17 same general pattern. In these counties, hydraulic fracturing is a relatively large user and consumer
18 of water.
19 High fracturing water use or consumption alone does not necessarily result in impacts to drinking
20 water resources. Rather, impacts result from the combination of water use or consumption and
21 water availability at local scales. In our survey of published literature, we did not find a case where
22 hydraulic fracturing water use or consumption alone caused a drinking water well or stream to run
23 dry. This could indicate an absence of effects or a lack of documentation in the literature we
24 reviewed. Additionally, water availability is rarely impacted by just one use or factor alone. In
25 Louisiana, for example, the state requested hydraulic fracturing operations switch from ground to
26 surface water, due to concerns that ground water withdrawals for fracturing could, in combination
27 with other uses, adversely affect drinking water supplies.
28 The potential for impacts to drinking water resources from hydraulic fracturing water withdrawals
29 is highest in areas with relatively high fracturing water use and low water availability. Southern
30 and western Texas are two locations where hydraulic fracturing water use, low water availability,
31 drought, and reliance on declining ground water has the potential to affect the quantity of drinking
32 water resources. Any impacts are likely to be realized locally within these areas. In a detailed case
33 study of southern Texas, Scanlonetal. (2014] observed generally adequate water supplies for
34 hydraulic fracturing, except in specific locations. They found excessive drawdown of local ground
35 water in a small proportion (approximately 6% of the area] of the Eagle Ford Shale. They suggested
3 6 water management, particularly a shift towards brackish water use, could minimize potential future
37 impacts to fresh water resources.
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1 The potential for impacts to drinking water quantity due to hydraulic fracturing water use appears
2 to be lower—but not eliminated—in other areas of the United States. Future problems could arise if
3 hydraulic fracturing increases substantially in areas with low water availability, or in times of water
4 shortages. In detailed case studies in western Colorado and northeastern Pennsylvania, the EPA did
5 not find current impacts, but did conclude that streams could be vulnerable to water withdrawals
6 from hydraulic fracturing. In northeast Pennsylvania, water management, such as minimum stream
7 flow requirements, limits the potential for impacts, especially in small streams. In western North
8 Dakota, ground water is limited, but the industry may have sufficient supplies of surface water from
9 the Missouri River system. These location-specific examples emphasize the need to focus on
10 regional and local dynamics when considering potential impacts of hydraulic fracturing water
11 acquisition on drinking water resources.
• What are the possible impacts of water withdrawals for hydraulic fracturing on water quality?
12 Water withdrawals for hydraulic fracturing, similar to all water withdrawals, have the potential to
13 alter the quality of drinking water resources. Ground water withdrawals exceeding natural
14 recharge rates decrease water storage in aquifers, potentially mobilizing contaminants or allowing
15 the infiltration of lower quality water from the land surface or adjacent formations. Withdrawals
16 could also decrease ground water discharge to streams, potentially affecting surface water quality.
17 Areas with large amounts of sustained ground water pumping are most likely to experience
18 impacts, particularly drought-prone regions with limited ground water recharge.
19 Surface water withdrawals also have the potential to affect water quality. Withdrawals may lower
2 0 water levels and alter stream flow, potentially decreasing a stream's capacity to dilute
21 contaminants. Case studies by the EPA show that streams can be vulnerable to changes in water
2 2 quality due to water withdrawals, particularly smaller streams and during periods of low flow.
2 3 Management of the rate and timing of surface water withdrawals has been shown to help mitigate
24 potential impacts of hydraulic fracturing withdrawals on water quality.
Chemical Mixing
25 Hydraulic fracturing fluids are developed to perform specific functions, including: create and
2 6 extend fractures, transport proppant, and place proppant in the fractures. The fluid generally
27 consists of three parts: (1) the base fluid, which is the largest constituent by volume and is typically
28 water; (2) the additives, which can be a single chemical or a mixture of chemicals; and (3) the
29 proppant Additives are chosen to serve a specific purpose (e.g., adjust pH, increase viscosity, limit
30 bacterial growth). Chemicals generally comprise a small percentage (typically 2% or less) of the
31 overall injected fluid volume. Because over one million gallons of fluids are typically injected per
32 well, thousands of gallons of chemicals can be potentially stored on-site and used during hydraulic
3 3 fracturing activities.
34 On-site storage, mixing, and pumping of chemicals and hydraulic fracturing fluids have the potential
35 to result in accidental releases, such as spills or leaks. Potential impacts to drinking water resources
36 from spills of hydraulic fracturing fluids and chemicals depend on the characteristics of the spills,
37 and the fate, transport, and the toxicity of chemicals spilled.
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Research Questions: Chemical Mixing
• What is currently known about the frequency, severity, and causes of spills of hydraulic
fracturing fluids and additives?
1 The frequency of on-site spills from hydraulic fracturing could be estimated for two states, but not
2 for operations nationally or for other areas. Frequency estimates from data and literature ranged
3 from one spill for every 100 wells in Colorado to between approximately 0.4 and 12.2 spills for
4 every 100 wells in Pennsylvania.1 These estimates include spills of hydraulic fracturing fluids and
5 chemicals, and produced water reported in state databases. Available data generally precluded
6 estimates of hydraulic fracturing fluid and/or chemical spill rates separately from estimates of an
7 overall spill frequency. It is unknown whether these spill estimates are representative of national
8 occurrences. If the estimates are representative, the number of spills nationally could range from
9 approximately 100 to 3,700 spills annually, assuming 25,000 to 30,000 new wells are fractured per
10 year.
11 The EPA characterized volumes and causes of hydraulic fracturing-related spills identified from
12 selected state and industry data sources. The spills occurred between January 2006 and April 2012
13 in 11 states and included 151 cases in which fracturing fluids or chemicals spilled on or near a well
14 pad. Due to the methods used for the EPA's characterization of spills, these cases were likely a
15 subset of all fracturing fluid and chemical spills during the study's time period. The reported
16 volume of fracturing fluids or chemicals spilled ranged from 5 gal to more than 19,000 gal (19 to
17 72,000 L), with a median volume of 420 gal (1,600 L) per spill. Spill causes included equipment
18 failure, human error, failure of container integrity, and other causes (e.g., weather and vandalism).
19 The most common cause was equipment failure, specifically blowout preventer failure, corrosion,
20 and failed valves. More than 30% of the 151 fracturing fluid or chemical spills were from fluid
21 storage units (e.g., tanks, totes, and trailers).
• What are the identities and volumes of chemicals used in hydraulic fracturing fluids, and how
might this composition vary at a given site and across the country?
22 In this assessment, we identified a list of 1,076 chemicals used in hydraulic fracturing fluids. This is
23 a cumulative list over multiple wells and years. These chemicals include acids, alcohols, aromatic
24 hydrocarbons, bases, hydrocarbon mixtures, polysaccharides, and surfactants. According to the
25 EPA's analysis of disclosures to FracFocus, the number of unique chemicals per well ranged from 4
26 to 28, with a median of 14 unique chemicals per well.
27 Our analysis indicates that chemical use varies and that no single chemical is used at all well sites
28 across the country, although several chemicals are widely used. Methanol, hydrotreated light
29 petroleum distillates, and hydrochloric acid were reported as used in 65% or more of wells,
30 according to FracFocus disclosures analyzed by the EPA. Only 32 chemicals, excluding water,
31 quartz, and sodium chloride, were used in more than 10% of wells according to the EPA's analysis
1 Spill frequency estimates are for a given number of wells over a given period of time. These are not annual estimates nor
are they for the lifetime of a well.
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1 of FracFocus disclosures. The composition of hydraulic fracturing fluids varies by state, by well, and
2 within the same service company and geologic formation. This variability likely results from several
3 factors, including the geology of the formation, the availability and cost of different chemicals, and
4 operator preference.
5 Estimates from the EPA's database developed from FracFocus suggest median volumes of
6 individual chemicals injected per well ranged from a few gallons to thousands of gallons, with an
7 overall median of 650 gal (2,500 L) per chemical per well. Based on this overall median and
8 assuming 14 unique chemicals are used per well, an estimated 9,100 gal (34,000 L) of chemicals
9 may be injected per well. Given that the number of chemicals per well ranges from 4 to 28, the
10 estimated volume of chemicals injected per well may range from approximately 2,600 to 18,000 gal
11 (9,800 to 69,000 L).
• What are the chemical, physical, and toxicological properties of hydraulic fracturing chemical
additives?
12 Measured or estimated physicochemical properties were obtained for 453 chemicals of the total
13 1,076 chemicals reported in hydraulic fracturing fluids. We could not estimate physicochemical
14 properties for the inorganic chemicals or mixtures. The 453 chemicals have a wide range of
15 physicochemical properties.
16 Properties affecting the likelihood of a spilled chemical reaching and impacting a drinking water
17 resource include mobility, solubility, and volatility. Of the 453 chemicals for which physicochemical
18 properties were available, 18 of the top 20 most mobile ones were reported in the EPA's FracFocus
19 database for 2% or less of wells. Choline chloride and tetrakis (hydroxymethyl) phosphonium were
20 exceptions and were reported in 14% and 11% of wells, respectively. These two chemicals appear
21 to be relatively more common, and, if spilled, would move quickly through the environment with
22 the flow of water. The majority of the 453 chemicals associate strongly with soils and organic
23 materials, suggesting the potential for these chemicals to persist in the environment as long-term
24 contaminants. Many of the 453 chemicals fully dissolve in water, but their aqueous solubility varies
2 5 greatly. Few of the chemicals volatilize, and thus a large proportion of most hydraulic fracturing
2 6 chemicals tend to remain in water.
27 Oral reference values and oral slope factors meeting the criteria used in this assessment were not
28 available for the majority of chemicals used in hydraulic fracturing fluids, representing a significant
29 data gap for hazard identification.l'2 Reference values and oral slope factors are important for
30 understanding the potential human health effects resulting from exposure to a chemical. Chronic
31 oral reference values and/or oral slope factors from selected federal, state, and international
32 sources were available for 90 (8%) of the 1,076 chemicals used in hydraulic fracturing fluids. From
1A reference value is an estimate of an exposure to the human population (including susceptible subgroups) for a given
duration that is likely to be without an appreciable risk of adverse health effects over a lifetime. Reference value is a
generic term not specific to a given route of exposure.
An oral slope factor is an upper-bound, approximating 95% confidence limit, on the increased cancer risk from a lifetime
oral exposure to an agent.
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1 U.S. federal sources alone, chronic oral reference values were available for 73 chemicals (7%) of the
2 1,076 chemicals, and oral slope factors were available for 15 chemicals (1%). Of the 32 chemicals
3 reported as used in at least 10% of wells in the EPA's FracFocus database (excluding water, quartz,
4 and sodium chloride), seven (21%) have a federal chronic oral reference value. Oral reference
5 values and oral slope factors are a key component of the risk assessment process, although
6 comprehensive risk assessments that characterize the health risk associated with exposure to these
7 chemicals are not available.
8 Of the chemicals that had values available, the health endpoints associated with those values
9 include the potential for carcinogenesis, immune system effects, changes in body weight, changes in
10 blood chemistry, cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and
11 developmental toxicity. However, it is important to note that evaluating any potential risk to human
12 populations would require knowledge of the specific chemicals that are present at a particular site,
13 whether or not humans are exposed to those chemicals and, if so, at what levels and for what
14 duration, and the toxicity of the chemicals. Since most chemicals are used infrequently on a
15 nationwide basis, potential exposure is likely to be a local or regional issue, rather than a national
16 issue. Accordingly, consideration of hazards and risks associated with these chemical additives
17 would be most useful on a site-specific basis and is beyond the scope of this assessment.
• If spills occur, how might hydraulic fracturing chemical additives contaminate drinking water
resources?
18 There are several mechanisms by which a spill can potentially contaminate drinking water
19 resources. These include overland flow to nearby surface water, soil contamination and eventual
2 0 transport to surface water, and infiltration and contamination of underlying ground water. Of the
21 151 spills characterized by the EPA, fluids reached surface water in 13 (9% of 151) cases and soil in
22 97 (64%) cases. None of the spills of hydraulic fracturing fluid were reported to have reached
23 ground water. This could be due to an absence of impact; however, it can take several years for
24 spilled fluids to infiltrate soil and leach into ground water. Thus, it may not be immediately
25 apparent whether a spill has reached ground water or not
26 Based on the relative importance of each of these mechanisms, impacts have the potential to occur
27 quickly, be delayed short or long periods, or have a continual effect over time. In Kentucky, for
28 example, a spill impacted a surface water body relatively quickly when hydraulic fracturing fluid
29 entered a creek, significantly reducing the water's pH and increasing its conductivity (Papoulias
30 and Velasco. 2013).
Well Injection
31 Hydraulic fracturing fluids are injected into oil or gas wells under high pressures. The fluids flow
32 through the well (commonly thousands of feet below the surface) into the production zone (i.e., the
33 geologic formation being fractured) where the fluid injection pressures are sufficient to create
34 fractures in the rock.
35 There are two major subsurface mechanisms by which the injection of fluid and the creation and
36 propagation of fractures can lead to contamination of drinking water resources: (1) the unintended
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1 movement of liquids or gases out of the production well or along the outside of the production well
2 into a drinking water resource via deficiencies in the well's casing or cement, and (2) the
3 unintended movement of liquids or gases from the production zone through subsurface geologic
4 formations into a drinking water resource. Combinations of these two mechanisms are also
5 possible.
Research Questions: Well Injection
• How effective are current well construction practices at containing fluids—both liquids and
gases—before, during, and after fracturing?
6 Production wells are constructed to access and convey hydrocarbons from the formations in which
7 they are found to the surface, and to isolate fluid-bearing zones (containing oil, gas, or water) from
8 each other. Typically, multiple casings are emplaced and cemented along the wellbore to protect
9 and isolate the oil and/or natural gas from the formations it must travel through to reach the
10 surface.
11 Below ground drinking water resources are often separated from the production well using casing
12 and cement. Cemented surface casing, in particular, is an important well construction feature for
13 isolating drinking water resources from liquids and gases that may move through the subsurface. A
14 limited risk modeling study of selected injection wells in the Williston Basin in North Dakota
15 suggests that the risk of aquifer contamination from leaks inside the well to the drinking water
16 resource decreases by a factor of approximately one thousand when surface casing extends below
17 the bottom of the drinking water resource [Michie and Koch. 1991]. Most wells used in hydraulic
18 fracturing operations have casing and a layer of cement to protect drinking water resources, but
19 there are exceptions: a survey conducted by the EPA of oil and gas production wells hydraulically
20 fractured by nine oil and gas service companies in 2009 and 2010 estimated that at least 3% of the
21 wells (600 out of 23,000 wells) did not have cement across a portion of the casing installed through
22 the protected ground water resource identified by well operators. The absence of cement does not
23 in and of itself lead to an impact However, it does reduce the overall number of casing and cement
24 barriers fluids must travel through to reach ground water resources.
25 Impacts to drinking water resources from subsurface liquid and gas movement may occur if casing
26 or cement are inadequately designed or constructed, or fail. There are several examples of these
27 occurrences in hydraulically fractured wells that have or may have resulted in impacts to drinking
28 water resources. In one example, an inner string of casing burst during hydraulic fracturing, which
29 resulted in a release of fluids on the land surface and possibly into the aquifer near Killdeer, North
30 Dakota. The EPA found that, based on the data analysis performed for the study, the only potential
31 source consistent with conditions observed in two impacted monitoring wells was the blowout that
32 occurred during hydraulic fracturing (U.S. EPA, 2015)]. In other examples, inadequately cemented
33 casing has contributed to impacts to drinking water resources. In Bainbridge, Ohio, inadequately
34 cemented casing in a hydraulically fractured well contributed to the buildup of natural gas and high
35 pressures along the outside of a production well. This ultimately resulted in movement of natural
36 gas into local drinking water aquifers (Bair etal.. 2010: ODNR. 2008). In the Mamm Creek gas field
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1 in Colorado, inadequate cement placement in a production well allowed methane and benzene to
2 migrate along the production well and through natural faults and fractures to drinking water
3 resources fScience Based Solutions LLC. 2014: Crescent. 2011: COGCC. 20041 These cases illustrate
4 how construction issues, sustained casing pressure, and the presence of natural faults and fractures
5 can work together to create pathways for fluids to migrate toward drinking water resources.
6 Fracturing older wells may also increase the potential for impacts to drinking water resources via
7 movement of gases and liquids from the inside of the production well or along the outside of the
8 production well to ground water resources. The EPA estimated that 6% of 23,000 oil and gas
9 production wells were drilled more than 10 years before being hydraulically fractured in 2009 or
10 2010. Although new wells can be designed to withstand the stresses associated with hydraulic
11 fracturing operations, older wells may not have been built or tested to the same specifications and
12 their reuse for this purpose could be of concern. Moreover, aging and use of the well can contribute
13 to casing degradation, which can be accelerated by exposure to corrosive chemicals, such as
14 hydrogen sulfide, carbonic acid, and brines.
• Can subsurface migration of fluids—both liquids and gases—to drinking water resources
occur, and what local geologic or artificial features might allow this?
15 Physical separation between the production zone and drinking water resources can help protect
16 drinking water. Many hydraulic fracturing operations target deep formations such as the Marcellus
17 Shale or the Haynesville Shale (Louisiana/Texas), where the vertical distance between the base of
18 drinking water resources and the top of the shale formation may be a mile or greater. Numerical
19 modeling and microseismic studies based on a Marcellus Shale-like environment suggest that
20 fractures created during hydraulic fracturing are unlikely to extend upward from these deep
21 formations into shallow drinking water aquifers.
22 Not all hydraulic fracturing is performed in zones that are deep below drinking water resources.
23 For example, operations in the Antrim Shale (Michigan) and the New Albany Shale
24 (Illinois/Indiana/Kentucky) take place at shallower depths (100 to 1,900 ft or 30 to 579 m), with
25 less vertical separation between the formation and drinking water resources. The EPA's survey of
26 oil and gas production wells hydraulically fractured by nine service companies in 2009 and 2010
27 estimated that 20% of 23,000 wells had less than 2,000 ft (610 m) of measured distance between
28 the point of shallowest hydraulic fracturing and the base of the protected ground water resources
29 reported by well operators.
30 There are also places in the subsurface where oil and gas resources and drinking water resources
31 co-exist in the same formation. Evidence indicates that hydraulic fracturing occurs within these
32 formations. This results in the introduction of fracturing fluids into formations that may currently
33 serve, or in the future could serve, as a source of drinking water for public or private use. According
34 to the data examined, the overall frequency of occurrence of this practice appears to be low, with
35 the activity generally concentrated in some areas in the western United States. The practice of
36 injecting fracturing fluids into a formation that also contains a drinking water resource directly
37 affects the quality of that water, since some of the fluid likely remains in the formation following
38 hydraulic fracturing. Hydraulic fracturing in a drinking water resource is a concern in the short-
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1 term (should there be people currently using these zones as a drinking water supply) and the long-
2 term (if drought or other conditions necessitate the future use of these zones for drinking water).
3 Liquid and gas movement from the production zone to underground drinking water resources may
4 also occur via other production wells or injection wells near hydraulic fracturing operations.
5 Fractures created during hydraulic fracturing can intersect nearby wells or their fracture networks,
6 resulting in the flow of fluids into those wells. These well communications, or "frac hits," are more
7 likely to occur if wells are close to each other or on the same well pad. In the Woodford Shale in
8 Oklahoma, the likelihood of well communication was less than 10% between wells more than 4,000
9 ft (1,219 m) apart, but rose to nearly 50% between wells less than 1,000 ft (305 m) apart (Ajani and
10 Kelkar. 2012). If an offset well is not able to withstand the stresses applied during the hydraulic
11 fracturing of a neighboring well, well components may fail, which could result in a release of fluids
12 at the surface from the offset well. The EPA identified incidents in which surface spills of hydraulic
13 fracturing-related fluids were attributed to well communication events.
14 Older or inactive wells—including oil and gas wells, injection wells, or drinking water wells—near a
15 hydraulic fracturing operation may pose an even greater potential for impacts. A study in Oklahoma
16 found that older wells were more likely to be negatively affected by the stresses applied by
17 hydraulic fracturing in neighboring wells (Ajani and Kelkar. 2012). In some cases, inactive wells in
18 the vicinity of hydraulic fracturing activities may not have been plugged properly—many wells
19 plugged before the 1950s were done so with little or no cement. The Interstate Oil and Gas Compact
20 Commission estimates that over one million wells may have been drilled in the United States prior
21 to a formal regulatory system being in place, and the status and location of many of these wells are
22 unknown (IOGCC, 2008). State programs exist to plug identified inactive wells, and work is on-
23 going to identify and address such wells.
Flowback and Produced Water
24 Water, of variable quality, is a byproduct of oil and gas production. After hydraulic fracturing, the
25 injection pressure is released and water flows back from the well. Initially this water is similar to
26 the hydraulic fracturing fluid, but as time goes on the composition is affected by the characteristics
27 of the formation and possible reactions between the formation and the fracturing fluid. Water
28 initially produced from the well after hydraulic fracturing is sometimes called flowback in the
29 literature, and the term appears in this assessment However, hydraulic fracturing fluids and any
30 formation water returning to the surface are often referred to collectively as produced water. This
31 definition of produced water is used in this assessment
32 The amountof produced water varies, but typically averages 10% to 25% of injected volumes,
33 depending upon the amount of time since fracturing and the particular well (see Figure ES-3a).
34 However, there are exceptions to this, such as in the Barnett Shale in Texas where the total volume
35 of produced water can equal or exceed the injected volume of hydraulic fracturing fluid (see Figure
36 ES-3b). Flow rates are generally high initially, and then decrease over time throughout oil or gas
37 production.
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1 Impacts on drinking water resources have the potential to occur if produced water is spilled and
2 enters surface water or ground water. Environmental transport of chemical constituents in
3 produced water depends on the characteristics of the spill (e.g., volume and duration), the
4 composition of spilled fluids, and the characteristics of the surrounding environment
Research Questions: Flowback and Produced Water
• What is currently known about the frequency, severity, and causes of spills of flow/back and
produced water?
5 Surface spills of produced water from hydraulically fractured wells have occurred. As noted in the
6 Chemical Mixing section above, the frequency of on-site spills from hydraulic fracturing activities
7 could be estimated for two states, but not nationally. Estimates of spill frequencies at hydraulic
8 fracturing sites in Colorado and Pennsylvania, including spills of produced water, ranged from
9 approximately 0.4 to 12.2 spills per 100 wells. Available data generally precluded estimates of
10 produced water spill rates separately from estimates of overall spill frequency. Away from the well,
11 produced water spills from pipelines and truck transport also have the potential to impact drinking
12 water resources.
13 The EPA characterized spill volumes and causes for 225 cases in which produced water spilled on
14 or near a well pad. These spills occurred between January 2006 and April 2012 in 11 states. The
15 median reported volume per produced water spill was 990 gallons (3,750 L), more than double that
16 for spills of hydraulic fracturing fluids and chemicals. The causes of produced water spills were
17 reported as human error, equipment failure, container integrity failure, miscellaneous causes (e.g.,
18 well communication), and unknown causes. Most of the total volume spilled (74%) for all 225 cases
19 combined was caused by a failure of container integrity.
• What is the composition of hydraulic fracturing flowback and produced water, and what
factors might influence this composition?
20 A combination of factors influence the composition of produced water, including: the composition
21 of injected hydraulic fracturing fluids, the type of formation fractured, subsurface processes, and
2 2 residence time. The initial chemical composition of produced water primarily reflects the chemistry
23 of the injected fluids. At later times, the chemical composition of produced water reflects the
24 geochemistry of the fractured formation.
25 Produced water varies in quality from fresh to highly saline, and can contain high levels of major
26 anions and cations, metals, organics, and naturally occurring radionuclides. Produced water from
27 shale and tight gas formations typically contains high levels of total dissolved solids (TDS) and ionic
28 constituents (e.g., bromide, calcium, chloride, iron, potassium, manganese, magnesium, and
29 sodium). Produced water also may contain metals (e.g., barium, cadmium, chromium, lead, and
30 mercury), and organic compounds such as benzene. Produced water from coalbed methane
31 typically has much lower TDS levels compared to other produced water types, particularly if the
32 coalbed was deposited under fresh water conditions..
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1 We identified 134 chemicals that have been detected in hydraulic fracturing produced water. These
2 include chemicals added during the chemical mixing stage, as well as naturally occurring organic
3 chemicals and radionuclides, metals, and other constituents of subsurface rock formations
4 mobilized by the hydraulic fracturing process. Data on measured chemical concentrations in
5 produced water were available for 75 of these 134 chemicals.
6 Most of the available data on produced water content are for shale and coalbed methane
7 formations, while less data are available for tight formations, such as sandstones. The composition
8 of produced water must be determined through sampling and analysis, both of which have
9 limitations—the former due to challenges in accessing production equipment, and the latter due to
10 difficulties identifying target analytes before analysis and the lack of appropriate analytical
11 methods. Most current data are for inorganic chemicals, while less data exist for organic chemicals.
12 Many more organic chemicals were reported as used in hydraulic fracturing fluid than have been
13 identified in produced water. The difference may be due to analytical limitations, limited study
14 scopes, and undocumented subsurface reactions.
• What are the chemical, physical, and toxicological properties of hydraulic fracturing flowback
and produced water constituents?
15 The identified constituents of produced water include inorganic chemicals (cations and anions, i.e.,
16 metals, metalloids, non-metals, and radioactive materials), organic chemicals and compounds, and
17 unidentified materials measured as total organic carbon and dissolved organic carbon. Some
18 constituents are readily transported with water (i.e., chloride and bromide), while others depend
19 strongly on the geochemical conditions in the receiving water body (i.e., radium and barium), and
20 assessment of their transport is based on site-specific factors. We were able to obtain actual or
21 estimated physicochemical properties for 86 (64%) of the 134 chemicals identified in produced
22 water.
23 As in the case of chemicals in hydraulic fracturing fluid, chemical properties that affect the
24 likelihood of an organic chemical in produced water reaching and impacting drinking water
25 resources include: mobility, solubility, and volatility. In general, physicochemical properties suggest
26 that organic chemicals in produced water tend to be less mobile in the environment Consequently,
27 if spilled, these chemicals may remain in soils or sediments near spill sites. Low mobility may result
28 in smaller dissolved contaminant plumes in ground water, although these chemicals can be
29 transported with sediments in surface water or small particles in ground water. Organic chemical
30 properties vary with salinity, and effects depend on the nature of the chemical.
31 Oral reference values and/or oral slope factors from selected federal, state, and international
32 sources were available for 83 (62%) of the 134 chemicals detected in produced water. From U.S.
33 federal sources alone, chronic oral reference values were available for 70 (52%) of the 134
34 chemicals, and oral slope factors were available for 20 chemicals (15%). Of the chemicals that had
35 values available, noted health effects include the potential for carcinogenesis, immune system
36 effects, changes in body weight, changes in blood chemistry, pulmonary toxicity, neurotoxicity, liver
37 and kidney toxicity, and reproductive and developmental toxicity. As noted above, evaluating any
3 8 potential risk to human populations would require knowledge of the specific chemicals that are
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1 present at a particular site, whether or not humans are exposed to those chemicals and, if so, at
2 what levels and for what duration, and the toxicity of the chemicals. The chemicals present in
3 produced water can vary based on the formation and specific well, due to differences in fracturing
4 fluid formulation and formation geology. Accordingly, consideration of hazards and risks associated
5 with these chemicals would be most useful on a site-specific basis and is beyond the scope of this
6 assessment
• If spills occur, how might hydraulic fracturing flowback and produced water contaminate
drinking water resources?
7 Impacts to drinking water resources from spills or releases of produced water depend on the
8 volume, timing, and composition of the produced water. Impacts are more likely the greater the
9 volume of the spill, the longer the duration of the release, and the higher the concentration of
10 produced water constituents (i.e., salts, naturally occurring radioactive material, and metals).
11 The EPA characterization of hydraulic fracturing-related spills found that 8% of the 225 produced
12 water spills included in the study reached surface water or ground water. These spills tended to be
13 of greater volume than spills that did not reach a water body. A well blowout in Bradford County,
14 Pennsylvania spilled an estimated 10,000 gal (38,000 L) of produced water into a tributary of
15 Towanda Creek, a state-designated trout fishery. The largest volume spill identified in this
16 assessment occurred in North Dakota, where approximately 2.9 million gal (11 million L) of
17 produced water spilled from a broken pipeline and impacted surface and ground water.
18 Chronic releases can and do occur from produced water disposed in unlined pits or impoundments,
19 and can have long-term impacts. Ground water impacts may persist longer than surface water
20 impacts because of lower flow rates and decreased mixing. Plumes from unlined pits used for
21 produced water have been shown to persist for long periods and extend to nearby surface water
22 bodies.
Wastewater Management and Waste Disposal
2 3 Hydraulic fracturing generates large volumes of produced water that require management. In this
24 section we refer to produced water and any other waters generated onsite by the single term
25 "wastewater." Clark and Veil (2009) estimated that, in 2007, approximately one million active oil
26 and gas wells in the United States generated 2.4 billion gal per day (9.1 billion L per day) of
27 wastewater. There is currently no reliable way to estimate what fraction of this total volume can be
28 attributed to hydraulically fractured wells. Wastewater volumes in a region can increase sharply as
29 hydraulic fracturing activity increases.
3 0 Wastewater management and disposal could affect drinking water resources through multiple
31 mechanisms, including: inadequate treatment of wastewater prior to discharge to a receiving
32 water, accidental releases during transport or leakage from wastewater storage pits, unpermitted
3 3 discharges, migration of constituents in wastewaters following land application, inappropriate
34 management of residual materials from treatment, or accumulation of wastewater constituents in
35 sediments near outfalls of centralized waste treatment facilities (CWTs) or publicly owned
36 treatment works (POTWs) that have treated hydraulic fracturing wastewater. The scope of this
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1 assessment excludes potential impacts to drinking water from the disposal of hydraulic fracturing
2 wastewater in underground injection control (UIC) wells.
Research Questions: Wastewater Management and Waste Disposal
• What are the common treatment and disposal methods for hydraulic fracturing wastewater,
and where are these methods practiced?
3 Hydraulic fracturing wastewater is managed using several options, including: disposal in UIC wells
4 (also called disposal wells); through evaporation ponds; treatment at CWTs, followed by reuse or
5 by discharge to either surface waters or POTWs; reuse with minimal or no treatment; and land
6 application or road spreading. Treatment of hydraulic fracturing wastewater by POTWs was used in
7 the past in Pennsylvania. This decreased sharply following new state-level requirements and a
8 request by the Pennsylvania Department of Environmental Protection (PA DEP) for well operators
9 to stop sending Marcellus Shale wastewater to POTWs (and 15 CWTs) discharging to surface
10 waters.
11 Wastewater management decisions are generally based on the availability and associated costs
12 (including transportation) of disposal or treatment facilities. A survey of state agencies found that,
13 in 2007, more than 98% of produced water from the oil and gas industry was managed via
14 underground injection (Clark and Veil. 2009). Available information suggests that disposal wells are
15 also the primary management practice for hydraulic fracturing wastewater in most regions in the
16 United States (e.g., the Barnett Shale; see Figure ES-3b). The Marcellus Shale region is a notable
17 exception, where most wastewater is reused because of the small number of disposal wells in
18 Pennsylvania (see Figure ES-3a). Although this assessment does not address potential effects on
19 drinking water resources from the use of disposal wells, any changes in cost of disposal or
20 availability of disposal wells would likely influence wastewater management decisions.
21 Wastewater from some hydraulic fracturing operations is sent to CWTs, which may discharge
22 treated wastewater to surface waters, POTWs, or back to well operators for reuse in other
23 hydraulic fracturing operations. Available data indicate that the use of CWTs for treating hydraulic
24 fracturing wastewater is greater in the Marcellus Shale region than other parts of the country. Most
25 of the CWTs accepting hydraulic fracturing wastewater in Pennsylvania cannot significantly reduce
26 TDS, and many of these facilities provide treated wastewater to well operators for reuse and do not
27 currently discharge treated wastewater to surface water.
28 Reuse of wastewater for subsequent hydraulic fracturing operations may require no treatment,
29 minimal treatment, or more extensive treatment. Operators reuse a substantial amount (ca. 70-
30 90%) of Marcellus Shale wastewater in Pennsylvania (see Figure ES-3a). Lesser amounts of reuse
31 occur in other areas (e.g., the Barnett Shale; see Figure ES-3b). In certain formations, such as the
32 Bakken Shale in North Dakota, there is currently no indication of appreciable reuse.
33 In some cases, wastewater is used for land applications such as irrigation or road spreading for
34 deicing or dust suppression. Land application has the potential to introduce wastewater
35 constituents into surface water and ground water due to runoff and migration of brines. Studies of
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1 road spreading of conventional oil and gas brines have found elevated levels of metals in soils and
2 chloride in ground water.
• How effective are conventional POTWs and commercial treatment systems in removing
organic and inorganic contaminants of concern in hydraulic fracturing wastewater?
3 Publicly owned treatment works using basic treatment processes are not designed to effectively
4 reduce TDS concentrations in highly saline hydraulic fracturing wastewater—although specific
5 constituents or constituents groups can be removed (e.g., metals, oil, and grease by chemical
6 precipitation or other processes). In some cases, wastewater treated at CWTs may be sent to a
7 POTW for additional treatment and discharge. It is blended with POTW influent to prevent
8 detrimental effects on biological processes in the POTW that aid in the treatment of wastewater.
9 Centralized waste treatment facilities with advanced wastewater treatment options such as reverse
10 osmosis, thermal distillation, or mechanical vapor recompression, reduce TDS concentrations and
11 can treat contaminants currently known to be in hydraulic fracturing wastewater. However, there
12 are limited data on the composition of hydraulic fracturing wastewater, particularly for organic
13 constituents. It is unknown whether advanced treatment systems are effective at removing
14 constituents that are generally not tested for.
• What are the potential impacts from surface water disposal of treated hydraulic fracturing
wastewater on drinking water treatment facilities?
15 Potential impacts to drinking water resources may occur if hydraulic fracturing wastewater is
16 inadequately treated and discharged to surface water. Inadequately treated hydraulic fracturing
17 wastewater may increase concentrations of TDS, bromide, chloride, and iodide in receiving waters.
18 In particular, bromide and iodide are precursors of disinfection byproducts (DBPs) that can form in
19 the presence of organic carbon in drinking water treatment plants or wastewater treatment plants.
20 Drinking water treatment plants are required to monitor for certain types of DBPs, because some
21 are toxic and can cause cancer.
2 2 Radionuelides can also be found in inadequately treated hydraulic fracturing wastewater from
2 3 certain shales, such as the Marcellus. A recent study by the PADEP (2015b) found elevated radium
24 concentrations in the tens to thousands of picocuries per liter and gross alpha and gross beta in the
25 hundreds to thousands of picocuries per liter in effluent samples from some CWTs receiving oil and
26 gas wastewater. Radium, gross alpha, and gross beta were also detected in effluents from POTWs
27 receiving oil and gas wastewater (mainly as effluent from CWTs), though at lower concentrations
28 than from the CWTs. Research in Pennsylvania also indicates the accumulation of radium in
29 sediments and soils affected by the outfalls of some treatment plants that have handled oil and gas
30 wastewater, including Marcellus Shale wastewater, and other wastewaters (PADEP, 2015b:
31 Warner etal., 2013a). Mobilization of radium from sediments and potential impacts on downstream
32 water quality depend upon how strongly the radium has sorbed to sediments. Impacts may also
33 occur if sediment is resuspended (e.g., following storm events). There is no evidence of radionuclide
34 contamination in drinking water intakes due to inadequately treated hydraulic fracturing
35 wastewater.
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1 Hydraulic fracturing wastewaters contain other constituents such as barium, boron, and heavy
2 metals. Barium in particular has been documented in some shale gas produced waters. Little data
3 exist on metal and organic compound concentrations in untreated and treated wastewaters in
4 order to evaluate whether treatment is effective, and whether there are potential downstream
5 effects on drinking water resources when wastewater is treated and discharged.
Key Data Limitations and Uncertainties
6 This assessment used available data and literature to examine the potential impacts of hydraulic
7 fracturing from oil and gas on drinking water resources nationally. As part of this effort, we
8 identified data limitations and uncertainties associated with current information on hydraulic
9 fracturing and its potential to affect drinking water resources. In particular, data limitations
10 preclude a determination of the frequency of impacts with any certainty. These limitations and
11 uncertainties are discussed in brief below.
Limitations in Monitoring Data and Chemical Information
12 While many activities conducted as part of the hydraulic fracturing water cycle take place above
13 ground, hydraulic fracturing itself occurs below ground and is not directly observable. Additionally,
14 potential mechanisms identified in this assessment may result in impacts to drinking water
15 resources that are below ground (e.g., spilled fluids leaching into ground water). Data that could be
16 used to characterize the presence, migration, or transformation of chemicals in the subsurface
17 before, during, and after hydraulic fracturing were found to be scarce relative to the number of
18 hydraulically fractured oil and gas production wells. Specifically, local water quality data needed to
19 compare pre- and post-hydraulic fracturing conditions are not consistently collected or readily
20 available. The limited amount of data collected before and during hydraulic fracturing activities
21 reduces the ability to determine whether hydraulic fracturing affected drinking water resources in
22 cases of alleged contamination.
23 Information (identity, frequency of use, physicochemical and toxicological properties, etc.) on the
24 chemicals associated with the hydraulic fracturing water cycle is not complete and limits
2 5 understanding of potential impacts on drinking water resources. Well operators claimed at least
26 one chemical as confidential at more than 70% of wells reported to FracFocus and analyzed by the
27 EPA. The identity of these chemicals, and other chemicals in produced water, are needed to
28 understand their properties and would also help inform what chemicals to test for to establish
29 baseline conditions and to test for in the event of a suspected drinking water impact. Of the 1,173
30 total chemicals identified by the EPA in hydraulic fracturing fluid and flowback and produced
31 water, 147 have chronic oral reference values and/or oral slope factors from the sources that met
32 the selection criteria for inclusion in this assessment. Because the majority of chemicals identified
33 in this report do not have chronic oral reference values and/or oral slope factors, risk assessors at
34 the local and regional level may need to use alternative sources of toxicity information that could
35 introduce greater uncertainties.
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Other Contributing Limitations
1 We found other limitations that hamper the ability to fully assess the potential impacts of hydraulic
2 fracturing on drinking water resources nationally. These include the number and location of
3 hydraulically fractured wells, the location of drinking water resources, and information on changes
4 in industry practices. The lack of a definitive well count particularly contributes to uncertainties
5 regarding total water use or total wastewater volume estimates, and would limit any kind of
6 cumulative impact assessment Lack of specific information about private drinking water well
7 locations and the depths of drinking water resources in relation to hydraulically fractured rock
8 formations and well construction features (e.g., casing and cement) limits the ability to assess
9 whether subsurface drinking water resources are isolated from hydraulically fractured oil and gas
10 production wells. Finally, this assessment is a snapshot in time, and the industry is rapidly changing
11 (e.g., the number of wells fractured, the location of activities, and the chemicals used). It is unclear
12 how changes in industry practices could affect potential drinking water impacts in the future.
13 Consideration of future development scenarios was not a part of this assessment, but such an
14 evaluation could help establish potential short- and long-term impacts to drinking water resources
15 and how to assess them.
Conclusions
16 Through this national-level assessment, we have identified potential mechanisms by which
17 hydraulic fracturing could affect drinking water resources. Above ground mechanisms can affect
18 surface and ground water resources and include water withdrawals at times or in locations of low
19 water availability, spills of hydraulic fracturing fluid and chemicals or produced water, and
20 inadequate treatment and discharge of hydraulic fracturing wastewater. Below ground mechanisms
21 include movement of liquids and gases via the production well into underground drinking water
22 resources and movement of liquids and gases from the fracture zone to these resources via
23 pathways in subsurface rock formations.
24 We did not find evidence that these mechanisms have led to widespread, systemic impacts on
25 drinking water resources in the United States. Of the potential mechanisms identified in this report,
26 we found specific instances where one or more of these mechanisms led to impacts on drinking
27 water resources, including contamination of drinking water wells. The cases occurred during both
28 routine activities and accidents and have resulted in impacts to surface or ground water. Spills of
29 hydraulic fracturing fluid and produced water in certain cases have reached drinking water
30 resources, both surface and ground water. Discharge of treated hydraulic fracturing wastewater has
31 increased contaminant concentrations in receiving surface waters. Below ground movement of
32 fluids, including gas, most likely via the production well, have contaminated drinking water
33 resources. In some cases, hydraulic fracturing fluids have also been directly injected into drinking
34 water resources, as defined in this assessment, to produce oil or gas that co-exists in those
35 formations.
36 The number of identified cases where drinking water resources were impacted are small relative to
37 the number of hydraulically fractured wells. This could reflect a rarity of effects on drinking water
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1 resources, or may be an underestimate as a result of several factors. There is insufficient pre- and
2 post-hydraulic fracturing data on the quality of drinking water resources. This inhibits a
3 determination of the frequency of impacts. Other limiting factors include the presence of other
4 causes of contamination, the short duration of existing studies, and inaccessible information related
5 to hydraulic fracturing activities.
6 This state-of-the-science assessment contributes to the understanding of the potential impacts of
7 hydraulic fracturing on drinking water resources and the factors that may influence those impacts.
8 The findings in this assessment can be used by federal, state, tribal, and local officials; industry; and
9 the public to better understand and address any vulnerabilities of drinking water resources to
10 hydraulic fracturing activities. This assessment can also be used to help facilitate and inform
11 dialogue among interested stakeholders, and support future efforts, including: providing context to
12 site-specific exposure or risk assessments, local and regional public health assessments, and
13 assessments of cumulative impacts of hydraulic fracturing on drinking water resources overtime
14 or over defined geographic areas of interest Finally, and most importantly, this assessment
15 advances the scientific basis for decisions by federal, state, tribal, and local officials, industry, and
16 the public, on how best to protect drinking water resources now and in the future.
References for Executive Summary
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Technology Conference, February 6-8, 2012, The Woodlands, TX.
Bair. ES: Freeman. DC: Senko. IM. (2010). Subsurface gas invasion Bainbridge Township, Geauga County, Ohio.
(Expert Panel Technical Report). Columbus, OH: Ohio Department of Natural Resources.
http://oilandgas.ohiodnr.gov/resources/investigations-reports-violations-reformstfTHR
Clark, CE: Veil, IA. (2009). Produced water volumes and management practices in the United States (pp. 64).
(ANL/EVS/R-09/1). Argonne, IL: Argonne National Laboratory.
http://www.circleofblue.org/waternews/wp-
content/uploads/2010/09/ANL EVS R09 produced water volume report 2437.pdf
COGCC. Colorado Oil and Gas Conservation Commission Order No. 1V-276. (2004).
https://cogcc.state.co.us/orders/orders/lv/276.html
Crescent (Crescent Consulting, LLC). (2011). East Mamm creek project drilling and cementing study.
Oklahoma City, OK. http://cogcc.state.co.us/Library/PiceanceBasin/EastMammCreek/ReportFinal.pdf
EIA (Energy Information Administration). (2015a). Glossary. Available online at
http://www.eia.gov/tools/glossary/
IOGCC (Interstate Oil and Gas Compact Commission). (2008). Protecting our country's resources: The states'
case, orphaned well plugging initiative. Oklahoma City, OK: Interstate Oil and Gas Compact Commission
(IOGCC). http://iogcc.myshopify.com/products/protecting-our-countrys-resources-the-states-case-
orphaned-well-plugging-initiative-2008
Maupin. MA: Kenny. IF: Hutson. SS: Lovelace. IK: Barber. NL: Linsey. KS. (2014). Estimated use of water in the
United States in 2010. (USGS Circular 1405). Reston, VA: U.S. Geological Survey.
http://dx.doi.org/10.3133/cirl405
Michie. TW: Koch. CA. (1991). Evaluation of injection-well risk management in the Williston Basin. J Pet Tech
43: 737-741. http://dx.doi.org/10.2118/20693-PA
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Executive Summary
Newell. R. (2011). Shale gas and the outlook for U.S. natural gas markets and global gas resources.
Presentation presented at US EIA presentation at OECD Meetings, June 21, 2011, Paris, France.
ODNR. DMRM. (Ohio Department of Natural Resources, Division of Mineral Resources Management). (2008).
Report on the investigation of the natural gas invasion of aquifers in Bainbridge Township of Geauga
County, Ohio. Columbus, OH: ODNR.
http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/bainbridge/report.pdf
PA PEP (Pennsylvania Department of Environmental Protection). (2015b). Technologically enhanced
naturally occurring radioactive materials (TENORM) study report. Harrisburg, PA.
http://www.elibrary.dep.state.pa.us/dsweb/Get/Document-105822/PA-DEP-TENORM-
Study Report Rev. 0 01-15-2015.pdf
Papoulias. DM: Velasco. AL. (2013). Histopathological analysis offish from Acorn Fork Creek, Kentucky,
exposed to hydraulic fracturing fluid releases. Southeastern Naturalist 12: 92-111.
Scanlon. BR: Reedy. RC: Nicot. IP. (2014). Will water scarcity in semiarid regions limit hydraulic fracturing of
shale plays? Environmental Research Letters 9. http://dx.doi.Org/10.1088/1748-9326/9/12/124011
Science Based Solutions LLC. (2014). Summary of hydrogeology investigations in the Mamm Creek field area,
Garfield County. Laramie, Wyoming. http://www.garfield-county.com/oil-gas/documents/Summary-
Hydrogeologic-Studies-Mamm%2 OCreek-Area-Feb-10-2014.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2015J). Retrospective case study in Killdeer, North Dakota:
study of the potential impacts of hydraulic fracturing on drinking water resources [EPA Report]. (EPA
600/R-14/103). Washington, D.C.
USGS (U.S. Geological Survey). (2002). Natural gas production in the United States [Fact Sheet]. (USGS Fact
Sheet FS-113-01). Denver, CO.
Vengosh. A: lackson. RB: Warner. N: Darrah. TH: Kondash. A. (2014). A critical review of the risks to water
resources from unconventional shale gas development and hydraulic fracturing in the United States.
Environ Sci Technol 48: 36-52. http://dx.doi.org/10.1021/es405118y
Warner. NR: Christie. CA: lackson. RB: Vengosh. A. (2013a). Impacts of shale gas wastewater disposal on
water quality in western Pennsylvania. Environ Sci Technol 47:11849-11857.
http://dx.doi.org/10.1021/es402165b
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 1 - Introduction
Chapter 1
Introduction
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Hydraulic Fracturing Drinking Water Assessment Chapter 1 - Introduction
1. Introduction
1.1. Background
1 Since the early 2000s, oil and natural gas production in the United States has been transformed
2 through the technological innovations of hydraulic fracturing and directional drilling. Hydraulic
3 fracturing is a stimulation technique used to increase production of oil and gas. It involves the
4 injection of fluids under pressures great enough to fracture the oil- and gas-production formations.
5 Hydraulic fracturing in combination with advanced directional drilling techniques has made it
6 possible to economically extract hydrocarbons from unconventional resources, such as shale, tight
7 formations, and coalbeds.1 It can also enhance production from conventional resources. The surge
8 in use of hydraulic fracturing and associated technologies has significantly increased domestic
9 energy supplies (see Chapter 2) and brought economic benefits to many areas of the United States.
10 The growth in domestic oil and gas exploration and production- the direct result of the expanded
11 use of hydraulic fracturing- has also raised concerns about its potential for impacts to human
12 health and the environment. Specific concerns have been raised by the public about the effects of
13 hydraulic fracturing on the quality and quantity of drinking water resources. Some residents living
14 close to oil and gas production well sites report changes in the quality of ground water resources
15 used for drinking water and assert that hydraulic fracturing is responsible for these changes. Other
16 concerns include competition for water between hydraulic fracturing operations and other water
17 users, especially in areas of the country experiencing drought, and the disposal of waste water
18 generated from hydraulic fracturing. In response to public concerns, the U.S. Congress urged the
19 U.S. Environmental Protection Agency (EPA) to study the relationship between hydraulic fracturing
20 and drinking water (H.R. Rep. 111-316. 20091. In 2011, the EPA published its Plan to Study the
21 Potential Impacts of Hydraulic Fracturing on Drinking Water Resources (U.S. EPA. 2011c: hereafter
22 Study Plan). The research described in the Study Plan began the same year. In 2012, the EPA issued
2 3 Potential Impacts of Hydraulic Fracturing on Drinking Water Resources: Progress Report (U.S. EPA,
24 2012f: hereafter Progress Report] in order to update the public on the status of the research being
25 conducted under the Study Plan. In this report, we review and synthesize scientific literature,
26 including the publications resulting from the EPA's research and information provided by
27 stakeholders, to assess the potential for hydraulic fracturing for oil and gas to change the quality or
28 quantity of drinking water resources. This report also identifies factors affecting the frequency or
29 severity of any potential impacts.
1.2. Scope
30 This assessment focuses on hydraulic fracturing in onshore oil and gas wells in the contiguous
31 United States; limited available information on hydraulic fracturing in Alaska is included. To the
1 Unconventional resources is an umbrella term for oil and natural gas that is produced by means that do not meet the
criteria for conventional production. What has qualified as unconventional at any particular time is a complex function of
resource characteristics, the available exploration and production technologies, the economic environment, and the scale,
frequency, and duration of production from the resource (see Text Box 2-2).
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1 extent possible, this assessment addresses hydraulic fracturing in all types of oil- and gas-bearing
2 formations in which it is conducted, including shale, so-called 'tight' formations (e.g., certain
3 sandstones, siltstones, and carbonates), coalbeds, and conventional reservoirs. It tends to focus on
4 hydraulic fracturing in shale, which reflects the relatively large amount of literature and available
5 data on hydraulic fracturing in this type of geologic formation.
6 The scope of activities examined in this assessment is defined by the hydraulic fracturing water
7 cycle. This cycle encompasses activities involving water that support hydraulic fracturing and
8 consists of five stages: (1) acquisition of water needed to create hydraulic fracturing fluids; (2)
9 mixing of water and chemicals on the well pad to create hydraulic fracturing fluids; (3) injection of
10 hydraulic fracturing fluids into the well to fracture the geologic formation; (4) management of
11 flowback and produced water on the well pad and in transit for reuse, treatment, or disposal; and
12 (5) reuse, treatment and discharge, or disposal of hydraulic fracturing wastewater (see Figure
13 l-l).i.2.3-4
14 Activities within the hydraulic fracturing water cycle can take place on or near the well pad or some
15 distance away. On-site activities include mixing and injecting hydraulic fracturing fluids and
16 capturing flowback and produced water. Water withdrawals and wastewater treatment and
17 disposal may occur in the same watershed, adjacent watersheds, or watersheds many miles away
18 from the production site.
19 This assessment focuses on impacts on drinking water resource quantity and quality. Consistent
20 with the Study Plan (U.S. EPA. 2011c], drinking water resources are defined broadly within this
21 report as any body of ground water or surface water that now serves, or in the future could serve,
22 as a source of drinking water for public or private use. This is broader than most regulatory
23 definitions of "drinking water" and encompasses both fresh and non-fresh bodies of water, since
24 trends indicate both types of water bodies are now and in the future will be used as sources of
25 drinking water (see Chapter 3). We note that drinking water resources provide not only water that
26 individuals actually drink but also water used for many additional purposes such as cooking and
27 bathing.
28 We assess potential effects on drinking water resources from business-as-usual operations as well
29 as from accidents and unintended releases that may occur during the hydraulic fracturing water
30 cycle (see Table 1-1).
1 Hydraulic fracturing fluids are engineered fluids, typically consisting of a base fluid, additives, and proppants, that are
pumped under high pressure into the well to create and hold open fractures in the formation.
2 Flowback is defined multiple ways in the literature. In general, it is either fluids predominantly containing hydraulic
fracturing fluid that return from a well to the surface or a process used to prepare the well for production (see Chapter 7).
3 Produced water is water that flows from oil and gas wells.
4 Hydraulic fracturing wastewater is flowback and produced water that is managed using practices that include but are
not limited to reuse in subsequent hydraulic fracturing operations, treatment and discharge, and injection into disposal
wells (see Chapter 8).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 1 - Introduction
Well Injection
Chemical Mixing
Flowback and Produced Water
Water Acquisition
Wastewater Treatment and Waste Disposal
Figure 1-1. Conceptualized view of the stages of the hydraulic fracturing water cycle.
Shown here is a generalized landscape depicting the activities of the hydraulic fracturing water cycle and their relationship to each other, as well as
their relationship to drinking water resources. Activities may take place in the same watershed or different watersheds and close to or far from
drinking water resources. Drinking water resources are any body of ground water or surface water that now serves, or in the future could serve, as
a source of drinking water for public or private use. Arrows depict the movement of water and chemicals. Specific activities in the "Wastewater
Treatment and Waste Disposal" inset are (a) underground injection control (UIC) well disposal, (b) wastewater treatment and reuse, and (c)
wastewater treatment and discharge at a centralized waste treatment (CWT) facility. Note: Figure not to scale.
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Chapter 1 - Introduction
Table 1-1. Stages of the hydraulic fracturing water cycle have various potential effects on
drinking water resources.
The potential effects addressed in this assessment, and how they are related to the activities within
each stage, are summarized here.
Water cycle stage
Water acquisition
Chemical mixing
Well injection
Flowback and
produced water
Wastewater
treatment and
waste disposal
Activities or processes potentially
affecting drinking water resources
Water withdrawals
Spills of hydraulic fracturing fluids
Subsurface migration of hydraulic
fracturing fluids or formation fluids
Spills of flowback or produced water
Discharge of untreated or inadequately
treated wastewater and inappropriate
disposal of waste solids
Potential drinking water effects
addressed in this assessment
Quality
Ground
water
X
X
X
X
X
Surface
water
X
X
X
X
X
Quantity
Ground
water
X
Surface
water
X
1 As part of the assessment, we evaluated immediate, near-term, and long-term effects on drinking
2 water resources. For example, we considered how surface spills of hydraulic fracturing fluids may
3 potentially have immediate or near-term impacts on neighboring surface water and shallow ground
4 water quality (see Chapters 5 and 7). We also considered how the potential release of hydraulic
5 fracturing fluids in the subsurface may take years to impact ground water resources, because
6 liquids and gas often move slowly in the subsurface (see Chapter 6). Additionally, effects may be
7 detected near the activity or at some distance away. For instance, we considered that, depending on
8 the constituents of treated hydraulic fracturing wastewater discharged to a stream and the flow in
9 that stream, drinking water resource quality could be affected a significant distance downstream
10 (see Chapter 8).
11 This assessment focuses predominantly on activities supporting a single well or multiple wells on a
12 single well pad, accompanied by a more limited discussion of cumulative activities and the effects
13 that could result from having many wells on a landscape. Studies of cumulative effects are generally
14 lacking, but we use the scientific literature to address this topic where possible.1
15 We address mechanisms for impacts as well as impacts of hydraulic fracturing for oil and gas on
16 drinking water resources. In general, a mechanism is the means or series of events that links an
17 activity to an impact, while an impact is the end result of a mechanism and represents a change in
18 the entity of interest Specific definitions used in this assessment are provided below.
1 Cumulative effects refer to combined changes in the environment that can take place as a result of multiple activities
over time and/or space.
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1 • A mechanism is a means or series of events by which an activity within the hydraulic
2 fracturing water cycle has been observed to change the quality or quantity of drinking
3 water resources.
4 • A suspected mechanism is a means or series of events by which hydraulic fracturing
5 activities could logically have resulted in an observed change in the quality or quantity of
6 drinking water resources. Available evidence may or may not be sufficient to determine if
7 it is the only mechanism that caused the observed change.
8 • A potential mechanism is a means or series of events by which hydraulic fracturing
9 activities could logically or theoretically (for instance, based on modeling) change the
10 quality or quantity of drinking water resources but one that has not yet been observed.
11 • An impact is any observed change in the quality or quantity of drinking water resources,
12 regardless of severity, that results from a mechanism.
13 • A potential impact is any change in the quality or quantity of drinking water resources
14 that could logically occur as the result of a mechanism or potential mechanism but has not
15 yet been observed.
16 Potential mechanisms and impacts, as well as suspected mechanisms, are addressed because data
17 required to document mechanisms and impacts may be inaccessible, incomplete, or nonexistent. In
18 addition, evidence maybe insufficient to isolate the contribution of hydraulic fracturing to changes
19 in the quality or quantity of drinking water resources from other human activities occurring
20 nearby. We anticipate that our understanding of mechanisms and impacts will be advanced as the
21 scientific community continues to evaluate potential health and environmental effects of hydraulic
22 fracturing.
23 In this assessment, we also identify and discuss factors affecting the frequency or severity of
24 changes to avoid a simple inventory of all specific situations in which hydraulic fracturing might
25 alter drinking water quality or quantity. This allows knowledge about the conditions under which
26 effects are likely or unlikely to occur to be applied to new circumstances (e.g., a new area of oil or
27 gas development where hydraulic fracturing is expected to be used) and could inform the
28 development of strategies to prevent impacts. Although no attempt has been made in this
29 assessment to identify or evaluate comprehensive best practices for states, tribes, or the industry,
30 we describe ways to avoid or reduce the impacts of hydraulic fracturing activities as they have been
31 reported in the scientific literature. A summary and evaluation of current or proposed regulations
3 2 and policies is beyond the scope of this report
3 3 For this assessment, we did not conduct site-specific predictive modeling to quantitatively estimate
34 environmental concentrations of contaminants in drinking water resources, although modeling
35 studies conducted by others are described. Further, this report is not a human health risk
36 assessment. It does not identify populations that are exposed to chemicals or other stressors in the
37 environment, estimate the extent of exposure, or estimate the incidence of human health impacts
38 (see Chapter 9).
This document is a draft for review purposes only and does not constitute Agency policy.
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1 This assessment focuses on the potential impacts from activities in the hydraulic fracturing water
2 cycle on drinking water resources. It does not address all concerns that have been raised about
3 hydraulic fracturing nor about oil and gas exploration and production more generally. Activities
4 that are not considered include acquisition and transport of constituents of hydraulic fracturing
5 fluids besides water (e.g., sand mining and chemical production); site selection and well pad
6 development; other infrastructure development (e.g., roads, pipelines, compressor stations); site
7 reclamation; and well closure. We consider these activities to be outside the scope of the hydraulic
8 fracturing water cycle and, therefore, their impacts are not addressed in this assessment
9 Additionally, this report does not discuss the potential impacts of hydraulic fracturing on other
10 water uses (e.g., agriculture or industry), other aspects of the environment (e.g., air quality or
11 ecosystems), worker health or safety, or communities.
1.3. Approach
12 This assessment relies on scientific literature and data that address topics within the scope of the
13 hydraulic fracturing water cycle. Scientific journal articles and peer-reviewed EPA reports that have
14 been published containing results from the EPA's hydraulic fracturing study comprise one set of
15 applicable literature. Other literature evaluated includes articles published in science and
16 engineering journals, federal and state government reports, non-governmental organization (NGO)
17 reports, and oil and gas industry publications. Data sources examined include federal- and state-
18 collected data sets, databases curated by federal and state government agencies, other publicly
19 available data and information, and data including confidential and non-confidential business
20 information submitted by industry to the EPA.*
1.3.1. EPA Hydraulic Fracturing Study Publications
21 The research topic areas and projects described in the Study Plan were developed with substantial
2 2 expert and public input, and they were designed to meet the data and information needs of this
23 assessment As such, published, peer-reviewed results of the research conducted under the Study
24 Plan are incorporated and cited frequently throughout this assessment As is customary in
25 assessments that synthesize a large body of literature and data, the results of EPA research are
26 contextualized and interpreted in combination with the other literature and data described in
27 Section 1.3.2. The articles and EPA reports themselves that give complete and detailed project
28 results can be found on the EPA's hydraulic fracturing website (www.epa.gov/hfstudy). For ease of
29 reference, a description of the individual projects, the type of research activity they represent (i.e.,
30 analysis of existing data, scenario evaluation, laboratory study, or case study), and the
31 corresponding citations of published articles and EPA reports that are referenced in this
3 2 assessment can be found in Appendix H.
1.3.2. Literature and Data Search Strategy
33 The EPA used a broad search strategy to identify approximately 3,700 sources of scientific
34 information that could be applicable to this assessment. This search strategy included both
1 Information was provided to the EPA by nine hydraulic fracturing service companies in response to a September 2010
information request and by nine oil and gas well operators in response to an August 2011 information request.
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Hydraulic Fracturing Drinking Water Assessment Chapter 1 - Introduction
1 requesting input from scientists, stakeholders, and the public about relevant data and information,
2 and thorough searching of published information and applicable data.x
3 Over 1,400 articles, reports, data, and other sources of information were obtained through outreach
4 to the public, stakeholders, and scientific experts. The EPA requested material through many
5 venues, as follows. We received recommended literature from the Science Advisory Board (SAB),
6 the EPA's independent federal scientific advisory committee, from its review of the EPA's draft
7 Study Plan; its consultation on the EPA's Progress Report [U.S. EPA. 2012Q: and during an SAB
8 briefing on new and emerging information related to hydraulic fracturing in fall 2013. Subject
9 matter experts and stakeholders also recommended literature through a series of technical
10 workshops and roundtables organized by the EPA between 2011 and 2013. In addition, the public
11 submitted material to the SAB during the SAB review of the draft Study Plan, Progress Report, and
12 briefing on emerging information, as well as in response to a formal request for data and
13 information posted in the Federal Register (EPA-HQ-ORD-2010-0674) in November 2012. The
14 submission deadline was extended from April to November 2013 to provide the public with
15 additional opportunity to provide input to the EPA.
16 Approximately 2,300 additional sources were identified by conducting searches for material that
17 could be applicable to the assessment via online scientific databases and federal, state, and
18 stakeholder websites. We searched these databases and websites in particular for (1) materials
19 addressing topics not covered by the documents submitted by experts, stakeholders, and the public
20 as noted above, and (2) newly emerging scientific studies. Multiple targeted and iterative searches
21 on topics determined to be within the scope of the assessment were conducted until fall 2014. After
22 that time, we largely included newer literature as it was recommended to us during our internal
23 technical reviews or as it came to our attention and was determined to be important for filling a gap
24 in information. In many cases, our searches uncovered the same material submitted by the public,
25 but approximately 2,300 new sources were also identified.
1.3.3. Literature and Data Evaluation Strategy
2 6 We evaluated the literature and data identified in the search strategy above using the five
27 assessment factors outlined by the EPA Science Policy Council in A Summary of General Assessment
2 8 Factors for Evaluating the Quality of Scientific and Technical Information [U.S. EPA. 20031. The
29 factors are (1) applicability and utility, (2) evaluation and review, (3) soundness, (4) clarity and
30 completeness, and (5) uncertainty and variability. Table 1-2 lists these factors along with the
31 specific criteria for each that were developed for this assessment We first evaluated all materials
32 for applicability. If "applicable" under the criteria, the reference was evaluated on the basis of the
33 other four factors.
34 Our objective was to consider and then cite literature in the assessment that fully conforms to all
35 criteria defining each assessment factor. However, the preponderance of literature on some topics
36 did not fully conform to some aspects of the outlined criteria. For instance, there were many white
1 This study did not review information contained in state and federal enforcement actions concerning alleged
contamination of drinking water resources.
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 1 - Introduction
1 papers and reports in technical areas in which independent peer review is not standard practice or
2 is not well documented. Therefore, we included references in the assessment that were not peer-
3 reviewed but that addressed topics not found in the peer-reviewed literature, that provided useful
4 background information, or that corroborated conclusions in the peer-reviewed literature.
Table 1-2. Criteria developed for the five factors used to evaluate literature and data cited in
this assessment.
Criteria are consistent with those outlined by the EPA's Science Policy Council (U.S. EPA, 2003). Criteria
are incorporated into the Quality Assurance Project Plans for this assessment (U.S. EPA, 2014g,
2013d).
Factor
Applicability
Review
Soundness
Clarity/completeness
Uncertainty/variability
Criteria
Document provides information useful for assessing the potential pathways for
hydraulic fracturing activities to change the quality or quantity of drinking water
resources, identifies factors that affect the frequency and severity of impacts, or
suggests ways that potential impacts may be avoided or reduced.
Document has been peer-reviewed.
Document relies on sound scientific theory and approaches, and conclusions are
consistent with data presented.
Document provides underlying data, assumptions, procedures, and model parameters,
as applicable, as well as information about sponsorship and author affiliations.
Document identifies uncertainties, variability, sources of error, and/or bias and
properly reflects them in any conclusions drawn.
1.3.4. Quality Assurance and Peer Review
5 The use of quality assurance (QA) and peer review helps ensure that the EPA conducts high-quality
6 science that can be used to inform policymakers, industry, and the public. QA activities performed
7 by the EPA ensure that the agency's environmental data are of sufficient quantity and quality to
8 support the data's intended use. The EPA prepared a programmatic Quality Management Plan [U.S.
9 EPA. 2014h] for all of the research conducted under the EPA's Study Plan, including the review and
10 synthesis of the scientific literature in this assessment. The hydraulic fracturing Quality
11 Management Plan describes the QA program's organizational structure; defines and assigns QA and
12 quality control (QC) responsibilities; and describes the processes and procedures used to plan,
13 implement, and assess the effectiveness of the quality system. The broad plan is then supported by
14 more detailed QA Project Plans (QAPPs). For instance, the QAPPs developed for this assessment
15 provide the technical approach and associated QA/QC procedures for our data and literature search
16 and evaluation strategies introduced in Section 1.3.2 and 1.3.3 [U.S. EPA. 2014g. 2013d]. A QA audit
17 was conducted by the QA Manager during the preparation of this assessment in order to verify that
18 the appropriate QA procedures, criteria, reviews, and data verification were adequately performed
19 and documented. Identifying uncertainties is another aspect of QA; uncertainty, including data gaps
20 and data limitations, is discussed throughout this assessment
This document is a draft for review purposes only and does not constitute Agency policy.
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1 This report is classified as a Highly Influential Scientific Assessment (HISA), defined by the Office of
2 Management and Budget (OMB) as a scientific assessment that (1) could have a potential impact of
3 more than $500 million in any year or (2) is novel, controversial, or precedent-setting or has
4 significant interagency interest [OMB, 2004]. The OMB describes specific peer review requirements
5 for HISAs. The EPA often engages the SAB as an external federal advisory committee to conduct
6 peer reviews of high-profile scientific matters relevant to the agency. Members of an ad hoc panel,
7 the same panel that was convened under the auspices of the SAB to provide comment on the
8 Progress Report, will also provide comment on this assessment.1 Panel members were nominated
9 by the public and chosen to create a balanced review panel based on factors such as technical
10 expertise, knowledge, experience, and absence of any real or perceived conflicts of interest
1.4. Organization
11 This assessment begins with a general description of hydraulic fracturing activities and the role of
12 hydraulic fracturing in the oil and gas industry in the United States (see Chapter 2). It follows with a
13 characterization of drinking water resources in the continental United States, with a focus on areas
14 in which we estimate hydraulic fracturing has taken place over the time period of 2000-2013 (see
15 Chapter 3).
16 Chapters 4 through 8 are organized around the stages of the hydraulic fracturing water cycle (see
17 Figure 1-1) and address the potential for activities conducted during those stages to change the
18 quality or quantity of drinking water resources. Each of the stages is covered by a separate chapter.
19 There is also a chapter devoted to an examination of the properties of chemicals and constituents
20 that have been or may be used in hydraulic fracturing fluids or present in flowback and produced
21 water (see Chapter 9).
22 Each chapter addresses research questions developed under the Study Plan, as data and
23 information allow (see Table 1-3). Concise answers appear in text boxes at the end of each chapter.
24 The final chapter provides major conclusions and a synthesis of information presented across the
25 assessment It also highlights significant gaps in information that contribute to uncertainties about
26 those conclusions (see Chapter 10).
Table 1-3. Research questions addressed by this assessment.
Each chapter addresses research questions developed under the Study Plan. Chapters 2 and 3 develop
background on hydraulic fracturing and drinking water resources, respectively.
Chapter and water cycle stage Research questions
1 Information about this process is available online at http://yosemite.epa.gov/sab/sabproduct.nsf/
02ad90bl36fc21ef85256eba00436459/b436304ba804e3f885257a5b00521b3b!ODenDocument.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 1 - Introduction
Chapter and water cycle stage
Research questions
Chapter 4 - Water Acquisition
What are the types of water used for hydraulic fracturing?
How much water is used per well?
How might cumulative water withdrawals for hydraulic
fracturing affect drinking water quantity?
What are the possible impacts of water withdrawals for
hydraulic fracturing on water quality?
Chapter 5 - Chemical Mixing
What is currently known about the frequency, severity, and
causes of spills of hydraulic fracturing fluids and chemical
additives?
What are the identities and volumes of chemicals used in
hydraulic fracturing fluids, and how might this composition
vary at a given site and across the country?
What are the chemical and physical properties of hydraulic
fracturing chemical additives?
If spills occur, how might hydraulic fracturing chemical
additives contaminate drinking water resources?
Chapter 6 - Well Injection
How effective are current well construction practices at
containing fluids- both liquids and gases- before, during,
and after fracturing?
Can subsurface migration of fluids- both liquids and gases-
to drinking water resources occur, and what local geologic
or artificial features might allow this?
Chapter 7 - Flowback and
Produced Water
What is currently known about the frequency, severity, and
causes of spills of flowback and produced water?
What is the composition of hydraulic fracturing flowback
and produced water, and what factors might influence this
composition?
What are the chemical and physical properties of hydraulic
fracturing flowback and produced water constituents?
If spills occur, how might hydraulic fracturing flowback and
produced water contaminate drinking water resources?
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 1 - Introduction
Chapter and water cycle stage
Research questions
Chapter 8 - Wastewater
Treatment and Waste Disposal
What are the common treatment and disposal methods for
hydraulic fracturing wastewater, and where are these
methods practiced?
How effective are conventional publicly owned treatment
works and commercial treatment systems in removing
organic and inorganic contaminants of concern in hydraulic
fracturing wastewater?
What are the potential impacts from surface water disposal
of treated hydraulic fracturing wastewater on drinking
water treatment facilities?
Chapters - Hazard Evaluation
of Chemicals Across the Water
Cycle Stages
• What are the toxicological properties of hydraulic
fracturing chemical additives?
• What are the toxicological properties of hydraulic
fracturing flowback and produced water constituents?
1.5. Intended Use
1 We expect that this report, as a synthesis of the science, will contribute to the understanding of the
2 potential impacts of hydraulic fracturing on drinking water resources and the factors that may
3 influence those impacts. The data and findings in this report can be used by federal, tribal, state,
4 and local officials; industry; and the public to better understand and address any vulnerabilities of
5 drinking water resources to hydraulic fracturing activities.
6 We expect this report will be used to help facilitate and inform dialogue among interested
7 stakeholders, including Congress, other federal agencies, states, tribal governments, the
8 international community, industry, NGOs, academia, and the general public. Additionally, the
9 identification of knowledge gaps will promote greater attention to these areas by researchers.
10 We also expect this report may support future assessment efforts. For instance, we anticipate that it
11 could contribute context to site-specific exposure or risk assessments of hydraulic fracturing, to
12 regional public health assessments, or to assessments of cumulative impacts of hydraulic fracturing
13 on drinking water resources over time or over defined geographic areas of interest
14 Finally, and most importantly, this assessment advances the scientific basis for decisions by federal,
15 state, tribal, and local officials; industry; and the public on how best to protect drinking water
16 resources now and in the future.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 1 - Introduction
1.6. References for Chapter 1
H.R. Rep. 111-316. Department of the Interior. Environment, and Related Agencies Appropriation Act. 2010:
Conference report (to accompany H.R. 2996), (2009). http://www.gpo.gov/fdsys/pkg/CRPT-
lllhrpt316/pdf/CRPT-lllhrpt316.pdf
OMB (U.S. Office of Management and Budget). (2004). Final information quality bulletin for peer review.
Washington, DC: US Office of Management and Budget (OMB).
http://www.whitehouse.gov/sites/default/files/omb/assets/omb/memoranda/fy2005/m05-03.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2003). A summary of general assessment factors for
evaluating the quality of scientific and technical information [EPA Report]. (EPA/100/B-03/001).
Washington, DC: U.S. Environmental Protection Agency, Office of Research and Development.
http://www.epa.gov/spc/assess.htm
U.S. EPA (U.S. Environmental Protection Agency). (2011c). Plan to study the potential impacts of hydraulic
fracturing on drinking water resources [EPA Report]. (EPA/600/R-11/122). Washington, DC: U.S.
Environmental Protection Agency, Office of Research and Development.
http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-
resources-epa600r-11122
U.S. EPA (U.S. Environmental Protection Agency). (2012f). Study of the potential impacts of hydraulic
fracturing on drinking water resources: Progress report. (EPA/601/R-12/011). Washington, DC: U.S.
Environmental Protection Agency, Office of Research and Development.
http://nepis.epa.gov/exe/ZyPURL.cgi?Dockey=P100FH8M.txt
U.S. EPA (U.S. Environmental Protection Agency). (2013d). Supplemental programmatic quality assurance
project plan for work assignment 5-83 technical support for the hydraulic fracturing drinking water
assessment. Washington, D.C. http://www2.epa.gov/sites/production/files/documents/literature-
review-qappl.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2014g). Quality assurance project plan - Revision no. 2:
Data and literature evaluation for the EPA's study of the potential impacts of hydraulic fracturing (HF) on
drinking water resources [EPA Report]. Washington, D.C.
U.S. EPA (U.S. Environmental Protection Agency). (2014h). Quality management plan- Revision no. 2: Study of
the potential impacts of hydraulic fracturing for oil and gas on drinking water resources [EPA Report].
Washington, D.C. http://www2.epa.gov/hfstudy/quality-management-plan-revision-no-2-study-
potential-impacts-hvdraulic-fracturing-oil-and
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
Chapter 2
Hydraulic Fracturing, Oil and Gas Production, and
the U.S. Energy Sector
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
2. Hydraulic Fracturing, Oil and Gas Production, and the
U.S. Energy Sector
1 This chapter provides general background information useful for understanding the in-depth
2 technical chapters that follow. We describe the process and purpose of hydraulic fracturing and the
3 situations and settings in which it is used (Section 2.1). Then, to place hydraulic fracturing in the
4 context of well site operations, we describe activities from site assessment and selection through
5 production to site closure. This helps illustrate the intensive nature of activities during the
6 relatively short hydraulic fracturing phase during the life of a production well (Section 2.2). Finally,
7 we characterize the prevalence of hydraulic fracturing in the United States, its importance in the oil
8 and gas industry today and into the future, and its role in the U.S. energy sector (Sections 2.3 and
9 2.4).
2.1. What is Hydraulic Fracturing?
10 Hydraulic fracturing is a stimulation technique used to increase production of oil and gas. Hydraulic
11 fracturing involves the injection of fluids under pressures great enough to fracture the oil- andgas-
12 production formations. Hydraulic fracturing fluid transfers the pressure generated by equipment at
13 the surface into the subsurface to create fractures, and it carries and places the proppant into the
14 fractures so that they remain "propped" open after the injection pumping pressure is terminated
15 (Gupta and Valko. 2007). Oil and gas can then flow through the fractures into the well and through
16 the well to the surface. Hydraulic fracturing has been used since the late 1940s and for the first
17 almost 5 0 years was used in vertical wells in conventional hydrocarbon reservoirs.x Hydraulic
18 fracturing is still used in these settings, but the process has evolved; technological developments
19 have led to the use of hydraulic fracturing in low-permeability (unconventional) hydrocarbon
20 reservoirs that could not otherwise be profitably produced (see Text Box 2-1). Wells stimulated by
21 hydraulic fracturing may be vertical, deviated, or horizontal in orientation (see Figure 2-1), and
22 they may be newly drilled or older at the time the fracturing is done.
23
1A conventional reservoir is a reservoir in which buoyant forces keep hydrocarbons in place below a sealing caprock.
Reservoir and fluid characteristics of conventional reservoirs typically permit oil or natural gas to flow readily into
wellbores. The term is used to make a distinction from shale and other unconventional reservoirs, in which gas might be
distributed throughout the reservoir at the basin scale, and in which buoyant forces or the influence of a water column on
the location of hydrocarbons within the reservoir are not significant.
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Text Box 2-1. Is Hydraulic Fracturing "New"?
1 Hydraulic fracturing in one form or another has been in use since the late 1940s, when a fracturing technique
2 was patented by the Stanolind Oil and Gas Company and licensed to the Halliburton Oil Well Cementing
3 Company. There are precedents that go back even further: reports from the early days of the oil and gas
4 industry in the mid-19th century show producers trying to increase production by pumping fluids or
5 dropping explosives into wells (Montgomery and Smith. 20101. Throughout its history, hydraulic fracturing
6 has been used as a production technique to increase, or "stimulate," production from a well (some hydraulic
7 fracturing methods are used to stimulate production in water wells, which is outside the scope of this report).
8 The groundwork for the transformation to modern hydraulic fracturing was laid in the 1970s and early
9 1980s, when a coalition of private companies, government agencies, and industry groups began sponsoring
10 research into shale gas development technologies. During that period, Congress began to offer tax incentives
11 to induce producers to apply the developing technologies in the field [Wang and Krupnick. 2013: EIA. 2011a:
12 Yergin. 2011]. The first horizontal wells were drilled in the mid-1980s in the Austin Chalk oil-bearing
13 formation in Texas (Pearson. 2011: Haymond. 19911. Directional drilling and other emerging technologies
14 matured in the late 1990s. In 2001, the Mitchell Energy company found a way to economically fracture the
15 Barnett Shale in Texas. The company was bought by Devon Energy, a company with advanced experience in
16 horizontal drilling. In 2002, seven wells were drilled and developed in the Barnett Shale using both horizontal
17 drilling and hydraulic fracturing. Fifty-five more wells were completed in 2003 [Yergin. 2011]. The
18 techniques were rapidly adopted and further developed by others. By 2003/2004, modern hydraulic
19 fracturing in the Barnett Shale was producing more gas than all other shale gas wells in the rest of the country
20 (mostly shallow shale gas production in the Appalachian and Michigan Basins, see Section 2.4.1) (DOE,
21 2011b: Montgomery and Smith. 2010). By 2005, the new techniques were being used in low-permeability
22 hydrocarbon plays outside of Texas, and modern hydraulic fracturing soon became the industry standard,
23 driving the surge in U.S. production of natural gas.
24 Despite the long history of hydraulic fracturing, the culmination of technical innovations in the early 2000s
25 represent an appreciable change. These innovations have made hydraulic fracturing economical enough to
26 become standard practice in the oil and gas industry. Modern hydraulic fracturing (sometimes referred to as
27 high-volume hydraulic fracturing) is characterized by the use of long horizontal wells and higher volumes of
28 more complex mixtures of water, proppants, and chemical additives for injection as compared to earlier
29 fracturing practices. Wells are often deep and long: shale gas production wells are commonly 5,000 to 13,500
30 ft (1,524 to 4,115 m) deep with long horizontal sections of 2,000 to 5,000 ft (610 to 1,524 m) or more in
31 length. Other important advances occurred in oil and gas geophysical survey techniques (such as downhole
32 telemetry and 3D seismic imaging) (Wang and Krupnick. 2013: EIA. 2011a). Hydraulic fracturing continues to
33 be conducted in vertical production wells as well as conventional reservoirs using some of these newer
34 techniques. Modern hydraulic fracturing has made it possible to extract resources in previously untapped
3 5 hydrocarbon-bearing geologic settings, altering and expanding the geographic range of oil and gas production
36 activities.
This document is a draft for review purposes only and does not constitute Agency policy.
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Figure 2-1. Schematic cross-section of general types of oil and gas resources and the
orientations of production wells used in hydraulic fracturing.
Shown are conceptual illustrations of types of oil and gas wells. A vertical well is producing from a
conventional oil and gas deposit (right). In this case, a thin, gray confining layer serves to "trap" oil
(green) or gas (red). Also shown are wells producing from unconventional formations: a vertical
coalbed methane well (second from right); a horizontal well producing from a shale formation
(center); and a deviated well producing from a tight sand formation (left). Note: Figure not to scale.
Modified from USGS (2002) and Newell (2011).
1 Historically, oil and gas have been extracted from conventional reservoirs that develop when
2 hydrocarbons formed in deeper geologic source formations migrate until they accumulate
3 underneath an impermeable layer (see Figure 2-1). Extraction practices vary. In settings where a
4 reservoir is permeable enough and under enough pressure to yield a relatively high rate of
5 hydrocarbon flow into a well, the economic extraction of oil and/or gas may be as simple as using a
6 drilled well to enable hydrocarbons to flow to the surface under the natural pressure of the
7 reservoir. In other cases, producers may inject water and/or carbon dioxide under pressure into
8 the reservoir via one or more nearby wells to help move and enhance production of the oil and gas.
9 But essentially, producers are drawing on hydrocarbons that have already accumulated in a
10 relatively accessible form.
11 Hydraulic fracturing is one of several methods used to enhance production from oil and gas
12 reservoirs. It is distinct from other methods of hydrocarbon extraction (known generally as
13 enhanced recovery techniques) that involve injecting fluids to influence either reservoir pressure,
14 fluid viscosity, or both. The primary purpose of hydraulic fracturing is to increase the surface area
15 of the reservoir rock by creating fractures that are propped open, allowing the hydrocarbon to flow
16 from the rock through the fractures to the well and through the well up to the surface.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
1 Hydraulic fracturing, in conjunction with horizontal and directional drilling, has made it possible to
2 economically extract oil and gas from "unconventional" geologic formations (see Text Box 2-2),
3 such as the relatively low permeability shales in which oil and gas form (see Figure 2-1). With
4 modern horizontal drilling techniques, producers can, for example, drill a single well that follows
5 the contours of a relatively thin, horizontal shale formation. Such drilling allows fracturing to be
6 conducted in a long horizontal section of the well that accesses an extensive portion of the oil- or
7 gas-bearing formation. Unconventional formations include:
8 • Shales. Organic-rich black shales are the source rocks in which oil and gas form on geologic
9 timescales. Shales have very low permeability, and the hydrocarbons are contained in the
10 pore space in the shales. Some shales produce predominantly gas and others predominantly
11 oil; often there will be some coproduction of gas from oil wells and coproduction of liquid
12 hydrocarbons from gas wells (USGS. 2013a: EIA. 2011a).
13 • Tight formations. "Tight" sands (sandstones), siltstone, carbonates, etc., are relatively low
14 permeability, non-shale, sedimentary formations that can contain hydrocarbons. The
15 hydrocarbons are contained in the pore space of the formations. There is a continuum in
16 permeability between "tight" formations which require hydraulic fracturing to be produced
17 economically and sandstone (and other) formations that do not In the literature, "tight gas"
18 is generally distinguished from "shale gas," while oil resources from shale and tight
19 formations are frequently lumped together under the label "shale oil" or "tight oil"
20 fSchlumberger. 2014: USGS. 2014al
21 • Coalbeds. Hydraulic fracturing can be used to extract methane (the primary component of
22 natural gas) from coal seams. In coalbeds, the methane is adsorbed to the coal surface
23 rather than contained in pore space or structurally trapped in the formation. Pumping the
24 injected and formation water out of the coalbeds after fracturing serves to depressurize the
25 coal, thereby allowing the methane to desorb and flow into the well and to the surface
26 (USGS. 2000).
Text Box 2-2. "Conventional" Versus "Unconventional."
27 The terms "conventional" and "unconventional" are widely used in the literature to distinguish types of oil
28 and gas reservoirs, plays, wells, production techniques, and more. In this report, the terms are used to
29 distinguish different types of hydrocarbon resources: "conventional" resources are those that can
30 economically be extracted using long-established technologies, and "unconventional" resources are those
31 whose extraction has become economical only with the advances that have occurred in modern hydraulic
32 fracturing (often coupled with directional drilling) in recent years.
33 Note that as modern hydraulic fracturing has become industry standard, the word "unconventional" is less
34 apt than it once was to describe these resources. In a sense, "the unconventional has become the new
35 conventional" (NETL, 2013).
36 Although the goal of stimulation by hydraulic fracturing is the same wherever it is employed, the
37 way it is accomplished varies due to a number of factors. General location and geologic conditions,
This document is a draft for review purposes only and does not constitute Agency policy.
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1 whether the well is existing or newly drilled, the proximity of the well to infrastructure and raw
2 materials, operator preferences, and other factors can affect how a hydraulic fracturing operation is
3 designed and carried out Technological advances have made it possible to drill deeper and longer
4 horizontal wells, to conduct fracturing through longer portions of the well, and to place multiple
5 wells on a single well pad [NETL. 2013: Montgomery and Smith. 2010]. Many facets of hydraulic
6 fracturing-related technology have changed since they were first pioneered (see Text Box 2-1). How
7 hydraulic fracturing is practiced now (especially in the long horizontal wells) is different from how
8 it was conducted during the first decades of its use. As operators gain experience with both
9 evolving and new technologies, practices will continue to change.
10 The following three maps show the locations of major shale oil and gas resources, tight gas
11 resources, and coalbed methane resources, respectively, in the continental United States (see
12 Figure 2-2, Figure 2-3, and Figure 2-4). These maps represent resources that are being exploited
13 now or could be exploited in the future. Hydraulic fracturing continues to be used to enhance
14 production in conventional reservoirs (not shown), although it is uncertain how often this occurs.
15 The formations hydraulically fractured for gas or oil vary in their depth below the surface. For
16 example, the Marcellus Shale (found primarily in Pennsylvania, New York, and West Virginia) is
17 found at depths of 4,000 to 8,500 ft (1,200 to 2,600 m), the Barnett Shale (Texas) is found at depths
18 of 6,500 to 8,500 ft (2,000 to 2,600 m), andthe Haynesville-Bossier Shale (Louisiana and Texas) is
19 found at depths of 10,500 to 13,500 ft (3,200 to 4,100 m) fNETL. 20131 These represent some of
20 the largest gas-producing shale formations or shale plays. However, some other plays are
21 shallower. Parts of the Antrim (Michigan), Fayetteville (Arkansas), and New Albany (Indiana and
22 Kentucky) shale plays, for example, are less than 2,000 ft (600 m) deep (NETL. 2013: GWPC and
23 ALL Consulting. 2009). Exploitation of thin coal seams often takes place close to the surface as well.
24 In the San Juan Basin (New Mexico), coal seams are 550 to 4,000 ft (170 to 1,200 m) deep; in the
25 Powder River Basin (Wyoming and Montana) they are 450 to greater than 6,500 ft (140 to 2,000 m)
26 deep, and in the Black Warrior Basin (Alabama and Mississippi) depths can range from the ground
27 surface to 3,500 ft (1,100 m) (ALL Consulting. 2004). See Chapter 6 for more information on the
28 depths of these formations and plays.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
Lower 48 states shale plays
fcSS±»tioR^
BMHI
Conasauge
Fbl« * "ftis*
_ . fcwn Haynesville-
B,Iim-n Bossier TS-L*-*-'S s^i Ba»m
Figure 2-2. Shale gas and oil plays in the lower 48 United States.
Source: EIA(2015b).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
Major Tight Gas Plays, Lower 48 States
Figure 2-3. Tight gas plays in the lower 48 United States.
Source: EIA(2011b).
Coalbed Methane Fields, Lower 48 States
«Coo»Ba>
flew
if
&
W*: ^
"'BUCK MtM^ i $3™ ^°a^
i Basin
•Irwtt I
V VBnn V
1^-SW CO«M•."
iPi *•!«!,; zi
r«,-x
Source Energy I
Updated April 8. 200&
data from USGS and vanous pubfestied s
Figure 2-4. Coalbed methane fields in the lower 48 United States.
Source: EIA(2011b).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
2.1. Hydraulic Fracturing and the Life of a Well
1 Hydraulic fracturing itself is a relatively short-term process, with the timeframe for a typical
2 fracturing treatment being two to 10 days during which fluids are injected into the well to fracture
3 the oil- and gas-bearing geologic formations [Halliburton. 2013: NYSDEC. 2011). However, it is a
4 period of intense activity— the most activity that takes place at a well site during its existence.
5 In this section, we briefly describe some of the supporting and ancillary activities that take place at
6 the well site, from initial site development through production and ultimately to closure (see Figure
7 2-5). This time period likely ranges from years to decades, depending on factors such as rate of
8 depletion of the oil or gas, cost of production, and the price of oil and gas. The rate of oil and gas
9 depletion in the reservoir is somewhat uncertain in unconventional formations because there is
10 relatively little history on which to base predictions.
11 The overview of well operations presented in this section is broad and is provided to illustrate
12 common activities and describe some specific operational details. The details of well preparation,
13 operations, and closure vary from company to company, from play to play, from jurisdiction to
14 jurisdiction, and from well to well. The various activities involved in well development and
15 operations can be conducted by the well owner and/or operator, owner/operator representatives,
16 service companies, or other third parties contractors working for the well owner.
3 OUT years
Site assessment
and development
• Surveys, core
sampling, and
test well logging
• Permitting
• Road, well pad,
and pit
construction
==^
Well drilling and
construction
• Drillingand
installation of
casing and
cement
"-- -_.
Hydraulic fracturing
• Setup of water tanks,
pumps, blenders,
command center, and
other equipment on site
• Transport of water,
chemicals, and
proppantto site
• Well preparation,
including perforation, if
necessary
• Injection of fracturing
fluids in multiple stages
• Removal of equipment
Fluid recovery and Oil and Gas
management Production
• Recovery, storage, • Capture of oil
treatment, and/or gas
and/or reuse, or
disposal of
wastewater
Site and well
closure
• Well plugging
• Site
reclamation
Figure 2-5. Generalized timeline and summary of activities that take place during the
operational phases of an oil or gas well site operation in which hydraulic fracturing
is used.
Relative duration of phases is approximate.
This document is a draft for review purposes only and does not constitute Agency policy.
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2.1.1. Site and Well Development
1 Numerous activities occur to assess and develop the site and to drill and construct the production
2 well before hydraulic fracturing and production can occur.
2.1.1.1. Site Assessment and Development
3 Identifying a geologically suitable well site requires integrating data from geophysical surveys
4 (including seismic surveys) that help to delineate subsurface features with other geologic
5 information from rock core samples. Cores may be obtained while drilling exploratory wells or test
6 holes. Core samples provide firsthand information on the characteristics of the oil- or gas-bearing
7 formation, such as porosity, permeability, and details about the quantities and qualities of the
8 hydrocarbon resource. Drilling rates and drill cuttings help identify the strata being drilled through
9 and can help confirm and correlate stratigraphy and formation depths, including the depths of
10 water-bearing formations.1 Well logging (also known as wireline logging) is especially useful
11 combined with core analysis for understanding the properties of formations (Kundert and Mullen,
12 2009).2
13 Logistical factors involved in the selection of the well drilling site include topography; proximity to
14 facilities such as roads, pipelines, and water sources; well spacing considerations; well setback
15 requirements; potential for site erosion; location relative to environmentally sensitive areas; and
16 proximity to populated areas (Drohan and Brittingham. 2012: Arthur etal.. 2009a). Before
17 developing the site and initiating well drilling, the oil and gas company (or their representative)
18 obtains a mineral rights lease, negotiates with landowners, and applies for a drilling permit from
19 the appropriate state and local authorities. During the project, leases and permissions are also
20 needed for other activities including performing seismic surveys and drilling exploratory holes
21 (Hyne. 2012). This initial site assessment phase of the process may take several months (King.
22 2012).
23 Site preparation is necessary to enable equipment and supplies to reach the well area. Typically, the
24 site is surveyed first, and then an access road may need to be built to accommodate truck traffic
25 (Hyne. 2012). The operator then levels and grades the site to manage drainage and to allow
2 6 equipment to be hauled to and placed on site. Next, the operator may excavate and grade several
27 impoundments or storage pits near the well pad. In some cases, steel tanks may be used to hold
2 8 fluids instead of, or in addition to, pits. The pits may hold water intended for drilling fluids,
29 materials generated during drilling such as used drilling mud and drill cuttings, or the flowback and
30 produced waters after fracturing (Hyne. 2012). Pit construction is generally governed by local
31 regulations; federal regulations may also apply on federal and Indian Country. In some areas,
32 regulations may require pits to be lined to prevent fluid seepage into the shallow subsurface or may
1 Drill cuttings are ground rock produced by the drilling process.
2 Well logging consists of a continuous measurement of physical properties in or around the well with electrically
powered instruments to infer formation properties. Measurements may include electrical properties (resistivity and
conductivity), sonic properties, active and passive nuclear measurements, measurements of the wellbore, pressure
measurement, formation fluid sampling, sidewall coring tools and others. Measurements may be taken via a wireline,
which is a wire or cable that is used to deploy tools and instruments downhole and that transmits data to the surface.
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1 prohibit pits altogether. Some sites have piping along the surface of the well pad or in the shallow
2 subsurface that delivers water used for hydraulic fracturing, removes flowback and produced
3 water, or transports the oil and gas once production begins [Arthur etal.. 2009a).
4 After site and well pad preparation, drill rigs and associated equipment (e.g., the drill rig platform,
5 drilling mud system components, generators, chemical storage tanks, blowout preventer, fuel
6 storage tanks, cement pumps, drill pipe, and casing) are moved on and off the pad at the different
7 stages of well drilling and completion. During drilling and completion, well pads can range in size
8 from less than an acre to several acres depending on the scope of the operations [King. 2012:
9 NYSDEC. 20111.
10 Well Drilling and Construction
11 Construction of the production well involves the drilling of the hole (or wellbore), along with the
12 installation and cementing of a series of casing strings to support the wellbore and isolate and
13 protect both the hydrocarbons being produced and any water-bearing zones through which the
14 well passes.1 In certain settings, some portions of the well can be completed as open holes.2 Details
15 on these and other well construction activities are presented in Chapter 6 and Appendix D.
16 The operator begins drilling by lowering and rotating the drill string, which consists of the drill bit,
17 drill pipe (see Figure 2-6), and drill collars (heavy pieces of pipe that add weight to the bit). The
18 drill pipe attaches to the drill bit, rotating and advancing the bit; as drilling advances, new sections
19 of pipe are added at the surface, enabling the drilling to proceed deeper (Hyne. 2012). A drilling
20 fluid is circulated during drilling.3 The drilling fluid, which may be water-based or oil-based, is
21 pumped down to the drill bit, where it cools and lubricates the drill bit, counterbalances downhole
22 pressures, and lifts the drill cuttings to the surface (King. 2012).
23 Although all wells are initially drilled vertically, finished well orientations include vertical, deviated,
24 and horizontal. The operator selects the well orientation that will provide access to the targeted
25 zone(s) within a formation and that will align the well with existing fractures and other geologic
26 structures to optimize production. Deviated wells may be "S" shaped or continuously slanted.
27 Horizontal wells have lateral sections oriented approximately 90 degrees from the vertical portion
28 of the well. In wells completed horizontally, the lengths of these laterals can range from 2,000 to
29 5,000 ft (610 to 1,524 m) or more (Hyne. 2012: Miskimins. 2008: Bosworthetal.. 1998).4
30 Horizontal wells are instrumental in accessing productive areas of thin and laterally extensive oil-
31 and gas-bearing shales. Although the portion of hydraulically fractured wells that are horizontal is
32 growing, in some areas, such as California, hydraulic fracturing is still primarily conducted in
33 vertical wells fCCST. 20151.
1 Casing is steel pipe that is lowered into a wellbore. Casing extends from the bottom of the hole to the surface.
2 An open hole completion is a well completion that has no casing or liner set across the reservoir formation, allowing the
produced fluids to flow directly into the wellbore.
3 Drilling fluid is any of a number of liquid and gaseous fluids and mixtures of fluids and solids (as solid suspensions,
mixtures, and emulsions of liquids, gases, and solids) used when drilling boreholes [Schlumberger. 2014).
4 A lateral is a horizontal section of a well.
This document is a draft for review purposes only and does not constitute Agency policy.
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Figure 2-6. Pulling drill pipe onto the drilling platform.
Source: Joshua Doubek, Wikicommons, CC-BY-SA-3.0.
1 The drilling and well construction proceeds with repeated steps (the drill string is lowered, rotated,
2 drilled to a certain depth, pulled out, and then the casing is lowered into the hole, set, and
3 cemented). Successively smaller diameters of casing are used as the hole is drilled deeper (see
4 Figure 2-7). Selection and installation of the casing strings is important for several purposes,
5 including isolating hydrocarbon reservoirs from nearby aquifers, isolating over-pressured zones,
6 and transporting hydrocarbons to the surface (Hyne. 2012). Newly installed casing strings are
7 cemented in place before drilling continues (or before the well is completed in the instance of the
8 production casing). The cement protects the casing from corrosion by formation fluids, stabilizes
9 the casing and the wellbore, and prevents fluid movement along the well between the outside of the
10 casing and wellbore (Renpu, 2011). The well can be cemented continuously from the surface down
11 to the production zone of the well. Partially cemented wells are also possible with, for example,
12 cement from the surface to some distance below the deepest fresh water-bearing formation and
13 perhaps cement across other deeper formations. Chapter 6 and Appendix D contain more details on
14 casing and cement.
This document is a draft for review purposes only and does not constitute Agency policy.
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Figure 2-7. Sections of surface casing lined up and being prepared for installation at a well site
in Colorado.
Photo credit: Gregory Oberley (U.S. EPA).
1 When drilling, casing, and cementing are finished, the well can be completed in the production zone
2 in several ways. The production casing may be cemented all the way through the production zone
3 and perforated prior to hydraulic fracturing in the desired locations. Alternatively, operators may
4 use an open hole completion, in which the casing is set just into the production zone and cemented.
5 The remainder of the wellbore within the production zone is left open with no cement [Hyne,
6 2012). Once all aspects of well construction are completed, the operator can remove the drilling rig,
7 install the wellhead, and prepare the well for stimulation by hydraulic fracturing and subsequent
8 production.
2.1.1. Hydraulic Fracturing
9 Hydraulic fracturing is typically a short, intense, repetitive process requiring specialized equipment
10 and (for high volume horizontal wells) large amounts of water, chemicals, and proppant. Machinery
11 and equipment are often brought to the site mounted on trucks and remain that way during use.
12 Tanks, totes, and other storage containers of various sizes holding water and chemicals are also
13 transported and installed on site. Figure 2-8 shows a well pad prepared for hydraulic fracturing
14 with the necessary equipment and structures.
This document is a draft for review purposes only and does not constitute Agency policy.
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Figure 2-8. Hydraulic fracturing operation in Troy, PA.
Site with all equipment on site in preparation for injection. Source: NYSDEC (2011).
2.1.1.2. Injection Process
1 Prior to injection, hydraulic fracturing fluids are mixed using specialized feeding and mixing
2 equipment The mixing is generally performed mechanically on a truck-mounted blender and is
3 electronically monitored and controlled by the operator in a separate van (see Chapter 5).
4 Numerous hoses and pipes are used to transfer hydraulic fracturing fluid components from storage
5 units to the mixing equipment and ultimately to the wellhead.
6 A wellhead assembly is temporarily installed on the wellhead during the fracture treatment to
7 allow high pressures and volumes of proppant-laden fluid to be injected into the well. Pressures
8 required for fracturing can vary widely depending on depth, formation pressure, and rock type.
9 Fracturing pressures have been reported ranging from 4,000 psi to 12,000 psi [Ciezobka and Salehi,
10 2013: Abou-Saved etal., 2011: Thompson, 2010]. The pressure during fracturing is measured using
11 pressure gauges, which can be installed at the surface and/or downhole [Ross and King. 2007).
12 Figure 2-9 shows two wellheads side-by-side being prepared for fracturing.
This document is a draft for review purposes only and does not constitute Agency policy.
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Figure 2-9. Two wellheads side-by-side being prepared for hydraulic fracturing at a well site in
Pennsylvania.
Photo credit: Mark Seltzer (U.S. EPA).
1 The entire length of the well in the production zone is not fractured all at once; instead, shorter
2 lengths or segments of the well in the production zone are isolated and fractured in "stages" [Lee et
3 al.. 2011). Each stage of a fracturing job can consist of phased injection of different fluids consisting
4 of varying components (i.e., chemicals and additives). These different fluids (1) remove excess
5 drilling fluid or cement from the formation (often using acid) (GWPC and ALL Consulting, 2009),
6 (2) initiate fractures ("pad fluid" without proppant), (3) carry the proppant (Hyne, 2012), and
7 (4) flush the wellbore to ensure that all proppant-laden fluids reach the fractures. Each phase
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1 requires moving up to millions of gallons of fluids around the site through various hoses and lines,
2 blending the fluids, and injecting them at high pressures down the well.
3 The total number of stages depends on the formation properties and the orientation and length of
4 the well. As technology has improved, the lengths of laterals in horizontal wells and the numbers of
5 stages per well have tended to increase [NETL. 2013: Pearson etal.. 2013]. The number of stages
6 per well can vary, with several sources suggesting that between 10 and 20 is typical [GNB, 2015:
7 Lowe etal.. 2013). The full range reported in the literature is much wider, with one source
8 documenting between 1 and 59 stages per well [Pearson et al., 2013] and others reporting values
9 within this range [NETL. 2013: STO. 2013: Allison etal.. 20091. For more details on hydraulic
10 fracturing stages, see Chapter 5, Section 5.2.
11 The induced fractures are designed to achieve the optimum drainage of hydrocarbons from the
12 reservoir formations. Engineers can design fracture systems using modeling software that requires
13 a significant amount of data on formation permeability, porosity, in situ stress, mineralogy, and
14 geologic barrier locations, among other factors [Holditch. 2007). Microseismic monitoring during
15 fracturing can be used to characterize the horizontal and vertical extent of the fractures created and
16 assist with the design of future fracturing jobs [Cipollaetal., 2011]. Post-fracture monitoring of
17 pressure or tracers can also help characterize the results of a fracturing job. More details of
18 injection, fracturing, and related monitoring are provided in Chapter 6 and Appendix D.
2.1.1.3. Fracturing Fluids
19 The fracturing fluids injected into the well serve a variety of purposes and require chemical
20 additives to perform properly (see Chapter 5, Section 5.3]. Depending on the geologic setting,
21 reservoir geochemistry, production type, proppant size, and other factors, operators typically
22 choose to use one of several common types of fracturing fluid systems [Arthur etal.. 2014:
23 Spellman, 2012: Gupta and Valko, 2007]. Water-based fracturing fluids are the most common, but
24 other fluid types can be used such as: foams or emulsions made with nitrogen, carbon dioxide, or
25 hydrocarbons; acid-based fluids; and others [Montgomery, 2013: Sabaetal., 2012: Gupta and
2 6 Hlidek. 2009: Gupta and Valko. 2007: Halliburton. 19881 The most common water-based fluid
2 7 systems are slickwater formulations, which are typically used in very low permeability reservoirs,
2 8 and gelled fracturing fluids, which can be used in reservoirs with higher permeability [Barati and
29 Liang. 2014).1-2 More details of hydraulic fracturing fluid systems are discussed in Section 5.3.
30 Importantly, chemical usage in the industry is continually changing as processes are tested and
31 refined by companies. Shifts in fluid formulations are driven by economics, technological
32 developments, and concerns about environmental and health impacts.
1 Slickwater is a type of fracturing fluid that consists mainly of water with a very low portion of additives like polymers
that serve as friction reducers to reduce friction loss when pumping the fracturing fluid downhole [Barati and Liang.
2014).
2 Gelled fluids are fracturing fluids that are usually water-based with added gels to increase the fluid viscosity to aid in the
transport of proppants [Spellman. 2012: Gupta and Valko. 2007).
This document is a draft for review purposes only and does not constitute Agency policy.
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1 The largest constituent of a typical hydraulic fracturing fluid is water (see Figure 2-10). The water
2 sources used for hydraulic fracturing base fluid include ground water, surface water, treated
3 wastewater, and reused flowback or produced water from other wells [URS Corporation. 2011:
4 Blauch, 2010: Kargbo etal., 2010].* The water may be brought to the production well site via trucks
5 or piping, or it may be locally sourced (for example, pumped from a local river or obtained from a
6 water well tapping local ground water). Selection of water sources depends upon availability, cost,
7 quality of the water, and the logistics of delivering it to the site. Chapter 4 provides additional
8 details on water acquisition and the amount of water used for hydraulic fracturing.
Figure 2-10. Water tanks (blue, foreground) lined up for hydraulic fracturing at a well site in
central Arkansas.
Photo credit: Martha Roberts (U.S. EPA).
9 Proppants are, by volume, second to the base fluid in the hydraulic fracturing fluid system. Silicate
10 minerals, most notably quartz sand, are the most commonly used proppants. Increasingly, silicate
11 proppants are being coated with resins that help prevent development and flowback of particles or
12 fragments of particles. Ceramic materials, such as those based on calcined (heated) bauxite or
13 calcined kaolin (mullite) are also used as proppants due to their high strength and resistance to
14 crushing and deformation (Beckwith. 2011).
1 Base fluid is the fluid into which additives and proppants are mixed to formulate a hydraulic fracturing fluid.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Additives comprise relatively small percentages of hydraulic fracturing fluid systems, generally
2 constituting <2.0% of the fluid [GWPC and ALL Consulting. 2009]. The EPA analyzed additive data
3 in the EPA FracFocus project database 1.0 and estimated that hydraulic fracturing additives in 2Oil
4 and 2012 totaled 0.43% of the total amount of fluid injected for hydraulic fracturing [U.S. EPA,
5 2015a]. Note that this small percentage can total tens of thousands of gallons of chemical additives
6 for a typical high-volume hydraulic fracturing job (see Chapter 5, Section 5.4 for details on additive
7 volumes). A given additive may consist of a single chemical ingredient, or it may have multiple
8 ingredients. The mix of chemicals used in any particular fracturing job is influenced by the
9 properties of the target formation, the amount and type of proppant that needs to be carried,
10 operator preference, and to some degree, by local or regional availability of chemicals and potential
11 interactions between chemicals [King, 2012]. Chapter 5 includes details on the number, types, and
12 estimated quantities of chemicals that can be used in hydraulic fracturing.
2.1.2. Fluid Recovery, Management, and Disposal
13 When the injection pressure is reduced atthe endofthe fracturing process, the direction of fluid
14 flow reverses, with some of the injected hydraulic fracturing fluid flowing into the well and to the
15 surface along with some naturally-occurring fluids from the production zone [NYSDEC, 2011]. The
16 fluid is initially a portion of the injected fluid, which decreases over the first few weeks or months
17 until produced water originating from the fractured oil- or gas-bearing rock formation
18 predominates. This recovery of produced water continues over the life of the well [Barbotetal..
19 2013]. Chapter 7 presents descriptions and discussions of the composition and quantities of fluids
20 recovered at the well, referred to as flowback and produced water.
21 The hydraulic fracturing flowback and produced water (sometimes referred to as hydraulic
22 fracturing wastewater], as well as any other liquid waste from the well pad itself (e.g., rainwater
23 runoff), is typically stored on-site in impoundments (see Figure 2-11] or tanks. This wastewater can
24 be moved offsite via truck or pipelines. The majority of these hydraulic fracturing wastewaters
25 nationally are managed through disposal into deep Class II injection wells regulated under the
26 Underground Injection Control (UIC] program under the Safe Drinking Water Act (see Chapter 8].
27 Other management strategies include treatment followed by discharge to surface water bodies, or
28 reuse for subsequent fracturing operations either with or without treatment (U.S. EPA. 2012f: U.S.
29 GAP. 2012]. Decisions regarding wastewater management are driven by factors such as cost
3 0 (including costs of storage and transportation], availability of facilities for treatment, reuse, or
31 disposal, and regulations (Rassenfoss. 2011]. Wastewater management is yet another aspect of
32 fracturing-related oil and gas production that is changing significantly. Chapter 8 contains details of
33 the treatment, reuse and recycling, and disposal of wastewater.
This document is a draft for review purposes only and does not constitute Agency policy.
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Figure 2-11. Impoundment on the site of a hydraulic fracturing operation in central Arkansas.
Photo credit: Caroline E. Ridley (U.S. EPA).
2.1.3. Oil and Gas Production
1 After hydraulic fracturing, equipment is removed and partial site reclamation may take place if
2 drilling of additional wells or laterals is not planned [NYSDEC. 2011]. Operators may dewater, fill
3 in, and regrade pits that are no longer needed. Parts of the pad may be reseeded, and the well pad
4 may be reduced in size (e.g., from 3 to 5 acres (1 to 2 hectares) during the drilling and fracturing
5 process to 1 to 3 acres (0.4 to 1 hectares) during production) (NYSDEC, 2011).
6 Wells may be shut-in immediately after completion if there is no infrastructure to receive the
7 product or if prices are unfavorable. Prior to bringing a well into production, the operator typically
8 runs a production test to determine the maximum flow rate the well can sustain and to optimize
9 equipment settings (Hyne. 2012: Schlumberger. 2006). Such tests may be repeated throughout the
10 life of the well. During production, monitoring (e.g., mechanical integrity testing, corrosion
11 monitoring), including any compliance with state monitoring requirements, may be conducted to
12 enable operators to be sure that the well is operating as intended.
13 In the case of gas wells, the produced gas typically flows through a flowline to a separator that
14 separates the gas from water or any liquid hydrocarbons (NYSDEC. 2011). The finished gas is sent
15 to a compressor station where it is compressed to pipeline pressure and sent to a pipeline for sale.
16 Production at oil wells proceeds similarly, although oil/water or oil/water/gas separation occurs
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1 most typically on the well pad, no compressor is needed, and the oil can be hauled (by truck or
2 train) or piped from the well pad.
3 During the life of the well it may be necessary to perform workovers to maintain or repair portions
4 or components of the well and replace old equipment Such workovers involve ceasing production
5 and removing the wellhead, and may include cleaning out sand or deposits from the well, repairing
6 casing, replacing worn well components such as tubing or packers, or installing or replacing lift
7 equipment to pump hydrocarbons to the surface [Hyne. 2012). In some cases, wells may be
8 recompleted after the initial construction, with re-fracturing if production has decreased [Vincent,
9 2011]. Recompletion also may include additional perforations in the well at a different interval to
10 produce from a different formation than originally done, lengthening the wellbore, or drilling new
11 laterals from an existing wellbore.
12 As of 2012, Shires andLev-On [2012] suggested that the rate of re-fracturing in natural gas wells
13 was about 1.6%. Analysis for the EPA's 2012 Oil and Gas Sector New Source Performance Standards
14 indicated a re-fracture rate of 1% for gas wells [U.S. EPA. 2012d]. In the EPA's Inventory of U.S.
15 Greenhouse Gas Emissions and Sinks [U.S. EPA. 2015g]. the number of gas wells that were re-
16 fractured in a given year as a percent of the total existing population of hydraulically fractured
17 producing gas wells in a given year ranges from 0.3% to 1% across the 1990-2013 period.
2.1.1.4. Production Rates and Duration
18 The production life of a well depends on a number of factors, such as the amount of hydrocarbons
19 in place, the reservoir pressure, production rate, and the economics of well operations. It may be as
20 short as three or four years in deep-water, high-permeability formations and as long as 40 to 60
21 years in onshore tight gas reservoirs [Ross and King. 2007). In hydraulically fractured wells in
22 unconventional reservoirs, production is often characterized by a rapid drop followed by a slower
23 decline compared to conventional hydrocarbon production wells [Patzeketal., 2013]. However,
24 most modern, high-volume fractured wells are less than a decade old. Consequently, there is a
25 limited historical basis to determine the full extent of the production decline [Patzeketal., 2013]
2 6 and to ultimately determine how much they will produce.
2.1.4. Site and Well Closure
2 7 Once a well reaches the end of its useful life, it is plugged, and the well site is closed. If a wellbore is
2 8 not properly plugged, fluids from higher pressure zones may eventually migrate through the
29 wellbore to the surface or to other zones such as fresh water aquifers [NPC, 2011b]. Plugging is
30 usually performed according to state regulations governing the locations and materials for plugs
31 [Calvertand Smith, 1994]. Operators typically use cement plugs placed across fresh water
32 formations and oil or gas formations [NPC. 2011b]. Some surface structures can be left in place, and
3 3 the local topography and land cover are restored to predevelopment conditions to the extent
34 possible, per state regulations. The wellhead and any surface equipment are removed.
3 5 Impoundments are dewatered, filled in, and graded. The well casing is typically cut off below the
36 surface and a steel plate or cap is emplaced to seal the top of the casing and wellbore [API, 2010a],
37 although there may also be an aboveground marker used in some locations. Some states require
3 8 notification of the landowner or a government agency of the location of the well.
This document is a draft for review purposes only and does not constitute Agency policy.
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2.2. How Widespread is Hydraulic Fracturing?
1 Hydraulic fracturing activity in the United States and worldwide is substantial. One industry
2 cumulative estimate stated that by the time of writing in 2010, close to 2.5 million fracture
3 treatments had been performed globally [Montgomery and Smith. 2010). In 2002, the Interstate Oil
4 and Gas Compact Commission (IOGCC) stated that close to 1 million wells had been hydraulically
5 fractured in the United States since the 1940s [IOGCC. 20021. A recent U.S. Geological Survey
6 (USGS) publication analyzed 1 million hydraulically fractured wells and 1.8 million hydraulic
7 fracturing treatment records from the United States from 1947 to 2010 [USGS. 2015). Although
8 some form of hydraulic fracturing has been used for more than 60 years, the technological
9 advancements that combined hydraulic fracturing and directional drilling in the early 2000s
10 resulted in the new era of modern hydraulic fracturing, which uses higher volumes of fracturing
11 fluids than were typically used in prior decades. Modern hydraulic fracturing is typically associated
12 with horizontal wells producing from unconventional shale reservoirs, but hydraulic fracturing
13 continues to be done in vertical wells in conventional reservoirs also. This ongoing mix of
14 traditional and modern hydraulic fracturing activities makes estimates of the total number of
15 hydraulic fracturing wells challenging.
16 The following series of images illustrates hydraulic fracturing activities and the scale of those
17 activities in the United States. Figure 2-12 (taken in Springville Township, in northeastern
18 Pennsylvania) and Figure 2-13 (taken near Williston, in northwestern North Dakota) show
19 individual well pads in the context of the local landscape. Landsat images in Figure 2-14 and Figure
20 2-15 provide satellite views of areas in northwest Louisiana and southeast Wyoming, respectively,
21 where hydraulic fracturing activities currently occur as identified by the well pads in the images.
22 These images serve to illustrate activity at a wider scale, though they are not representative of all
23 hydraulic fracturing activities in the eastern or western United States. The light red circles around
24 some of the well pads identify them as hydraulic fracturing wells that were reported by well
25 operators to the FracFocus registry (as summarized in the EPA FracFocus project database 1.0)
26 (U.S. EPA. 2015b). (The FracFocus well locations reflect information in the EPA FracFocus project
27 database for well operations reporting hydraulic fracturing activities between January 2011 and
28 February 2013. The Landsat images are from a later period, July and August of 2014, so additional
29 well pads in the images now may be represented in the FracFocus registry.)
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
Figure 2-12. Aerial photograph of a well pad and service road in Springville Township,
Pennsylvania.
Image © T Henry Fair / Flights provided by LightHawk.
Figure 2-13. Aerial photograph of hydraulic fracturing activities near Williston, North Dakota.
Image © T Henry Fair / Flights provided by LightHawk.
This document /s a draft for review purposes only and does not constitute Agency policy.
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Hydraulic fracturing
; wells reported to
FracFocus
Figure 2-14. Landsat photo showing hydraulic fracturing well sites near Frierson, Louisiana.
Source: Imagery from USGS Earth Resources Observation and Science, Landsat 8 Operational Land
Imager (scene LC80250382014232LGNOO) captured August 20, 2014 and accessed on May 1, 2015
from USGS's EarthExplorer (http://earthexplorer.usgs.gov/).
Inset imagery from USDA National Agriculture Imagery Program (entity M 3209351_NE
15_1_20130703_20131107) captured July 3, 2013 and accessed May 1, 2015 from USGS's
EarthExplorer (http://earthexplorer.usgs.gov/).
FracFocus well locations are from the EPA FracFocus project database 1.0 (U.S. EPA, 2015b).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
Hydraulic fracturing
O wells reported to
FracFocus
1 Miles
/
Figure 2-15. Landsat photo showing hydraulic fracturing well sites near Pinedale, Wyoming.
Source: Imagery from USGS Earth Resources Observation and Science, Landsat 8 Operational Land
Imager (scene LC80370302014188LGNOO) captured July 7, 2014 and accessed May 1, 2015 from
USGS's EarthExplorer (http://earthexplorer.usgs.gov/).
Inset imagery from USDA National Agriculture Imagery Program (entity M 4210927_NW
12_1_20120623_20121004) captured June 23, 2012 and accessed May 1, 2015 from USGS's
EarthExplorer (http://earthexplorer.usgs.gov/).
FracFocus well locations are from the EPA FracFocus project database 1.0 (U.S. EPA, 2015b).
1 The maps in Figure 2-16 show recent changes nationally in the geography of oil and gas production
2 through the increased use of horizontal drilling, which occurs together with hydraulic fracturing.
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1 Some traditional oil- and gas-producing parts of the country, such as Texas, have seen an expansion
2 of historically strong production activity as a result of the deployment of horizontal drilling and
3 modern hydraulic fracturing. Pennsylvania, a century ago one of the leading oil- and gas-producing
4 states, has seen a resurgence in oil and gas activity. Other states currently experiencing a steep
5 increase in production activity, such as North Dakota, Arkansas, and Montana, have historically
6 produced less oil and gas and are therefore undergoing new development.
2000
2005
2012
New well locations in
select years (number
of wells)
• 2000 (341)
• 2005 (1,809)
• 2012 (14,560)
EIA shale basins
Figure 2-16. Location of horizontal wells that began producing oil or natural gas in 2000, 2005,
and 2012, based on data from Drillinglnfo (2014a).
This document is a draft for review purposes only and does not constitute Agency policy.
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2.2.1. Number of Wells Fractured per Year
1 We estimate that from roughly 2011 to 2014, approximately 25,000 to 30,000 new oil and gas wells
2 were hydraulically fractured each year. Additional, pre-existing wells (wells more than one year old
3 that may or may not have been hydraulically fractured in the past) were also likely fractured each
4 year. Since the early 2000s, the percentage of all hydraulically fractured wells that are either
5 horizontal or deviated has steadily grown. Our estimates are based on data detailed below from
6 several public and private sector organizations that track drilling and various aspects of hydraulic
7 fracturing activity. There is no complete database or registry of wells that are hydraulically
8 fractured in the United States. Another source of uncertainty is the rate at which relatively new
9 hydraulic fracturing wells are re-fractured or the rate at which operators use older, existing wells
10 for hydraulic fracturing. Future trends in the number of wells hydraulically fractured per year will
11 be affected by the cost of well operation and the price of oil and gas. Scenarios of increasing, flat,
12 and decreasing hydraulic fracturing activity all appear to be possible [Weijermars. 2014).
13 The number of wells reported to the FracFocus registry provides a low estimate of the number of
14 hydraulically fractured wells.x As of early April 2015, the FracFocus registry reported receiving
15 information on a cumulative total of approximately 95,000 fracturing jobs, or roughly 22,400 per
16 year over the 51-month period from January 2011 through March 2015 [GWPC. 2015]. In a more
17 detailed review of FracFocus data from 2011 and 2012, the EPA found there were approximately
18 14,000 and 22,500 fracturing jobs reported to the FracFocus website in those years, respectively,
19 across 20 states fU.S. EPA. 2015a). These 2011 and 2012 numbers are likely underestimates of
2 0 wells hydraulically fractured annually, in part because FracFocus reporting was voluntary for most
21 states for at least a portion of 2011 to 2012 (though the increase from 2011 to 2012 in part reflects
22 more states requiring reporting to the registry). Hydraulic fracturing practices may alternately (or
23 in addition to FracFocus) be tracked by states. Compared to state records of hydraulic fracturing
24 from North Dakota, Pennsylvania, and West Virginia in 2011 and 2012, we found thatthe count of
25 wells based on records submitted to FracFocus was an underestimate of the number of fracturing
26 jobs in those states by an average of approximately 30% (see Text Box 4-1).
27 An additional estimate of the number of hydraulically fractured wells can be obtained from
28 Drillinglnfo, a commercial database compiling data from individual state oil and gas agencies
29 (Drillinglnfo. 2014a). The data indicate an increase in the number of new hydraulically fractured
30 wells drilled each year, from approximately 12,800 in 2000 to slightly more than 21,600 in 2005, to
31 nearly 23,000 in 2012. The number of new horizontal wells (which are likely all hydraulically
32 fractured) show a significant increase, from 344 (about 1% of all new production wells) in 2000, to
33 1,810 in 2005, to 14,560 (nearly 41% of all new production wells) in 2012 (see Figure 2-16).
1 The FracFocus registry was developed by the Ground Water Protection Council and the Interstate Oil and Gas Compact
Commission. Oil and gas well operators can use the FracFocus registry to disclose information about hydraulic fracturing
well locations, and water and chemical use during hydraulic fracturing operations. Submission of information to
FracFocus was initially voluntary (starting in January 2011), but now about half of the 20 states represented in FracFocus
have enacted reporting requirements for well operators that either mandate reporting to FracFocus or allow it as one
reporting option. FracFocus data are discussed in more detail in Chapter 4 (regarding water volumes) and Chapter 5
(regarding chemical use). For more information see www.fracfocus.org and U.S. EPA(2015a).
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Because Drillinglnfo data do not directly report whether a well has been hydraulically fractured, we
2 relied on properties of the well and the oil or gas producing formation to infer which wells were
3 hydraulically fractured and when. First, we assumed that all horizontal wells were hydraulically
4 fractured in the year they started producing. Second, we assumed that all wells within a shale,
5 coalbed, or low-permeability formation, regardless of well orientation, were hydraulically fractured
6 in the year they started producing.*
7 We used well-specific data provided by oil and gas well operators to the EPA to supplement our
8 estimates of hydraulic fracturing using Drillinglnfo data [U.S. EPA, 2015o]. Matching wells in each
9 dataset using API well numbers, we found that 80% of 171 newly drilled wells known to be
10 fractured in 2009 and 2010 according to their well files were correctly identified as fractured using
11 well and formation properties in Drillinglnfo.2 We did not correctly identify all of the vertical or
12 deviated wells that were known to be fractured. (We were unable to identify wells for which
13 hydraulic fracturing was inferred using the properties in Drillinglnfo but were not fractured.) This
14 comparison suggests thatthe estimates of hydraulically fractured wells from Drillinglnfo are likely
15 underestimates.
16 Another source of estimates is from a U.S. Geological Survey publication that reviewed data from
17 the commercial IHS database of U.S. oil and gas production and well data [USGS. 2015]. The study
18 period was from 1947 through 2010. The authors estimated a total of approximately 277,000
19 hydraulically fractured wells between 2000 and 2010 (compared to close to 212,000 during the
20 same time period estimated based on Drillinglnfo data). This is roughly 25,000 wells per year over
21 that time period. Approximately three-quarters of these wells were vertical. Reflecting advances in
22 directional drilling technology over the decade ending in 2010, the percentage of total wells
23 fractured that were horizontal or deviated wells grew from less than 10% to over 60%.
24 Well counts tracked by Baker Hughes provide another estimate of new wells fractured annually.
25 Since 2012, this oilfield service company has published a quarterly count of new we 11s spudded; it
26 includes only new inland U.S. wells "identified to be significant consumers of oilfield services and
27 supplies."3 A reported total of 36,824 oil and gas wells were spudded in the United States in 2012,
28 with new wells per quarter fluctuating between about 8,500 and 9,500 (Baker Hughes, 2014b).
29 While 100% of new wells are probably not hydraulically fractured (see below for estimates of
3 0 hydraulic fracturing rates in new wells), a count of new wells also does not include hydraulic
31 fracturing taking place in older, existing wells.
1 The assignment of formation type (shale, coalbed, low-permeability, or conventional) for each well was based on a
crosswalk of information on basin/play provided in Drillinglnfo f2014a) with expert knowledge of those basins/plays at
EIA f2012a). If formation type could not be determined, it was considered conventional by default. This is similar
methodology to that used by the EPA for its greenhouse gas inventory [U.S. EPA. 2013c).
2 An API well number is a unique identifying number given to each oil and gas well drilled in the United States. The system
was developed by the American Petroleum Institute.
3 To spud a well is to start the well drilling process by removing rock, dirt, and other sedimentary material with the drill
bit.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Data collected under the EPA's Greenhouse Gas Reporting Program (GHGRP) provide information
2 on completions and workovers with hydraulic fracturing (i.e., re-fracturing) of gas wells. Data
3 reported to GHGRP for years 2011 to 2013 suggest that 9-14% of the gas wells reported to be
4 hydraulically fractured in each year were pre-existing wells undergoing re-fracturing [U.S. EPA,
5 20146].1 The GHGRP requirements do not include reporting of re-fracturing in oil wells, and other
6 data sources for information specifically on re-fracturing of existing oil wells compared to initial
7 fracturing of oil wells were not identified. For comparison, an EPA survey of an estimated 23,200 oil
8 and gas production wells that were hydraulically fractured by nine oil and gas service companies in
9 2009 and 2010 suggests that 42% of the wells were pre-existing (i.e., more than one year old) when
10 they were hydraulically fractured (U.S. EPA, 2015o). Differences in data (including data from
11 different years and data from gas wells only (GHGRP) versus oil and gas wells, for instance),
12 definitions, and assumptions used to estimate the percentage of pre-existing wells hydraulically
13 fractured in a year could account for the different results.
14 In summary, determination of the national scope of hydraulic fracturing activities in the United
15 States is complicated by a lack of a centralized source of information and the fact that well and
16 drilling databases each track different information. There is also uncertainty about whether
17 information sources are representative of the nation, whether they include data for all production
18 types, whether they represent only modern (high volume) hydraulic fracturing, and whether they
19 include activities in both conventional and unconventional reservoirs. Taking these limitations into
20 account, however, it is reasonable to assume that between approximately 25,000 and 30,000 new
21 wells (and, likely, additional pre-existing wells) were hydraulically fractured each year in the
2 2 United States from about 2 011 to 2 014.
2.2.2. Hydraulic Fracturing Rates
2 3 Estimates of hydraulic fracturing rates, or the proportion of all oil and gas production wells that are
24 associated with hydraulic fracturing, also indicate widespread use of the practice. Based on an
25 assessment described above of data from Drillinglnfo (2014a), hydraulic fracturing rates have
26 increased over time. From 2005 to 2012, rates of hydraulic fracturing increased from 57% to 64%
27 of all new production wells (including oil wells, gas wells, and wells producing both oil and gas).
28 In 2009, industry consultants stated that hydraulic fracturing was used on nearly 79% of all wells
29 and more than 95% of "unconventional" wells (IHS, 2009). A 2010 article in an industry publication
3 0 noted "some believe that approximately 60% of all wells drilled today are fractured" (Montgomery
31 and Smith. 2010). Of 11 important oil and gas producing states that responded to anIOGCC survey
32 (Arkansas, Colorado, Louisiana, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas,
3 3 Utah, and West Virginia), ten estimated that 78% to 99% of new oil and gas wells in their states
34 were hydraulically fractured in 2012; Louisiana was the one exception, reporting a fracturing rate
35 of 3.9% in 2012 (IOGCC. 2015). Although estimates of fracturing rates are variable, largely ranging
36 from near 60% to over 90% (as described above), they are often higher for gas wells than they are
37 for oil wells. A2010to2011 industry survey of 20 companies involved in natural gas production
1 The GHGRP reporting category that covers re-fracturing is "workovers with hydraulic fracturing."
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
1 found that 94% of the wells that they operated were fractured; among those, roughly half were
2 vertical and half were horizontal [Shires and Lev-On. 2012].
2.3. Trends and Outlook for the Future
3 Fossil fuels are the largest source of all energy generated in the United States. They currently
4 comprise approximately 80% of the energy produced [EIA. 2014Q. However, the mix of fossil fuels
5 has shifted in recent years. Coal, the leading fossil fuel produced by the U.S. since the 1980s, has
6 experienced a significant decrease in production. In 2007, coal accounted for approximately 33% of
7 U.S. energy production, and by 2013 it decreased to approximately 24% [EIA, 2014F). On the other
8 hand, natural gas production has risen to unprecedented levels, and oil production has resurged to
9 levels not seen since the 1980s (see Figure 2-17). Oil went from accounting for 15% of U.S. energy
10 production to 19% between 2007 and 2013, and natural gas (both dry and liquid) went from 31%
11 to 35% (EIA. 2014Q.
12 Below, we discuss recent and projected shifts in oil and natural gas production that can primarily
13 be attributed to hydraulic fracturing and directional drilling technologies.
2.3.1. Natural Gas (Including Coalbed Methane)
14 Natural gas production in the United States peaked in the early 1970s, reached those levels again in
15 the mid-1990s, and between the mid- to late-2000s has increased to even higher levels (see Figure
16 2-17). The recent increase in total gas production has been driven almost entirely by shale gas (see
17 Figure 2-18).
18 As natural gas prices fell between 2008 and 2012 (EIA. 2014e). drilling of new natural gas wells
19 declined markedly (EIA, 2014g] (see Figure 2-19). Nevertheless, natural gas production is expected
20 to increase over the coming decades (see Figure 2-18). EIA(2013b] predicts that shale gas
21 production will more than double between 2011 and 2040 and that the portion of total natural gas
22 production represented by shale gas will increase from one-third to one-half. The EIA projects
23 steady growth in the development of tight gas as well (about a 25% increase in production over the
24 30-year period) and delayed growth in the development of coalbed methane resources, for which
25 production is not expected to increase again until sufficiently high natural gas prices are realized
26 around 2035. Overall, the EIA projects thatthe share of U.S. natural gas production from shales,
27 tight formations, and coalbeds will increase from 65% in 2011 to nearly 80% in 2040.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
or
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o
15
— — — U.S. Natural Gas Gross Withdrawals (trillion cubic feet)
U.S. Field Production of Crude Oil (billion barrels)
Figure 2-17. Trends in U.S. oil and gas production.
Source: EIA (2013d) and EIA(2014d).
History
2012
Projections
1990 2000 2010 2020 2030 2040
Figure 2-18. Historic and projected natural gas production by source (trillion cubic feet).
Source: EIA(2014a).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
U.S. Natural Gas Wellhead Price (Dollars per Thousand Cubic Feet)
— — — U.S. Natural Gas Rotary Rigs in Operation (Count)
^^^U.S. Crude Oil Rotary Rigs in Operation (Count)
Figure 2-19. Natural gas prices and oil and gas drilling activity, 2008-2012.
Source: EIA(2014e). EIA(2014g). and EIA(2013b).
1 Shale gas production varies by play (see Figure 2-20a). Until 2010, the Texas Barnett Shale was the
2 play with the most production. Although production from the Barnett Shale is still significant,
3 production has increased sharply in other plays. By 2012, production from the Haynesville play (on
4 the Louisiana/Texas border) surpassed that in the Barnett play, and by 2013 the Marcellus Shale
5 (in the Appalachian Basin underlying Pennsylvania, West Virginia, and other states) was the play
6 with the most production. Because technically recoverable resources are an order of magnitude
7 higher in the Marcellus than in any other U.S. shale gas play, it is likely that the Marcellus Shale will
8 be very active in shale gas production for the foreseeable future (EIAJ_2fllla).1
9 In the 1970s, most tight gas production in the United States was in the San Juan Basin centered in
10 New Mexico. As modern hydraulic fracturing came into common usage in the mid-2000s, the lead in
11 tight gas production shifted to Texas (especially East Texas) and the Rocky Mountain states (Vidas
12 and Hugman. 20081
1 Technically recoverable resources represent the volumes of oil and natural gas that could be produced with current
technology, regardless of oil and natural gas prices and production costs [EIA. 2013c).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
U.S. dry shale gas production
billion cubic feet per day
• Marcel I us (PA & WV)
• Haynesville(LA&TX)
• Eagle Ford (TX)
• Fayetteville(AR)
• Barnett (TX)
• Woodford (OK)
Bakken (ND)
• Antrim (Ml, IN, & OH)
• Utica(OH, PA&VW)
Rest of US 'shale'
40
35
30
25
20
15
10
i Eagle Ford (TX)
Bakken (MT&ND)
i Spraberry (TX & NM Permian)
• Bonespring (TX & NM Permian)
Wolfcamp (TX & NM Permian)
Delaware (TX & N M Permian)
Yeso-Glorieta (TX & NM Permian)
Niobrara-Codell (CO, WY)
iHaynesville
iUtica(OH, PA&WV)
• Marcellus
i Woodford (OK)
Granite Wash (OK & TX)
i Austin Chalk (LA &TX)
Monterey (CA)
U.S. tight oil production
million barrels of oil per day
4.5
0.0
<£>
(a)
(b)
Figure 2-20. (a) Production from U.S. shale gas plays, 2000-2014, in billion cubic feet per day;
(b) Production from U.S. tight oil plays, 2000-2014.
Tight oil includes oil from shale and other tight formations, plus lease condensate from natural gas
production. Source: EIA(2012c).
1 Modern coalbed methane production techniques were pioneered in the Black Warrior Basin in
2 Alabama and in the San Juan Basin [Vidas and Hugman. 2008]. With the use of hydraulic fracturing,
3 most coalbed methane production in the United States now comes from the San Juan Basin and
4 from Rocky Mountain Basins (e.g., the Uinta-Piceance Basin in Colorado and Utah and the Powder
5 River Basin centered in Wyoming) [Vidas and Hugman, 2008].
2.3.2. Oil
6 The EIA data indicate that as drilling activity for natural gas declined between 2008 and 2012,
7 drilling for oil increased by a similar order of magnitude (see Figure 2-19]. Figure 2-21 shows past
8 and projected future trends in U.S. oil production and importation (EIA. 2013a]. Note that this
9 graph shows production and importation in millions of barrels (bbl] per day. The current surge in
10 tight oil production is expected to continue until the latter part of the current decade and then
11 taper, while conventional oil production is projected to remain fairly level. However, downward
12 trends in the price of oil since mid-2014 are not reflected in these projections.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
Historic
2012
Projected
1970
1980
1990
2000
2010
2020
2030
Net Petroleum &
Biofuel Imports
Other
Natural Gas
Plant Liquids
17% Tight Oil
Production
Crude Oil Production
23% (Excluding Tight Oil)
2040
Figure 2-21. U.S. petroleum and other liquid fuels supply by source, past and projected future
trends (million barrels per day).
Source: EIA(2013a).
1 Like shale gas production, tight oil production varies by play (Figure 2-20b). The Bakken Shale play,
2 centered in western North Dakota, is important for shale oil production with production increasing
3 from 123 million bbl (20 billion L) in 2011 to 213 million bbl (34 billion L) in 2012. Proved reserves
4 in the Bakken have increased from almost 2 billion to over 3 billion bbl (316 billion L to 503 billion
5 L). The Eagle Ford play in Texas is another major area of shale oil activity, with production
6 increasing from 71 million bbl (11 billion L) in 2011 to 210 million bbl (33 billion L) in 2012, and
7 proved reserves increasing from 1.25 billion to 3.4 billion bbl (199 billion to 536 billion L) (EIA,
8 2014b]. Oil production from the Eagle Ford surpassed that from the Bakken in 2013 (EIA, 2014h].
9 Among other shale oil plays that might become important in future domestic U.S. oil production, the
10 Niobrara (centered in Colorado) and Austin Chalk (in Texas, Louisiana, and Mississippi) are
11 believed to have quantities of recoverable resources on the same order of magnitude as the Bakken
12 and Eagle Ford plays fEIA. 2012bj.
2.4. Conclusion
13 Since about 2005, the combination of hydraulic fracturing and horizontal drilling pioneered in the
14 Barnett Shale have become widespread in the oil and gas industry. Hydraulic fracturing is now a
15 standard industry practice and has significantly contributed to a surge in U.S. production of both oil
16 and gas. Modern hydraulic fracturing has resulted in additional types of geological formations being
17 tapped, and sometimes these formations are located in regions of the country new to intensive oil
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water AssessmentChapter 2-Hydraulic Fracturing, OH and Gas Production, andthe U.S. Energy Sector
1 and gas exploration and production. In other areas, the improved techniques have made possible a
2 resurgence of production.
3 An estimated 25,000 to 30,000 new wells drilled in the United States were hydraulically fractured
4 as a production-enhancing technique in each year from 2011 to 2014. Additional pre-existing wells
5 were also fractured. Since the early 2000s, the percentage of all hydraulically fractured wells that
6 are either horizontal or deviated has steadily grown. Reserves of oil and gas that are now accessible
7 with modern hydraulic fracturing are considerable, and if technical improvements outpace
8 depletion of oil and gas resources, the quantity of resources that are deemed economically and
9 technically recoverable may continue to grow. Given current trends, it appears likely that hydraulic
10 fracturing will continue to play an important role in the oil and gas industry, and the United States'
11 energy portfolio, in the decades ahead.
2.5. References for Chapter 2
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This document is a draft for review purposes only and does not constitute Agency policy.
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This document is a draft for review purposes only and does not constitute Agency policy.
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EIA (Energy Information Administration). (2014a). Annual energy outlook 2014 with projections to 2040.
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This document is a draft for review purposes only and does not constitute Agency policy.
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Holditch. SA. (2007). Chapter 8: Hydraulic fracturing. In JD Clegg (Ed), Petroleum engineering handbook (pp.
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fracturing. Prepared for American Petroleum Institute. Lexington, MA: IHS Global Insight.
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IOGCC (Interstate Oil and Gas Compact Commission). (2002). States experience with hydraulic fracturing. A
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IOGCC (Interstate Oil and Gas Compact Commission). (2015). Groundwork: hydraulic fracturing - state
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Kargbo. DM: Wilhelm. RG: Campbell. PI. (2010). Natural gas plays in the Marcellus Shale: Challenges and
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Kundert. D: Mullen. M. (2009). Proper evaluation of shale gas reservoirs leads to a more effective hydraulic-
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recovery from the marcellus shale, northeastern United States. K S C E Journal of Civil Engineering 15:
679-687. http://dx.doi.org/10.1007/sl2205-011-0008-4
Lowe. T: Potts. M: Wood. D. (2013). A case history of comprehensive hydraulic fracturing monitoring in the
Cana Woodford. In 2013 SPE annual technical conference and exhibition. Richardson, TX: Society of
Petroleum Engineers. http://dx.doi.org/10.2118/166295-MS
Miskimins. IL. (2008). Design and life cycle considerations for unconventional reservoir wells. In 2008 SPE
Unconventional Reservoirs Conference. Richardson, TX: Society of Petroleum Engineers.
http://dx.doi.org/10.2118/114170-MS
Montgomery, C. (2013). Fracturing fluid components. In A Bunder; J McLennon; R Jeffrey (Eds.), Effective and
Sustainable Hydraulic Fracturing. Croatia: InTech. http://dx.doi.org/10.5772/56422
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26-32.
NETL (National Energy Technology Laboratory). (2013). Modern shale gas development in the United States:
An update. Pittsburgh, PA: U.S. Department of Energy. National Energy Technology Laboratory.
http://www.netl.doe.gov/File%20Library/Research/Oil-Gas/shale-gas-primer-update-2013.pdf
Newell, R. (2011). Shale gas and the outlook for U.S. natural gas markets and global gas resources.
Presentation presented at US EIA presentation at OECD Meetings, June 21, 2011, Paris, France.
NPC (National Petroleum Council). (2011b). Plugging and abandonment of oil and gas wells. (Paper #2-25).
Washington, DC: National Petroleum Council (NPC).
This document is a draft for review purposes only and does not constitute Agency policy.
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NYSDEC (New York State Department of Environmental Conservation). (2011). Revised draft supplemental
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http://www.dec.ny.gov/energy/75370.html
Patzek. TW: Male. F: Harder. M. (2013). Gas production in the Barnett Shale obeys a simple scaling theory.
PNAS 110: 19731-19736. http://dx.doi.org/10.1073/pnas.1313380110
Pearson. CM: Griffin. L: Wright. CA: Weijers. L. (2013). Breaking up is hard to do: creating hydraulic fracture
complexity in the Bakken central basin. In 2013 SPE hydraulic fracturing technology conference.
Richardson, TX: Society of Petroleum Engineers. http://dx.doi.org/10.2118/163827-MS
Pearson. K. (2011). Geologic models and evaluation of undiscovered conventional and continuous oil and gas
resourcesUpper Cretaceous Austin Chalk, U.S. Gulf Coast. In US Geological Survey Scientific Investigations
Report. (20125159). U.S. Geological Survey, http://pubs.usgs.gov/sir/2012/5159/
Rassenfoss. S. (2011). From flowback to fracturing: Water recycling grows in the Marcellus shale. J Pet Tech
63: 48-51.
Renpu. W. (2011). Advanced well completion engineering (Third ed.). Houston, TX: Gulf Professional
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Schlumberger (Schlumberger Limited). (2006). Fundamentals of formation testing. Sugar Land, Texas.
http://www.slb.eom/~/media/Files/evaluation/books/fundamentals formation testing overview.pdf
Schlumberger (Schlumberger Limited). (2014). Schlumberger oilfield glossary. Available online at
http://www.glossary.oilfield.slb.com/
Shires, T: Lev-On, M. (2012). Characterizing pivotal sources of methane emissions from unconventional
natural gas production - summary and analysis of API and ANGA survey responses. Washington, DC:
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Spellman. FR. (2012). Environmental impacts of hydraulic fracturing. In Environmental impacts of hydraulic
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STO (Statoil). (2013). Shale facts: drilling and hydraulic fracturing, how it's done, responsibly. (Global
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Thompson. AM. (2010) Induced fracture detection in the Barnett Shale, Ft. Worth Basin, Texas. (Master's
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U.S. EPA (U.S. Environmental Protection Agency). (2012d). Oil and natural gas sector: standards of
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D.C. http://www.epa.gov/airquality/oilandgas/pdfs/20120418tsd.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2012f). Study of the potential impacts of hydraulic
fracturing on drinking water resources: Progress report. (EPA/601/R-12/011). Washington, DC: U.S.
Environmental Protection Agency, Office of Research and Development.
http://nepis.epa.gov/exe/ZvPURL.cgi?Dockev=P100FH8M.txt
This document is a draft for review purposes only and does not constitute Agency policy.
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of Research and Development, U.S. Environmental Protection Agency.
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fractured oil and gas production wells: Well design and construction [EPA Report]. (EPA/601/R-14/002).
Washington, D.C.: Office of Research and Development, U.S. Environmental Protection Agency.
U.S. GAP (U.S. Government Accountability Office). (2012). Energy-water nexus: Information on the quantity,
quality, and management of water produced during oil and gas production. (GAO-12-156). Washington,
D.C. http://www.gao.gov/products/GAO-12-156
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Canadian Petroleum Technology 50: 36-52. http://dx.doi.org/10.2118/136757-PA
This document is a draft for review purposes only and does not constitute Agency policy.
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Wang. Z: Krupnick. A. (2013). A retrospective review of shale gas development in the United States. What let
to the boom? (RFF DP 13-12). Washington, DC: Resources for the Future.
http://www.rff.org/RFF/documents/RFF-DP-13-12.pdf
Weijermars. R. (2014). US shale gas production outlook based on well roll-out rate scenarios. Appl Energ 124:
283-297. http://dx.doi.0rg/10.1016/j.apenergy.2014.02.058
Yergin. D. (2011). The quest: energy, security and the remaking of the modern world. In The quest: energy,
security and the remaking of the modern world. New York, NY: Penquin Press.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 3-Drinking Water Resources in the UnitedStates
Chapter 3
Drinking Water Resources in the United States
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Hydraulic Fracturing Drinking Water Assessment Chapter 3 - Drinking Water Resources in the UnitedStates
3. Drinking Water Resources in the United States
1 Consideration of how and where hydraulic fracturing activities potentially impact drinking water
2 resources requires an understanding of both the activities and the potentially impacted resources.
3 In Chapter 2, we provided background on hydraulic fracturing and in this chapter, we provide an
4 overview of drinking water resources in the United States. We describe the use of these resources,
5 including patterns in current use and trends for future use (Section 3.1). We then characterize the
6 spatial distribution of hydraulically fractured wells and current surface and ground water supplies
7 throughout the United States (Section 3.2) to evaluate where potential impacts of hydraulic
8 fracturing on drinking water resources may occur.
3.1. Current and Future Drinking Water Resources
9 In this assessment, drinking water resources are defined broadly as any body of ground water or
10 surface water that now serves, or in the future could serve, as a source of drinking water for public
11 or private use. Drinking water resources provide not only water that individuals actually drink but
12 also water used for many additional purposes such as cooking and bathing. Our definition of
13 drinking water resources includes both fresh and non-fresh bodies of water.
14 The average American uses about 90 gal (341 L) of drinking water per day for indoor and outdoor
15 purposes (e.g., drinking, food preparation, washing clothes and dishes, flushing toilets, and
16 watering lawns or gardens (Maupinetal.. 2014: AWWA. 1999). Drinking water is supplied to
17 households by either public water systems (PWSs) or private water systems (private ground water
18 wells and surface water intakes).1 In 2011, approximately 270 million people (86% of the
19 population) in the United States relied on water supplied to their homes by one of the more than
20 51,000 community water systems (Maupinetal.. 2014: U.S. EPA. 2013b).2 These systems provided
21 households with nearly 24 billion gal (91 billion L) of water per day (Maupinetal.. 2014).3 In areas
22 without service by PWSs, approximately 43 million people (14% of the population) relied on
23 private sources for drinking water, and private water systems account for about 3.6 billion gal (14
24 billion L) of daily water withdrawals (Maupinetal., 2014).
25 Drinking water resources can be surface waters such as rivers, streams, lakes, or reservoirs, as well
26 as ground water aquifers. In 2011, approximately 70% of the population receiving drinking water
27 from PWSs relied on surface water, and 30% relied on ground water (U.S. EPA. 2013b). However,
i Public water systems (PWSs) provide water for human consumption from surface or ground water through pipes or
other infrastructure to at least 15 service connections or serve an average of at least 25 people for at least 60 days a year
[U.S. EPA. 2012e). Private (non-public) water systems serve fewer than 15 connections and fewer than 25 individuals
(U.S. EPA. 1991).
2 The EPA categorizes public water systems as either community water systems, which supply water to the same
population year-round, or non-community water systems, which supply water to at least 25 of the same people at least six
months per year, but not year-round. Approximately 101,000 non-community water systems provide water to non-
residential facilities (e.g., schools, small businesses, churches, and campgrounds (U.S. EPA. 2013b).
3 The U.S. Geological Survey (USGS) compiles data in cooperation with local, state, and federal environmental agencies to
produce water-use information aggregated at the county, state, and national levels. Every five years, data at the county
level are compiled into a national water use census and state-level data are published. The most recent USGS water use
report was released in 2014, and contains water use estimates from 2010 (Maupinetal.. 2014: USGS. 2014b).
This document is a draft for review purposes only and does not constitute Agency policy.
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1 the relative importance of surface and ground water sources for supplying drinking water varies
2 geographically (see Figure 3-1). Most larger PWSs rely on surface water and are located in urban
3 areas [U.S. EPA. 2011b). whereas most smaller PWSs rely on ground water and are located in rural
4 areas [U.S. EPA, 2014), 2013b]. In fact, more than 95% of households in rural areas obtain their
5 drinking water from ground water aquifers [U.S. EPA, 2011b].
Drinking water sources* used by public water systems,
as a percentage of all sources in a state
J > 75% surface water sources
50 - 75% surface water sources
50 - 75% ground water sources
> 75% ground water sources
States with hydraulically fractured wells
*Drinking water sources include the following public water system sources: infiltration galleries, intakes, reservoirs, springs, and wells.
Sources: Drillinglnfo (2014); ESRI (2010); U.S. Environmental Protection Agency (2011, 2013); U.S. Census Bureau (2010)
Projection: North America Albers Equal Area Conic
Copyright:© 2014
Figure 3-1. Geographic variability in drinking water sources for public water systems.
The relative importance of surface and ground water as drinking water sources varies by state. The
public water system sources used in this analysis include infiltration galleries, intakes, reservoirs,
springs, and wells. States with hydraulically fractured wells were identified from Drillinglnfo data.
The future availability of drinking water resources that are considered fresh in the United States
will be affected by changes in climate and water use [Georgakakos etal.. 2014: U.S. Global Change
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Research Program, 2009].l Since 2000, about 30% of the total area of the contiguous United States
2 has experienced moderate drought conditions and about 20% has experienced severe drought
3 conditions [National Drought Mitigation Center. 2015: U.S. EPA. 2015r). Declines in surface water
4 resources have already led to increased withdrawals and cumulative net depletions of ground
5 water in some areas [Castle etal., 2014: Georgakakos etal., 2014: Konikow, 2013a: Famiglietti etal.,
6 2011]. Other sources of water that might not be considered fresh, such as wastewater from sewage
7 treatment plants, brackish (containing 3,000-10,000 mg/L IDS) and saline (containing more than
8 10,000 mg/L TDS) surface and ground water, as well as seawater (containing about 35,000 mg/L
9 TDS) are also increasingly being used to meet water demand. Through treatment or desalination,
10 these water sources can reduce the use of high-quality, potable fresh water for industrial processes,
11 irrigation, recreation, and toilet flushing (i.e., non-potable uses). In addition, in 2010, approximately
12 355 million gal per day (1.3 billion L per day) of treated wastewater was reclaimed through potable
13 reuse projects (NRG. 2012). Such projects use reclaimed wastewater to augment surface drinking
14 water resources or to recharge aquifers that supply drinking water to PWSs (NRG, 2012: Sheng,
15 2005).
16 An increasing number of states are developing new water supplies to augment existing water
17 through reuse of reclaimed water, recycling of storm water, and desalination (U.S. GAP. 2014). Most
18 desalination programs currently use brackish water, although plans are underway to expand the
19 use of seawater for desalination in some states. States with the highest installed capacity for
20 desalination include Florida, California, Arizona, and Texas (Cooley etal.. 2006). It is likely that
21 various water treatment technologies will continue to expand drinking water resources beyond
22 those currently being considered for use as drinking water. Therefore, these potential future
23 sources are also considered drinking water resources in this assessment
3.2. The Proximity of Drinking Water Resources to Hydraulic Fracturing Activity
24 The colocation of hydraulic fracturing activities with surface and ground water increases the
25 potential for impacts to current and future drinking water resources (Vengoshetal.. 2014: Entrekin
26 etal.. 2011). In this section, we analyze the aboveground proximity of hydraulically fractured well
2 7 sites, drinking water resources (including the location of surface water bodies and ground water
28 wells that supply public water systems), and populated areas.2
29 To determine the spatial relationship between hydraulically fractured wells and populated areas,
30 we analyzed the locations of the approximately 273,000 oil and gas wells that were hydraulically
31 fractured in 25 states between 2000 and 2013 (see Chapter 2) with respect to where people live
32 (i.e., census blocks).3 Nationwide, approximately 9.4 million people lived within one mile of a
1 Fresh water qualitatively refers to water with relatively low TDS that is most readily available for drinking water
currently.
2 The vertical proximity of ground water resources to geologic formations and hydraulic fracturing operations is
addressed in Chapter 6.
3 In the analyses in this chapter, we only include the oil and gas production wells that we identified were hydraulically
fractured using criteria outlined in Chapter 2 and that began producing between 2000 and 2013. The well data found in
Drillinglnfo may not represent the full year for 2013 since the frequency with which Drillinglnfo updates the database
varies by state. The final update performed by Drillinglnfo for 2013 ranges by state from June 2013 to December 2013.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 3 - Drinking Water Resources in the UnitedStates
1 hydraulically fractured well for some period of time between 2000 and 2013 [Drillinglnfo, 2014a:
2 U.S. Census Bureau. 2010]: more than 5.7 million people lived within half a mile of a hydraulically
3 fractured well.
4 We then analyzed trends in the proximity of hydraulically fractured wells to highly populated areas.
5 For this analysis, we considered metropolitan areas (areas with more than 50,000 people) and
6 micropolitan areas (areas with 10,000 to 49,999 people) (U.S. Census Bureau, 2013C].1
7 Approximately 81,300 (30%) of new wells hydraulically fractured between 2000 and 2013 were
8 located within a metropolitan or micropolitan area (see Figure 3-2) (Drillinglnfo, 2014a: U.S.
9 Census Bureau. 2013c: U.S. EPA. 2013b: ESRI. 2010). From 2000 to 2008, the number of new wells
10 hydraulically fractured per year within metropolitan and micropolitan areas increased 300%; the
11 proportion of wells hydraulically fractured per year in metropolitan and micropolitan areas almost
12 doubled over the same eight-year period (see Figure 3-3).2 From 2008 to 2012, however, the
13 number of wells hydraulically fractured per year in metropolitan and micropolitan areas decreased
14 by about half in comparison to the peak of approximately 10,000 wells in 2 008 (see Figure 3-3),
15 whereas hydraulic fracturing in areas outside of metropolitan and micropolitan areas increased or
16 remained relatively constant (Drillinglnfo, 2014a: U.S. Census Bureau, 2013b).
i Metropolitan and micropolitan combined statistical areas are geographic entities delineated by the Office of
Management and Budget. Specifically, a metropolitan combined statistical area is a core urban area of 50,000 or more
people while a micropolitan combined statistical area is an urban core of at least 10,000, but less than 50,000, people [U.S.
Census Bureau. 2013c). These terms are referred to as metropolitan and micropolitan areas in this assessment.
2 For comparison, the Drillinglnfo data indicate an increase in the number of wells estimated to be hydraulically fractured
each year, regardless of location, from approximately 12,800 in 2000 to slightly more than 21,600 in 2005 to nearly
23,000 in 2012, the last year for which complete data are available.
This document is a draft for review purposes only and does not constitute Agency policy.
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Proximity of hydraulkalty fractured wells relative to metropolitan and micropolitan areas
Hydraulically fractured wells within metropolitan and micropolitan areas
Hydraulically fractured wells outside of metropolitan and micropolitan areas
| Populated census blocks within 1 mile of at least one well hydraulically fractured well
Metropolitan and micropolitan areas without hydraulically fractured wells
urces: Drillinglnfa (2014); ESRI (2010); U.S. Census Bureau (2013)
roiectlon: North America Albers Equal Area Conic
Figure 3-2. Proximity of hydraulically fractured wells relative to populated areas.
The estimates of hydraulically fractured wells from 2000 to 2013 developed from the Drillinglnfo data were based on several assumptions
described in Chapter 2.
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapters - Drinking Water R
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Hydraulic Fracturing Drinking Water Assessment Chapters - Drinking Water R
1 Between 2000 and 2013, approximately 6,800 PWS sources had a hydraulically fractured well
2 within a 1 mile radius. Most of these PWS sources were located in Colorado, Louisiana, Michigan,
3 North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, and Wyoming (see Figure 3-5). These PWS
4 sources had an average of seven fractured wells and a maximum of 144 fractured wells within that
5 one mile proximity. They also supplied water to 3,924 PWSs—1,609 of which are community water
6 systems—that served more than 8.6 million people year-round in 2013 [U.S. EPA. 2014): U.S.
7 Census Bureau. 2013a: U.S. EPA. 201313).1
8 We also analyzed the location of hydraulically fractured wells relative to populations where a high
9 proportion (>30%, or twice the national average) obtain drinking water from private systems
10 (private ground water wells and surface water intakes).2 Between 2000 and 2013, approximately
11 3.6 million people obtained drinking water from private systems in counties with at least one
12 hydraulically fractured well fDrillinglnfo. 2014a: USGS. 2014bl and approximately 740,000 people
13 obtained drinking water from private supplies in counties with more than 400 fractured wells
14 (Drillinglnfo, 2014a: USGS, 2014b) (see Figure 3-6).3 These counties were located in Colorado,
15 Kentucky, Michigan, Montana, New Mexico, New York, Oklahoma, Pennsylvania, Texas, and
16 Wyoming (see Figure 3-6).
i All PWS types were included in the locational analyses performed. However, only community water systems were used
to calculate the number of customers obtaining water from a PWS with at least one source within 1 mile of a hydraulically
fractured well. If non-community water systems are included, the estimated number of customers increases by 533,000
people fU.S.EPA.2012e).
2 There is no national data set of private water systems. The USGS estimates the proportion of the population reliant on
private water systems, referred to as the "self-supplied population," by county, based on estimates of the population
without connections to a public water system [Maupin et al.. 2014). We used the USGS estimates for this analysis.
3 Approximately 14% of the U.S. population is supplied by private water systems [Maupin et al.. 2014). In this analysis, we
only considered counties in which more than double the national average—that is, at least 30% of the county's
population—was supplied by private water systems.
This document is a draft for review purposes only and does not constitute Agency policy.
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'
Number of public water system (PWS) sources located
| within 1 mile of a hydraulically fractured well
1-3
-, 4-8
• 9 22
• 23-10
Points indicate the location of hydraulically fractured wells; point color indicates
the number of hydraulically fractured wells within 1 mile of each PWS source.
The following PWS sources were included in this analysis: infiltration galleries, intakes,
reservoirs, springs, and wells.
Sources: Dtillinglnfo (2014); U.S. Environmental Protection Agency (2014); ESRI (2010)
Projection: North America Albers Equal Area Conic
Figure 3-4. Location and number of public water system (PWS) sources located within 1 mile of a hydraulically fractured well.
Points indicate the location of hydraulically fractured wells; point color indicates the number of hydraulically fractured wells within 1 mile of each
PWS source. The following PWS sources were included in this analysis: infiltration galleries, intakes, reservoirs, springs, and wells. The estimates of
wells hydraulically fractured from 2000 to 2013 developed from the Drillinglnfo data were based on several assumptions described in Chapter 2.
June 2015
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Chapters - Drinking Water Resources in the United States
Number of hydraullcally fractured wells within
1 mile of a public water system (PWS) source
1-8
• 9-24
• 25-48
• 49 -144
Points indicate the location of public water system (PWS) sources; point color Indicates
the number of hydraulically fractured wells within l mile of each PWS source.
The following PWS sources were included in this analysis: infiltration galleries, intakes,
reservoirs, springs, and wells. Note that some PWS systems have more than one source.
Sources: Drillinglnfo (2014); U.S. Environmental Protection Agency (2014); ESRI (2010)
Projection: North America Albers Equal Area Conic
Figure 3-5. The location of public water system sources within 1 mile of hydraulically fractured wells.
Points indicate the location of public water system (PWS) sources; point color indicates the number of hydraulically fractured wells within 1 mile of
each PWS source. The estimates of wells hydraulically fractured from 2000 to 2013 developed from the Drillinglnfo data were based on several
assumptions described in Chapter 2.
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Chapters - Drinking Water Resources in the United States
Number of hydraulically fractured
wells per county
1-400
] 401 1400
H 1101 - 3400
B 3401 - 8600
B 8601 • 16051
Counties with 30% or more of
—I population supplied by private water
_l systems and more than 400
hydraulicaliy fractured wells
Sources: Drillinglnfo (2014); U.S. Geological Survey (2014); ESRI (2010); U.S. Census Bureau (2010)
Projection: North America Albers Equal Area Conic
Figure 3-6. Co-occurrence of hydraulic fracturing activity and populations supplied by private water systems.
Color indicates the number of hydraulically fractured wells per county. The estimates of wells hydraulically fractured from 2000 to 2013 developed
from the Drillinglnfo data were based on several assumptions described in Chapter 2. Counties with more than 400 hydraulically fractured wells
and in which at least 30% of the population is supplied by private water systems are outlined in blue.
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3.3. Conclusion
1 The evaluation of potential hydraulic fracturing impacts on drinking water resources in the United
2 States depends on an understanding of how the country's current and future drinking water needs
3 are and will be met The U.S. population requires sufficient drinking water resources—that is,
4 bodies of fresh or non-fresh surface or ground water that now serve, or in the future could serve, as
5 a source of water for drinking water for public or private use—to meet everyday needs. Currently,
6 most people in the United States rely on water supplied to their homes via public water systems,
7 and most of this water comes from fresh surface water bodies. Shortages in fresh water availability
8 in the United States, especially in the western United States, have already led some states to
9 augment their water supplies with other water sources (e.g., brackish and saline surface and
10 ground water, seawater, and reclaimed wastewater), suggesting that additional water bodies may
11 provide drinking water as the quantity and quality of existing sources change.
12 The colocation of hydraulic fracturing activities with drinking water resources increases the
13 potential for these activities to affect the quality and quantity of current and future drinking water
14 resources. While close proximity of hydraulically fractured wells to drinking water resources does
15 not necessarily indicate that an impact has or will occur, information about the relative location of
16 wells and water supplies is an initial step in understanding where potential impacts might occur.
17 Millions of people live in areas where their drinking water resources are located near hydraulically
18 fractured wells. While most hydraulic fracturing activity from 2000 to 2013 did not occur in close
19 proximity to public water supplies, a sizeable number of hydraulically fractured wells (21,900)
20 were located within 1 mile of at least one PWS source (e.g., infiltration galleries, intakes, reservoirs,
21 springs and ground water wells). Approximately 6,800 sources of drinking water for public water
22 systems, serving more than 8.6 million people year-round, were located within 1 mile of at least one
23 hydraulically fractured well. An additional 3.6 million people obtain drinking water from private
24 systems in counties with at least one hydraulically fractured well and in which at least 30% of the
2 5 population is reliant on private water systems.
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Chapters - Drinking Water R
Text Box 3-1. Major Findings
Current and future drinking water resources
• Most of the U.S. population (270 million in 2011, or 86%) relies on water supplied to their
homes through a public water system, 70% of which comes from surface water and 30% of
which comes from ground water.
• An estimated 14% of the U.S. population relies on private water systems for drinking water.
• An increasing number of states are developing new drinking water supplies via reuse of
reclaimed water, recycling of storm water, and desalination. These new supplies can augment
existing water sources.
• Most of the U.S. population (270 million in 2011, or 86%) relies on water supplied to their
homes through a public water system, 70% of which comes from surface water and 30% of
which comes from ground water.
• An estimated 14% of the U.S. population relies on private water systems for drinking water.
• An increasing number of states are developing new drinking water supplies via reuse of
reclaimed water, recycling of storm water, and desalination. These new supplies can augment
existing water sources.
Proximity of drinking water resources to hydraulic fracturing activity
• Nationwide, while most hydraulic fracturing activity from 2000 to 2013 did not occur in close
proximity to public water supplies, a sizeable number of hydraulically fractured wells
(21,900) were located within 1 mile of at least one PWS source.
• The distance between wells that were hydraulically fractured between 2000 and 2013 and the
nearest source supplying a PWS ranged from 0.01 to 41 miles, with an average distance of 6.2
miles (9.9 km).
• An estimated 6,800 public water system sources were located within 1 mile of a hydraulically
fractured oil and gas well between 2000 and 2013. These PWS sources supplied water to
3,924 public water systems and served more than 8.6 million people year-round in 2013.
• Approximately 9.4 million people lived within 1 mile of at least one hydraulically fractured oil
and gas well between 2000 and 2013.
• Approximately 3.6 million people obtain drinking water from private systems in counties with
at least one hydraulically fractured well and in which at least 30% of the population (i.e.,
double the national average) is reliant on private water systems.
3.4. References for Chapter 3
AWWA (American Water Works Association). (1999). Residential end uses of water. In PW Mayer; WB
DeOreo (Eds.). Denver, CO: AWWA Research Foundation and American Water Works Association.
http://www.waterrf.org/PublicReportLibrarv/RFR90781 1999 241A.pdf
This document is a draft for review purposes only and does not constitute Agency policy.
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Castle. SL: Thomas. BF: Reager. IT: Rodell. M: Swenson. SC: Famiglietti. IS. (2014). Groundwater depletion
during drought threatens future water security of the Colorado River Basin. Geophys Res Lett 41: 5904-
5911. http://dx.doi.org/10.1002/2014GL061055
Cooley. H: Gleick. PH: Wolff. G. (2006). Desalination, with a grain of salt: A California perspective. Oakland, CA:
Pacific Institute for Studies in Development, Environment, and Security, http://www.pacinst.org/wp-
content/uploads/2013/02/desalination report3.pdf
Drillinglnfo, Inc.. (2014a). DI Desktop June 2014 download [Database]. Austin, TX: Drillinglnfo. Retrieved
from http://info.drillinginfo.com/
Entrekin, S: Evans-White, M: lohnson, B: Hagenbuch, E. (2011). Rapid expansion of natural gas development
poses a threat to surface waters. Front Ecol Environ 9: 503-511. http://dx.doi.org/10.1890/110053
ESRI (Environmental Systems Research Institute Inc.). (2010). US states shapefile. Redlands, California.
Retrieved from http://www.arcgis.com/home/item.html?id=la6cae723afl4f9cae228bl33aebc620
Famiglietti. IS: Lo. M: Ho. SL: Bethune. I: Anderson. Kl: Syed. TH: Swenson. SC: de Linage. CR: Rodell. M.
(2011). Satellites measure recent rates of groundwater depletion in California's Central Valley. Geophys
Res Lett 38: L03403. http://dx.doi.org/10.1029/2010GL046442
Georgakakos. A: Fleming. P: Dettinger. M: Peters-Lidard. C: Richmond. TC: Reckhow. K: White. K: Yates. D.
(2014). Water resources. In JM Melillo; TC Richmond; GW Yohe (Eds.), Climate change impacts in the
United States (pp. 69-112). Washington, D.C.: U.S. Global Change Research Program.
http://www.globalchange.gov/ncadac
Konikow. LF. (2013a). Groundwater depletion in the United States (1900-2008): U.S. Geological Survey
Scientific Investigations Report 2013-5079. Reston, VA: U.S. Geological Survey.
http://pubs.usgs.gov/sir/2013/5079
Maupin. MA: Kenny. IF: Hutson. SS: Lovelace. IK: Barber. NL: Linsey. KS. (2014). Estimated use of water in the
United States in 2010. (USGS Circular 1405). Reston, VA: U.S. Geological Survey.
http://dx.doi.org/10.3133/cirl405
National Drought Mitigation Center. (2015). U.S. drought monitor. Available online at
http://droughtmonitor.unl.edu/Home.aspx (accessed February 27, 2015).
NRC (National Research Council). (2012). Water reuse: Potential for expanding the nations water supply
through reuse of municipal wastewater. Committee on the Assessment of Water Reuse as an Approach for
Meeting Future Water Supply Need. Washington, DC: The National Academies Press.
http://www.nap.edu/openbook.php7record id=13303
Sheng. Z. (2005). An aquifer storage and recovery system with reclaimed wastewater to preserve native
groundwater resources in El Paso, Texas. J Environ Manage 75: 367-377.
http://dx.doi.0rg/10.1016/j.jenvman.2004.10.007
U.S. Census Bureau. (2010). Special release - census blocks with population and housing unit counts, 2010
TIGER/Line shapefiles [Computer Program]. Suitland, MD: U.S. Census Bureau, Geography Division.
Retrieved from https://www.census.gov/geo/maps-data/data/tiger-line.html
U.S. Census Bureau. (2013a). Annual estimates of the resident population: April 1, 2010 to July 1, 2013.
Suitland, MD: U.S. Census Bureau, Population Division.
http://factfinder2.census.gov/faces/tableservices/jsf/pages/productview.xh tml?src=bkmk
U.S. Census Bureau. (2013b). Cartographic boundary shapefiles metropolitan and micropolitan statistical
areas and related statistical areas (Combined statistical areas, 500k). Suitland, MD. Retrieved from
https://www.census.gov/geo/maps-data/data/cbf/cbf msa.html
U.S. Census Bureau. (2013c). Metropolitan and micropolitan statistical areas main. Available online at
http://www.census.gov/population/metro/ (accessed January 12, 2015).
This document is a draft for review purposes only and does not constitute Agency policy.
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U.S. EPA (U.S. Environmental Protection Agency). (1991). Manual of individual and non-public water supply
systems [EPA Report]. (EPA 570/9-91-004). Washington, D.C.
U.S. EPA (U.S. Environmental Protection Agency). (2011b). Ground water cleanup at Superfund Sites [EPA
Report]. (EPA 540-K-96 008). Washington, DC: U. S. Environmental Protection Agency, Office Water.
http://www.epa.gov/superfund/health/conmedia/gwdocs/brochure.htm
U.S. EPA (U.S. Environmental Protection Agency). (2012e). Public drinking water systems: facts and figures.
Washington, DC: U.S. Environmental Protection Agency, Office of Water.
http://water.epa.gov/infrastructure/drinkingwater/pws/factoids.cfm
U.S. EPA (U.S. Environmental Protection Agency). (2013b). Drinking water and ground water statistics, fiscal
year 2011. Washington, DC: U.S. Environmental Protection Agency, Office of Water.
http://water.epa.gov/scitech/datait/databases/drink/sdwisfed/upload/epa816rl3003.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2014J). Safe drinking water information system (SDWIS).
Data obtained from the Office of Water [Database]. Washington, D.C.: Office of Water. Retrieved from
http://water.epa.gov/scitech/datait/databases/drink/sdwisfed/index.cfm
U.S. EPA (U.S. Environmental Protection Agency). (2015r). WaterSense: water supply in the U.S. Available
online at http://www.epa.gov/WaterSense/pubs/supply.html (accessed January 12,2015).
U.S. GAP (U.S. Government Accountability Office). (2014). Freshwater: Supply concerns continue, and
uncertainties complicate planning. Report to Congressional requesters. (GAO-14-430). Washington, DC:
U.S. Government Accountability Office (GAO). http://www.gao.gov/assets/670/663343.pdf
U.S. Global Change Research Program. (2009). Global climate change impacts in the United States. New York,
NY: Cambridge University Press, http://downloads.globalchange.gov/usimpacts/pdfs/climate-impacts-
reportpdf
USGS (U.S. Geological Survey). (2014b). Estimated use of water in the United States, county-level data for
2010. Reston, VA. http://water.usgs.gov/watuse/data/2010/
Vengosh. A: lackson. RB: Warner. N: Darrah. TH: Kondash. A. (2014). A critical review of the risks to water
resources from unconventional shale gas development and hydraulic fracturing in the United States.
Environ Sci Technol 48: 36-52. http://dx.doi.org/10.1021/es405118v
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Chapter 4
Water Acquisition
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4. Water Acquisition
4.1. Introduction
1 Water is a crucial component of nearly all hydraulic fracturing operations, making up
2 approximately 90% or more of fluid injected into a well [U.S. EPA. 2015a: GWPG and ALL
3 Consulting. 2009). Given that at least 25,000 to 30,000 wells maybe fractured each year
4 (Chapter 2), and that each well requires thousands to millions of gallons of water (Section 4.3), the
5 potential exists for effects on the quantity of drinking water resources. Large volume water
6 withdrawals also could alter the quality of drinking water resources by decreasing dilution of
7 pollutants by surface waters, or in the case of ground water, allowing the infiltration of lower-
8 quality water from the land surface or adjacent formations.
9 In this chapter, we consider potential effects of water acquisition for hydraulic fracturing on both
10 drinking water resource quantity and quality, and where possible, identify factors that affect the
11 frequency or severity of impacts. We define drinking water resources broadly, to include not just
12 currently designated drinking waters, but waters that could in the future be used as drinking water
13 sources (see Chapter 1). Although most available data and literature pertain to water use, we
14 discuss water consumption where possible.1
15 We provide an overview of the types of hydraulic fracturing water used (Section 4.2); the amount of
16 water used per well (Section 4.3); and cumulative water use and consumption estimates
17 (Section 4.4).2 We then discuss these three factors for 15 states where hydraulic fracturing
18 presently occurs and consider the potential for hydraulic fracturing water withdrawals to affect
19 water quantity and quality in localities within those states (Section 4.5). We primarily discuss
20 results at the state and county level because data are most available at these scales. Moreover,
21 states and localities often differ in industry activity, formation type, and water availability, all of
22 which affect potential impacts.3 Lastly, we provide a synthesis that summarizes major findings,
23 factors affecting the frequency or severity of impacts, uncertainties, and conclusions (Section 4.6).
Water use is water withdrawn for a specific purpose, part or all of which may be returned to the local hydrologic cycle.
Water consumption is water that is removed from the local hydrologic cycle following its use (e.g., via evaporation,
transpiration, incorporation into products or crops, consumption by humans or livestock), and is therefore unavailable to
other water users (Maupin et al.. 2014). Hydraulic fracturing water consumption can occur through evaporation from
storage ponds, the retention of water in the subsurface through imbibition, or disposal in Underground Injection Control
(UIC) Class II injection wells.
2 In this chapter, cumulative annual water use or water consumption refers to the amount of water used or consumed by
all hydraulic fracturing wells in a given area per year.
3 There is no standard definition for water availability, and it has not been assessed recently at the national scale [U.S.
GAP. 2014). Instead, a number of water availability indicators have been suggested [e.g.. Roy et al.. 2005). Here,
availability is most often used to qualitatively refer to the amount of a location's water that could, currently or in the
future, serve as a source of drinking water [U.S. GAP. 2014). which is a function of water inputs to a hydrologic system
(e.g., rain, snowmelt, groundwater recharge) and water outputs from that system occurring either naturally or through
competing demands of users. Where specific numbers are presented, we note the specific water availability indicator
used.
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4.2. Types of Water Used
1 Water used for hydraulic fracturing generally comes from surface water (i.e., rivers, streams, lakes,
2 and reservoirs), ground water aquifers, or reused hydraulic fracturing waste water.1'2*3 These
3 sources can vary in their initial water quality and in how they are provisioned to hydraulic
4 fracturing operations. In this section, we provide an overview of the sources (Section 4.2.1), water
5 quality (Section 4.2.2), and provisioning of water (Section 4.2.3) required for hydraulic fracturing.
6 Detailed information on the types of water used by state and locality is presented in Section 4.5.
4.2.1. Source
7 Whether water used in hydraulic fracturing originates from surface or ground water resources is
8 largely determined by the amount of water needed and the type of locally available water sources.
9 Water transportation costs can be high, so the industry tends to acquire water from nearby sources
10 if available (Nicotetal.. 2014: Mitchell et al.. 2013a: Kargbo etal.. 2010). Surface water is typically
11 available to supply most of the water needed in the eastern United States, whereas mixed supplies
12 of surface and ground water are used in the more semi-arid to arid western states. In western
13 states that lack available surface water resources, ground water supplies the majority of water
14 needed for fracturing unless alternative sources, such as reused waste water, are available and
15 utilized. Local policies also may direct the industry to seek withdrawals from designated sources
16 (U.S. EPA, 2013a): for instance, some states have encouraged the industry to seek water
17 withdrawals from surface water rather than ground water due to concerns over aquifer depletion
18 (Section 4.5).
19 The reuse of waste water from past hydraulic fracturing operations can reduce the need for fresh
20 surface or ground water and offset total new water withdrawals for hydraulic fracturing.4*5 Based
21 on available data, the median reuse of wastewater as a percentage of injected volume is 5%
22 nationally, butthis percentage varies by location (Table 4-1).6-1
i Throughout this chapter we sometimes refer to "reused hydraulic fracturing wastewater" as simply "reused
wastewater" because this is the dominant type of wastewater reused by the industry. When referring to other types of
reused wastewater not associated with hydraulic fracturing (e.g., acid mine drainage, wastewater treatment plant
effluent) we specify the source of the wastewater.
2 We use the term "reuse" regardless of the extent to which the wastewater is treated [Nicotetal.. 2014): we do not
distinguish between reuse and recycling except when specifically reported in the literature.
3 We use "wastewater" as a general term to include both flowback and produced water that may be reused in hydraulic
fracturing; we do not distinguish between flowback and produced water except when specifically reported in the
literature.
4 Hydraulic fracturing wastewater may be stored on-site in open pits, which may also collect rainwater and runoff water.
We do not distinguish between the different types of water that are collected on-site during oil and gas operations, and
assume that most of the water collected on-site at well pads is hydraulic fracturing wastewater.
5 We use the term "fresh water" to qualitatively refer to water with relatively low TDS that is most readily and currently
available for drinking water. We do not use the term to imply an exact TDS limit.
6 Throughout this chapter, we preferentially report medians where possible be
values than averages. Where medians are not available, averages are reported.
6 Throughout this chapter, we preferentially report medians where possible because medians are less sensitive to outlier
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1 The reuse of waste water for hydraulic fracturing is limited by the amount of water that returns to
2 the surface during production [Nicotetal.. 2012]. In the first 10 days of well production, 5% to
3 almost 50% of injected fluid volume may be collected, with values varying across geologic
4 formations (see Chapter 7, Table 7-1). Longer duration measurements are rare, but between 10%
5 and 30% of injected fluid volume has been collected in the Marcellus Shale in Pennsylvania over 9
6 years of production, while over 100% has been collected in the Barnett Shale in north-central Texas
7 over six years of production (see Chapter 7, Table 7-2). Assuming that 10% of injected fluid volume
8 is collected in the first 30 days and the reuse rate is 100%, it would take 10 wells to produce
9 enough water to hydraulically fracture a new well. As more wells are hydraulically fractured in a
10 given area, the potential for waste water reuse increases.
11 Besides hydraulic fracturing wastewater, other wastewaters may be reclaimed for use in hydraulic
12 fracturing. These may include acid mine drainage, wastewater treatment plant effluent, and other
13 sources of industrial and municipal wastewater (Nicotetal.. 2014: Ziemkiewicz etal.. 2013).
14 Limited information is available on the extent to which these other wastewaters are used.
Table 4-1. Percentage of injected water volume that comes from reused hydraulic fracturing
wastewater in various states, basins, and plays.
States listed by order of appearance in the chapter. See Section 4.5 for additional discussion of reuse
practices by state and locality and variation over time where data are available.
State, basin, or play
Available estimate
Year of estimate
(NA = not available)
i This chapter examines reused wastewater as a percentage of injected volume because reused wastewater may offset
total fresh water acquired for hydraulic fracturing. In contrast. Chapter 8 of this assessment discusses the total percentage
of the generated wastewater that is reused rather than managed by different means (e.g., disposal in Class II injection
wells). This distinction is sometimes overlooked, which sometimes leads to a misrepresentation of the extent to which
wastewater is reused to offset total fresh water used for hydraulic fracturing.
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State, basin, or play
Texas— Barn ett Shale
Texas— Eagle Ford Shale
Texas-TX-LA-MS Salt Basin"
Texas— Permian Basin (far west portion)
Texas— Permian Basin (Midland portion)
Texas— Anadarko Basin
Colorado— Garfield County, Uinta-Piceance Basin
Colorado— Wattenberg Field, Denver-Julesburg Basin
Pennsylvania — Marcellus Shale, Susquehanna River Basin
West Virginia— Marcellus Shale, Statewide
California— Monterey Shale, Statewide
Overall Mean'1
Overall Median1
Available estimate
5%a
0%a
5%a
0%a
2%a
20%a
100%c
0%d
18%e
15%f
4%g
15%
5%
Year of estimate
(NA= not available)
2011
2011
2011
2011
2011
2011
NA
NA
2012
2012
2014
a Estimated percentage of recycling/reused water in 2011 (Nicot et al., 2012).
b Nicot et al. (2012) refer to this region of Texas as the East Texas Basin.
c Based on industry practices reported in U.S. EPA(2015c).
Reflects an assumption of reuse practices by Noble Energy in the Wattenberg Field of Colorado's Denver-Julesburg Basin, as
reported by Goodwin et al. (2014).
e Volume of flowback injected as a percentage of total water injected, 2012 (Hansen et al., 2013). This is the most recent
estimate available. For 2008 to 2011, reuse as a percentage of injected volume averaged 13%, with a median of 8%, according
to U.S. EPA(2015c).
f Reused fracturing water as a percentage of total water used for hydraulic fracturing, 2012, calculated from data provided by
the West Virginia PEP (2014).
5 Reported data on planned hydraulic fracturing operations as described in 249 well stimulation notices submitted during the
first half of January 2014 to CCST (2014). Of these notices, 4% indicated planned use of produced water (sometimes blended
with fresh water) for fracturing, while 96% indicated planned use of only fresh water.
The overall mean is not weighted by the number of wells in a given state, basin, or play.
'The overall median is not weighted by the number of wells in a given state, basin, or play.
4.2.2. Quality
1 Water quality is an important consideration when sourcing water for hydraulic fracturing. Fresh
2 water is often preferred to maximize hydraulic fracturing fluid performance and to ensure
3 compatibility with the geologic formation being fractured. This finding is supported by the EPA's
4 analysis of disclosures to FracFocus 1.0 (hereafter the EPA FracFocus report) [U.S. EPA. 2015a], as
5 well as by regional analyses from Texas [Nicot etal., 2012] and the Marcellus [Mitchell etal.,
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1 2013aj.1-2 Fresh water was the most commonly cited water source by companies included in an
2 analysis of nine hydraulic fracturing service companies on their operations from 2005 to 2010 [U.S.
3 EPA. 2013a). Three service companies noted that the majority of their water was fresh because it
4 required minimal testing and treatment [U.S. EPA, 2013a].3 The majority of the nine service
5 companies recommended testing for certain water quality parameters (pH and maximum
6 concentrations of specific cations and anions) in order to ensure compatibility among the water,
7 other fracturing fluid constituents, and the geologic formation [U.S. EPA, 2013a].
8 The reuse of hydraulic fracturing waste water may be limited by water quality. As a hydraulically
9 fractured well ages, the waste water quality begins to resemble the water quality of the geologic
10 formation and may be characterized by high TDS [Goodwin etal.. 2014]. High concentrations of
11 TDS and other individual dissolved constituents in wastewater, including specific cations (calcium,
12 magnesium, iron, barium, strontium), anions (chloride, bicarbonate, phosphate, and sulfate), and
13 microbial agents, can interfere with hydraulic fracturing fluid performance by producing scale in
14 the wellbore or by interfering with certain chemical additives in the hydraulic fracturing fluid (e.g.,
15 high TDS may inhibit the effectiveness of friction reducers) (Gregory etal., 2011: North Dakota
16 State Water Commission, 2010). Due to these limitations, wastewater may require treatment to
17 meet the level of water quality desired in the hydraulic fracturing fluid formulation. Minimal
18 treatment or blending of wastewater and fresh water is sometimes done to dilute high TDS or other
19 constituents. Fresh water typically makes up the largest proportion of the base fluid when blended
20 with water sources of lesser quality (U.S. EPA. 2015a].4 However, direct reuse of wastewater with
21 minimal or no treatment is sometimes possible with higher-quality wastewater (U.S. EPA, 2015c]
22 (Section 4.5.2). No data are currently available to characterize the relative frequency of reuse done
2 3 with treatment, minimal treatment, or no treatment
4.2.3. Provisioning
24 Water for hydraulic fracturing is typically either self-supplied by the industry or purchased from
25 public water systems.5 Self-supplied water for fracturing generally refers to permitted direct
i FracFocus is a national hydraulic fracturing registry for oil and gas well operators to disclose information about
hydraulic fracturing well locations, and water and chemical use during hydraulic fracturing operations developed by the
Ground Water Protection Council and the Interstate Oil and Gas Compact Commission [U.S. EPA. 2015a). The registry was
originally established in 2011 for voluntary reporting. However, six of the 20 states discussed in this assessment required
disclosure to FracFocus at various points between January 1,2011 and February 28,2013, the time period analyzed by
the EPA; another three of the 20 states offered the choice of reporting to FracFocus or the state during this same time
period (see Appendix Table B-5 for states and disclosure start dates) [U.S. EPA. 2015a).
2 Of all disclosures to FracFocus that indicated a source of water for the hydraulic fracturing base fluid, 68% listed "fresh"
as the only source of water used. Note, 29% of all disclosures considered in the EPA's FracFocus report included
information on the source of water used for the base fluid [U.S. EPA. 2015a).
3 Service companies did not provide data on the percentage of fresh water versus non-fresh water used for hydraulic
fracturing fU.S. EPA. 2015a1.
4 In FracFocus disclosures indicating that fresh water was used in any combination with "recycled," "produced," or
"brine," the median concentration of fresh water across all states ranged from 69% to 93% [U.S. EPA. 2015a).
5 According to Section 1401(4) of the Safe Drinking Water Act, a public water system is defined as system that provides
water for human consumption from surface or ground water through pipes or other infrastructure to at least 15 service
connections, or an average of at least 25 people, for at least 60 days per year. Public water systems may either be publicly
or privately owned.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 withdrawals from surface or ground water or the reuse of waste water. Nationally, self-supplied
2 water is more common, although there is much regional variation [U.S. EPA. 2015a: CCST. 2014:
3 Mitchell et al.. 2 013a: Nicotetal.. 2012). Public water systems encompass a variety of water
4 suppliers [U.S. EPA, 2015c]. Water purchased from municipal public water systems can be provided
5 either before or after treatment [Nicotetal., 2014]. Water for hydraulic fracturing is also
6 sometimes purchased from smaller private entities, such as local land owners [Nicotetal., 2014].
4.3. Water Use Per Well
7 In this section, we provide an overview of the amount of water used per well during hydraulic
8 fracturing. We discuss water use in the life cycle of oil and gas operations (Section 4.3.1], national
9 patterns and associated variability (Section 4.3.2], as well as the factors affecting water use per well
10 including well length, geology, and fracturing fluid formulation (Section 4.3.3]. More detailed state-
11 and locality-specific information on water use per well is provided in Section 4.5.
4.3.1. Hydraulic Fracturing Water Use in the Life Cycle of Oil and Gas
12 Water is needed throughout the life cycle of oil and gas production and use, including both at the
13 well for processes such as well pad preparation, drilling, and fracturing (i.e., the upstream portion],
14 and later for end uses such as electricity generation, home heating, or transportation (i.e., the
15 downstream portion] (Jiang etal.. 2014: Laurenzi and Tersey. 2013]. Most of the water used and
16 consumed in the upstream portion of the life cycle occurs during hydraulic fracturing (Jiang etal..
17 2014: Clark etal., 2013: Laurenzi and Tersey, 2013].* Water use per well estimates in this chapter
18 focus on hydraulic fracturing in the upstream portion of the oil and gas life cycle.2
4.3.2. National Patterns of Water Use Per Well for Fracturing
19 Hydraulic fracturing for oil and gas requires a large volume of water to create sufficient pressures.
20 According to the EPA's project database of disclosures to FracFocus 1.0 (hereafter the EPA
21 FracFocus project database], the median volume of water used per well, based on
Laurenzi and lersey (2013) reported that hydraulic fracturing accounted for 91% of upstream water consumption,
based on industry data for 29 wells in the Marcellus Shale. (91% was calculated from their paper by dividing hydraulic
fracturing fresh water consumption (13.7 gal (51.9 L)/Megawatt-hour (MWh)) by total upstream fresh water
consumption (15.0 gal (56.8 L)/MWh) and multiplying by 100). Similarly, liangetal. (2014) reported that 86% of water
consumption occurred at the fracturing stage for the Marcellus, based on Pennsylvania Department of Environmental
Protection (PA DEP) data on 500 wells. The remaining water was used in several upstream processes (e.g., well pad
preparation, well drilling, road transportation to and from the wellhead, and well closure once production ended). Clark
etal. (2013) estimated lower percentages (30%-80%) of water use at the fracturing stage for multiple formations.
Although their estimates for the fraction of water used at the fracturing stage may be low due to their higher estimates for
transportation and processing, the estimates by Clark etal. (2013) similarly illustrate the importance of the hydraulic
fracturing stage in water use, particularly in terms of the upstream portion of the life cycle.
2 When the full life cycle of oil and gas production and use is considered (i.e., both upstream and downstream water use),
most water is used and consumed downstream. For example, in a life cycle analysis of hydraulically fractured gas used for
electricity generation. Laurenzi and lersey (2013) reported that only 6.7% of water consumption occurred upstream
(15.0 gal (56.8 L)/MWh), while 93.3% of fresh water consumption occurred downstream for power plant cooling via
evaporation (209.0 gal (791.2 L)/MWh).
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1 37,796 disclosures nationally, was 1.5 million gal (5.7 million L) (U.S. EPA. 2015b1.1 There was
2 substantial variability around this median, however, with 10th and 90th percentiles of 74,000 and 6
3 million gal (280,000 and 23 million L) per well, respectively.2 Even in specific basins and plays,
4 water use per well varied widely. Water injected also can vary within a single field; Laurenzi and
5 Jersey (2013] reported volumes for the Wattenberg Field of the Niobrara play ranging from 1 to 6
6 million gal (3.8 to 23 million L) per well (10th to 90th percentile).
4.3.3 Factors Affecting Water Use Per Well
7 Water use varies depending on many factors, including well length, geology, and the composition of
8 the fracturing fluid.
9 Well length: Well length is a principal driver of the amount of water used per well. Increases in well
10 length affect total water volumes injected primarily by allowing a larger fracture volume to be
11 stimulated (Economides etal.. 2013]. Fracture volume is the volume of the fractures in the geologic
12 formation that fill with hydraulic fracturing fluid. The total volume of injected fluid equals fracture
13 volume plus the volume of the wellbore itself, plus any fluid lost due to "leakoff" or other
14 unintended losses.3 Thus, as wells get longer, fracture, well, and total volumes all increase. This is
15 particularly evident in longer horizontal wells versus vertical wells. For example, median water use
16 in horizontal gas wells was over 35 times higher than in vertical gas wells (2.9 million gal vs. 82,000
17 gal (11 million L vs. 310,000 L), respectively) between the years 2000 and 2010 (USGS. 20151.
18 Geology: Geologic characteristics also influence the amount of water used per well. There are three
19 major formation types: shales, tight sands, and coalbeds (see Chapter 2). Reported differences in
2 0 water use for shales versus tight sands are rare. However, Nicotetal. (2012) reported that total
21 water use in tight sand formations is less than half of that of shale in Texas, although results were
2 2 not reported per well.
23 In contrast to hydrocarbons from shales and tight sands, coalbed methane (CBM) comes from coal
24 seams that often have a high initial water content and tend to occur at much shallower depths (U.S.
25 EPA. 20151]. Thus, dewatering is often necessary to stimulate production of CBM. In addition,
26 geologic pressures are lower (leading to higher permeability] and well lengths are shorter, all of
2 7 which result in lower water use per well. Water use per well in CBM operations can be lower by an
28 order of magnitude or more compared to operations in shales or tight sands. For example, Murray
29 (2013] reported water use across formations in Oklahoma, and found that water use in the
30 CBM-dominated Hartshorn Formation was much lower than in the shale gas-dominated Woodford
31 Formation.
i Water use data from the EPA's FracFocus project database were obtained from disclosures made to FracFocus 1.0.
Although disclosures were made on a per well basis, a small proportion of the wells were associated with more than one
disclosure (i.e., 876 out of 37,114, based on unique API numbers) [U.S. EPA. 2015b). For the purposes of this chapter, we
discuss water use per disclosure in terms of water use per well.
2 Although the EPA FracFocus report shows 5th and 95th percentiles, we report 10th and 90th percentiles throughout this
chapter to further reduce the influence of outliers.
3 Leakoff is the fraction of the injected fluid that infiltrates into the formation (e.g., through an existing natural fissure) and
is not recovered during production. See Chapter 6 for more information about leakoff.
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1 Fracturing Fluid Type: The majority of wells use fracturing fluids that consist mostly of water [U.S.
2 EPA. 2015a: Yang etal.. 2013: GWPC and ALL Consulting. 20091. The EPA inferred that more than
3 93% of reported disclosures to FracFocus used water as a base fluid [U.S. EPA. 2015a). The median
4 reported concentration of water in the hydraulic fracturing fluid was 88% by mass, with 10th and
5 90thpercentiles of 77% and 95%, respectively. Only roughly 2% of disclosures (761 wells) reported
6 the use of non-aqueous substances as base fluids, typically either liquid-gas mixtures of nitrogen
7 (643 disclosures, 84% of non-aqueous formulations) or carbon dioxide (83 disclosures, 11% of
8 non-aqueous formulations). Both of these formulations still contained substantial amounts of
9 water, as water made up roughly 60% (median value) of fluid in them (U.S. EPA, 2015a). Other
10 formulations were rarely reported. Non-aqueous formulations are discussed further in Chapter 5.
4.4. Cumulative Water Use and Consumption
11 In this section we provide an overview of cumulative water use and consumption for hydraulic
12 fracturing at the national, state, and county scales. We then compare these values to total water use
13 and consumption. We discuss both use and consumption because hydraulic fracturing is both a user
14 and consumer of water. Water use refers to water withdrawn for a specific purpose, part or all of
15 which may be returned to the local hydrologic cycle. Water consumption refers to water that is
16 removed from the local hydrologic cycle following its use, and is therefore unavailable to other
17 users (Maupinetal.. 2014). Hydraulic fracturing water consumption can occur through such means
18 as evaporation from storage ponds, the retention of water in the subsurface through imbibition, or
19 disposal in UIC Class II injection wells. In the latter two cases, the water consumed is generally
20 completely removed from the hydrologic cycle. In this section, water consumption estimates are
21 derived from USGS water use data, and therefore both use and consumption are presented with the
22 published water use numbers being first.
4.4.1. National and State Scale
23 Cumulatively, hydraulic fracturing uses and consumes billions of gallons of water each year in the
24 United States, but at the national or state scale, it is a relatively small user (and consumer) of water
25 compared to total water use and consumption. According to the EPA's FracFocus project database,
26 hydraulic fracturing used 36 billion gal (136 billion L) of water in 2011, and 52 billion gal (197
27 billion L) in 2012; therefore, hydraulic fracturing used an annual average of 44 billion gal (167
28 billion L) of water in 2011 and 2012 across all 20 states in the project database (U.S. EPA. 2015a. b).
29 Cumulative national water use for hydraulic fracturing can also be estimated by multiplying the
30 water use per well by the number of wells hydraulically fractured. If the median water use per well
31 (1.5 million gal) (5.7 million L) from the EPA's FracFocus project database is multiplied by 25,000
32 to 30,000 wells fractured annually (see Chapter 2), cumulative national water use for hydraulic
33 fracturing is estimated to range from 37.5 to 45.0 billion gal (142 to 170 billion L) annually. Other
34 calculated estimates have ranged higher than this, including estimates of approximately 80 billion
35 gal (300 billion L) fVengosh etal.. 20141 and 50-72 billion gal (190-273 billion L) fU.S. EPA. 2015cl.
36 These estimates are higher due to differences in the estimated water use per well and the number
37 of wells used as multipliers. For example, (Vengosh et al., 2014) derived the estimate of
38 approximately 80 billion gal (300 billion L) by multiplying an average of 4.0 million gal (15 million
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1 L) per well (estimated for shale gas wells) by 20,000 wells (the approximate total number of
2 fractured wells in 2012).:
3 All of these estimates of cumulative water use for hydraulic fracturing are small relative to total
4 water use and consumption at the national scale. For example, in the combined 20 states where
5 operators reported water use to FracFocus in 2011 and 2012 (U.S. EPA. 2015b), annual hydraulic
6 fracturing water use and consumption averaged over those two years was less than 1% of total
7 annual water use and consumption in 2010 (see Appendix Table B-l).2'3
8 At the state scale, hydraulic fracturing also generally uses billions of gallons of water cumulatively,
9 but accounts for a low percentage of total water use or consumption. Of all states, operators in
10 Texas used the most water cumulatively (47% of cumulative water use reported in the EPA
11 FracFocus project database) (U.S. EPA. 2015b) (see Appendix Table B-l). This was due to the large
12 number of wells in that state. Over 94% of reported cumulative water use occurred in just seven of
13 the 20 states in the EPA FracFocus project database: Texas, Pennsylvania, Arkansas, Colorado,
14 Oklahoma, Louisiana, and North Dakota (U.S. EPA. 2015b). Hydraulic fracturing is a small
15 percentage when compared to total water use (<1%) and consumption (<3%) in each individual
16 state (see Appendix Table B-l). Other studies have shown similar results, with hydraulic fracturing
17 water use and consumption ranging from less than 1% of total use in West Virginia (West Virginia
18 PEP. 2013). Colorado (Colorado Division of Water Resources: Colorado Water Conservation Board:
19 Colorado Oil and Gas Conservation Commission. 2014). and Texas (Nicotetal.. 2014: Nicot and
20 Scanlon. 2012). to approximately 4% in North Dakota (North Dakota State Water Commission.
21 2014).
4.4.2. County Scale
2 2 Cumulative water use and consumption for hydraulic fracturing is also relatively small in most, but
23 not all, counties in the United States (see Table 4-2, Figure 4-1, and Figure 4-2a,b). Reported
1 This could result in an overestimation because the estimate of 20,000 wells was derived in part from FracFocus, and
these wells are not necessarily specific to shale gas; they may include other types of wells that use less water (e.g., CBM).
The estimate of 1.5 million gal (5.7 million L) per well based on the EPA FracFocus project database likely leads to a more
robust estimate when used to calculate national cumulative water use for hydraulic fracturing because it includes wells
from multiple formation types (i.e., shale, tight sand, and CBM), some of which use less water than shale gas wells on
average (U.S. EPA.2015b).
2 The USGS compiles water use estimates approximately every five years in the National Water Census including the 1995
Census in Solley etal. (1998): 2005 Census in Kenny etal. (2009): and 2010 Census in Maupinetal. (2014). The 2010
version is the most updated version available. The Census includes uses such as public supply, irrigation, livestock,
aquaculture, thermoelectric power, industrial, and mining at the national, state, and county scale. The 2010 Census
included hydraulic fracturing water use in the mining category; there was no designated category for hydraulic fracturing
alone.
Percentages were calculated by averaging annual water use for hydraulic fracturing in 2011 and 2012 for a given state
or county (U.S. EPA. 2015b). and then dividing by 2010 USGS total water use (Maupinetal.. 2014) and multiplying by 100.
Note, the annual hydraulic fracturing water use reported in FracFocus was not added to the 2010 total USGS water use
value in the denominator, and is simply expressed as a percentage compared to 2010 total water use or consumption.
This was done because of the difference in years between the two datasets, and because the USGS 2010 Census (Maupin
etal.. 2014) included hydraulic fracturing water use estimates in their mining category. This approach is consistent with
that of other literature on this topic; see Nicot and Scanlon (2012). See footnotes for Appendix Table B-l and Table 4-2 for
description of the consumption estimate calculations.
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1 fracturing water use in FracFocus in 2011 and 2012 was less than 1% compared to 2010 USGS total
2 water use in 299 of the 401 reporting counties [U.S. EPA. 2015b) (see Figure 4-2a and Appendix
3 Table B-2). However, hydraulic fracturing water use was 10% or more compared to total water use
4 in 26 counties, 30% or more in nine counties, and 50% or more in four counties (see Table 4-2 and
5 Figure 4-2a). McMullen County in Texas had the highest percentage at over 100% compared to
6 2010 total water use.1 Total consumption estimates followed the same pattern, but with more
7 counties in the higher percentage categories (hydraulic fracturing water consumption was 10% or
8 more compared to total water consumption in 53 counties; 30% or more in 25 counties; 50% or
9 more in 16 counties; and over 100% in four counties) (see Table 4-2 and Figure 4-2b). Note,
10 estimates based on the EPA's FracFocus project database may form an incomplete picture of
11 hydraulic fracturing water use in a given state or county because the majority of states with data in
12 the project database did not require disclosure to FracFocus during the time period analyzed (U.S.
13 EPA, 2015a]. We conclude that this likely does not substantially alter the overall patterns observed
14 in Figure 4-2a,b (see Text Box 4-1 for further details).
15 These percentages depend both upon the absolute water use and consumption for hydraulic
16 fracturing and the relative magnitude of other water uses and consumption in that state or county.
17 For instance, a rural county, with a small population, might have relatively low total water use prior
18 to hydraulic fracturing.2 Also, just because water is used in certain county does not necessarily
19 mean it originated in that county. While the cost of trucking water can be substantial (Slutz etal..
20 2012), and the industry tends to acquire water from nearby sources when possible (see Section
21 4.2.1), water can also be piped in from more distant, regional supplies. Despite these caveats, it is
22 clear that hydraulic fracturing is generally a relatively small user (or consumer) of water at the
23 county level, with the exception of a small number of counties where water use and consumption
24 for fracturing can be high relative to other uses and consumption.
Estimates of use or consumption exceeded 100% when hydraulic fracturing water use averaged for 2011 and 2012
exceeded total water use or consumption in that county in 2010.
2 For example, McMullen County, Texas mentioned above contains a small number of residents (707 people in 2010,
according to the U.S. Census Bureau (2014)).
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Table 4-2. Annual average hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010, by county.
Only counties where hydraulic fracturing water was 10% or greater compared to 2010 total water use
are shown (for full table see Appendix Table B-2). Annual average hydraulic fracturing water use data
in 2011 and 2012 from the EPA's FracFocus project database (U.S. EPA. 2015b). Total annual water use
data in 2010 from the USGS (Maupin et al., 2014). States listed by order of appearance in the chapter.
State
Texas
Pennsylvania
West Virginia
Ohio
County
McMullen
Karnes
La Salle
Dimmit
Irion
Montague
De Witt
Loving
San Augustine
Live Oak
Wheeler
Cooke
Susquehanna
Sullivan
Bradford
Tioga
Lycoming
Doddridge
Carroll
Total annual
water use in
2010 (millions
ofgal)3
657.0
1861.5
2474.7
4073.4
1335.9
3989.5
2394.4
781.1
1131.5
1916.3
6522.6
4533.3
1617.0
222.7
4354.5
2909.1
5854.6
405.2
1127.9
Annual average
hydraulic fracturing
water use in 2011
and 2012
(millions of gal)b
745.9
1055.2
1288.7
1794.2
411.4
925.3
546.6
138.4
182.1
294.0
858.0
454.3
751.3
66.5
1059.4
566.3
704.6
78.5
152.7
Hydraulic
fracturing
water use
compared to
total water use
(%)C
113.5
56.7
52.1
44.0
30.8
23.2
22.8
17.7
16.1
15.3
13.2
10.0
46.5
29.9
24.3
19.5
12.0
19.4
13.5
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
350.4
120.1
93.7
81.3
74.5
77.8
48.6
94.1
50.8
40.1
21.5
29.9
123.4
79.8
78.2
47.3
33.8
69.4
37.3
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State
North Dakota
Arkansas
Louisiana
County
Mountrail
Dunn
Burke
Divide
Van Buren
Red River
Sabine
Total annual
water use in
2010 (millions
ofgal)3
1248.3
1076.8
394.2
806.7
1587.8
1606.0
1522.1
Annual average
hydraulic fracturing
water use in 2011
and 2012
(millions of gal)b
449.4
309.5
63.6
102.2
899.6
569.6
395.2
Hydraulic
fracturing
water use
com pa red to
total water use
(%)C
36.0
28.7
16.1
12.7
56.7
35.5
26.0
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
98.3
43.1
40.8
18.6
168.8
83.2
76.6
a County-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on November
11, 2014. Total water withdrawals per day were multiplied by 365 days to estimate total water use for the year
(Maupin etal., 2014).
b Average of water used for hydraulic fracturing in 2011 and 2012 as reported to FracFocus (U.S. EPA, 2015b).
c Percentages were calculated by averaging annual water use for hydraulic fracturing reported in FracFocus in
2011 and 2012 for a given state or county (U.S. EPA. 2015b), and then dividing by 2010 USGS total water use
(Maupin etal., 2014) and multiplying by 100.
d Consumption values were calculated with use-specific consumption rates predominantly from the USGS,
including 19.2% for public supply, 19.2% for domestic use, 60.7% for irrigation, 60.7% for livestock, 14.8% for
industrial uses, 14.8% for mining (Solley et al., 1998), and 2.7% for thermoelectric power (USGS, 2014h). We used
rates of 71.6% for aquaculture (from Verdegem and Bosma, 2009) (evaporation per kg fish + infiltration per
kg)/total water use per kg); and 82.5% for hydraulic fracturing (consumption value calculated by taking the
median value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this
assessment and then subtracting from 100%). If a range of values was given, the midpoint was used. Note, this
aspect of consumption is likely a low estimate since much of this produced water (injected water returning to the
surface) is not subsequently treated and reused, but rather disposed of in UIC Class II injection wells—see
Chapter 8).
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 4 - Water Acquisition
Annual Average
Water Use in Mgal
(number of counties)
^| > 500 (27)
^| 100-500(60)
^ 10-100(86)
1-10(115)
ElAshale basins
n State reporting
requirement
Figure 4-1. Annual average hydraulic fracturing water use in 2011 and 2012 by county (U.S. EPA, 2015b).
Source: (U.S. EPA, 2015b). Water use in millions of gallons (Mgal). Counties shown with respect to major U.S. Energy Information Administration
(EIA) shale basins (EIA, 2015b). Orange borders identify states that required some degree of reporting to FracFocus 1.0 in 2011 and 2012.
June 2015
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Hydraulic fracturing water
consumption compared to total wa
consumption (number of counties)
Figure 4-2. (a) Annual average hydraulic fracturing water use in 2011 and 2012 compared to
total annual water use in 2010, by county, expressed as a percentage; (b) Annual
average hydraulic fracturing water consumption in 2011 and 2012 compared to
total annual water consumption in 2010, by county, expressed as a percentage.
Annual average hydraulic fracturing water use data in 2011 and 2012 from the EPA's FracFocus project
database (U.S. EPA. 2015b). Total annual water use data in 2010 from the USGS (Maupin et al.. 2014).
See Table 4-2 for descriptions of calculations for estimating consumption. Counties shown with
respect to major U.S. EIA shale basins (EIA, 2015b). Orange borders identify states that required some
degree of reporting to FracFocus 1.0 in 2011 and 2012. Note: Values over 100% denote counties
where the annual average hydraulic fracturing water use or consumption in 2011 and 2012 exceeded
the total annual water use or consumption in that county in 2010.
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Text Box 4-1. Using the EPA's FracFocus Project Database to Estimate Water Use for Hydraulic
Fracturing.
1 FracFocus is a national hydraulic fracturing registry managed by the Ground Water Protection Council and the Interstate
2 Oil and Gas Compact Commission (GWPC.2015). The registry was established in 2011 for voluntary reporting. However,
3 six of the 20 states discussed in this assessment required disclosure to FracFocus at various points between January 1,
4 2011 and February 28,2013, the time period analyzed by the EPA; another three of the 20 states offered the choice of
5 reporting to FracFocus or the state during this same time period [U.S. EPA. 2015a). Estimates based on the EPA's
6 FracFocus project database likely form an incomplete picture of hydraulic fracturing water use because most states with
7 data in the project database (14 out of 20) did not require disclosure to FracFocus during the time period analyzed [U.S.
8 EPA. 20153).
9 Cumulative water use for fracturing is a function of the water use per well and the total number of wells fractured. For
10 water use per well, we found seven literature values for comparison with values from the EPA's FracFocus project
11 database. On average, water use estimates per well in the project database were 77% of literature values (the median was
12 86%); Colorado's Denver Basin was the only location where the project database estimate as a percentage of the
13 literature estimate was low (14%) (see Appendix Table B-3). In general, water use per well estimates from the EPA's
14 FracFocus project database appear to provide a reasonable approximation for most areas for which we have data, with
15 the exception of the Denver Basin of Colorado.
16 For number of wells, we compared data in the EPA's FracFocus project database to numbers available in state databases
17 from North Dakota, Pennsylvania, and West Virginia (see Appendix Table B-4). These were the state databases from
18 which we could distinguish hydraulically fractured wells from total oil and gas wells. On average, we found that the EPA
19 FracFocus project database included 67% of the wells listed in state databases for 2011 and 2012 (see Appendix Table B-
20 4). Unlike North Dakota and Pennsylvania, West Virginia did not require operators to report fractured wells to FracFocus
21 during this time period, possibly explaining its lower reporting rate. Multiplying the average EPA FracFocus project
22 database values of77% for water use per well and 67% for well counts yields 52%. Thus, the EPA FracFocus project
23 database estimates for water use could be slightly over half of the estimates from these three state databases during this
24 time period. These values are based on a small sample sizes (7 literature values and 3 state databases) and should be
2 5 interpreted with caution. Nevertheless, these numbers at the very least suggest that estimates based on the EPA's
26 FracFocus project database may form an incomplete picture of hydraulic fracturing water use during this time period.
27 To assess how this might affect hydraulic fracturing water use estimates in this chapter, we doubled the water use value
28 in the EPA's FracFocus project database for each county, an adjustment much higher than any likely underestimation.
29 Even with this adjustment, fracturing water use was still less than 1% of 2010 total water use in the majority of U.S.
30 counties (299 counties without adjustment versus 280 counties with adjustment). The number of counties where
31 hydraulic fracturing water use was 30% or more of 2010 total county water use increased from nine to 21 with the
32 adjustment.
3 3 These results indicate that most counties have relatively low hydraulic fracturing water use, relative to total water use,
34 even when accounting for likely underestimates. Since consumption estimates are derived from use, these will also follow
35 the same pattern. Thus, potential underestimates based on the EPA's FracFocus project database likely do not
36 substantially alter the overall pattern shown in Figure 4-2. Rather, underestimates of hydraulic fracturing water use
37 would mostly affect the percentages in the small number of counties where fracturing already constitutes a higher
38 percentage of total water use and consumption.
4.5. Potential for Water Use Impacts by State
39 High fracturing water use or consumption alone does not necessarily result in impacts to drinking
40 water resources. Rather, impacts most often result from the combination of water use and water
41 availability at a given withdrawal point Where water availability is high compared to water
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1 withdrawn for hydraulic fracturing, this water use can be accomodated. However, where water
2 availability is low compared to use, hydraulic fracturing withdrawals are more likely to impact
3 drinking water resources. Water management, such as the type of water used or the timing or
4 location of withdrawals, can modify this relationship. All of these factors can vary considerably by
5 location.
6 Besides potential water quantity effects, water withdrawals for hydraulic fracturing have the
7 potential to alter the quality of drinking water resources. This possibility is not unique to the oil and
8 gas industry, as any large-volume water withdrawal has the potential to affect water quality.
9 Although there is little research that specifically connects water withdrawals for hydraulic
10 fracturing to potential water quality impacts, multiple studies have described the impact of drought
11 or industrial withdrawals on water quality [Georgakakos etal., 2014: Whitehead etal., 2009:
12 Murdoch etal.. 2000: Schindler. 1997}. For instance, in the absence of controls, surface water
13 withdrawals can lower water levels and alter stream flows, potentially decreasing a stream's
14 capacity to dilute contaminants [Mitchell etal.. 2013a: Entrekin etal.. 2011: NYSDEC. 2011: van
15 VlietandZwolsman. 2008: IPCC. 2007: Environment Canada. 2004: Murdoch etal.. 20001.
16 Furthermore, ground water withdrawals exceeding natural recharge rates may lower the water
17 level in aquifers, potentially mobilizing contaminants or allowing the infiltration of lower-quality
18 water from the land surface or adjacent formations [USGS, 2003: Jackson etal., 2001].
19 In the following section, we assess the potential for water quantity and quality impacts by location,
20 organized by state. We focus our discussion on the 15 states that account for almost all disclosures
21 reported in the EPA FracFocus project database [U.S. EPA. 2015b]: Texas (Section 4.5.1); Colorado
22 and Wyoming (Section 4.5.2); Pennsylvania, West Virginia, and Ohio (Section 4.5.3); North Dakota
23 and Montana (Section 4.5.4); Oklahoma and Kansas (Section 4.5.5); Arkansas and Louisiana
24 (Section 4.5.6); and Utah, New Mexico, and California (Section 4.5.7).l Each section describes the
25 extent of hydraulic fracturing activity in that state or group of states; the type of water used in
26 terms of source, quality, and provisioning; and the water use per well. We then discuss cumulative
27 estimates and the potential for impacts to drinking water resources in the context of water
28 availability.
29 We have ordered the states by the number of hydraulically fractured wells reported, and combined
30 states with similar geographies or activity. Most of the available data did not allow us to assess the
31 potential for impacts at a finer resolution than the county scale. Any potential adverse impacts are
32 most likely to be observed locally at a particular withdrawal point Therefore, our analysis most
33 often suggests where the potential for impacts exists, but does not indicate where impacts will
34 occur at the local scale. Where possible, we utilize local-scale case studies in southern Texas,
35 western Colorado, and eastern Pennsylvania to provide details at a much finer resolution, and offer
36 insight into whether any impacts from water acquisition for hydraulic fracturing were realized in
37 these areas.
1 We do not highlight the remaining five states included in the EPA FracFocus project database because of low reported
activity: Virginia (90 disclosures), Alabama (55), Alaska (37), Michigan (15), and Mississippi (4).
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4.5.1. Texas
1 Hydraulic fracturing in Texas accounts for the bulk of the activity reported nationwide, comprising
2 48% of the disclosures in the EPA FracFocus project database fU.S. EPA. 2015bl (see Figure 4-3 and
3 Appendix Table B-5). There are five major basins in Texas: the Permian, Western Gulf (includes the
4 Eagle Ford play), Fort Worth (includes the Barnett play), TX-LA-MS Salt (includes the Haynesville
5 play), and the Anadarko (see Figure 4-4); together, these five basins contain 99% of Texas' reported
6 wells (see Appendix Table B-5).
Black Warrior
S^
^
Figure 4-3. Locations of wells in the EPA FracFocus project database, with respect to U.S. EIA
shale plays and basins (EIA, 2015; US. EPA, 2015b).
Note: Hydraulic fracturing is conducted in geologic settings other than shale; therefore, some wells on
this map are not associated with any EIA shale play or basin. (EIA. 2015b: U.S. EPA. 2015b).
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TX-LA-MS
Salt Marsh
HavnesviUe-Bossitr
Play
Figure 4-4. Major U.S. EIA shale plays and basins for Texas (EIA, 2015).
Source: (EIA, 2015b)
1 Types of water used: What is known about water sources in Texas largely comes from direct surveys
2 and interviews with industry operators and water suppliers [Nicot et al., 2014; Nicot et al., 20121.
3 Overall, ground water is the dominant source throughout most of the state [Nicot et al., 2014; Nicot et
4 al., 2012] (see Table 4-3). The exception is the Barnett Shale, where both surface and ground water
5 are used in approximately equal proportions.
6 Hydraulic fracturing in Texas uses mostly fresh water [Nicot etal.. 2012).* The exception is the far
7 western portion of the Permian Basin, where brackish water makes up an estimated 80% of total
8 hydraulic fracturing water use. Brackish water is used to a lesser extent in the Anadarko Basin and
9 the Midland portion of the Permian Basin (see Table 4-4). Reuse of wastewater as a percentage of
10 total water injected is generally very low (5% or less) in all major basins and plays in Texas, except
11 for the Anadarko Basin in the Texas Panhandle, where it is 20% (Nicot etal.. 2012] (see Table 4-1).
1 The EPA FracFocus report shows that "fresh" was the only source of water listed in 91% of all disclosures reporting a
source of water in Texas [U.S. EPA. 2015a). However, 19% of Texas disclosures included information related to water
sources [U.S. EPA.2015a).
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Table 4-3. Estimated proportions of hydraulic fracturing source water from surface and
ground water.
States listed by order of appearance in the chapter.
Location
Texas— Barn ett Shale
Texas— Eagle Ford Shale
Texas-TX-LA-MS Salt Basin0
Texas— Permian Basin
Texas— Anadarko Basin
Pennsylvania — Marcellus Shale, Susquehanna River Basin
West Virginia— Statewide, Marcellus Shale
Oklahoma— Statewide
Louisiana— Haynesville Shale
Surface water
50%a
10%b
30%b
0%b
20%b
78%d
91%e
63%f
87%g
Ground water
50%a
90%b
70%b
100%b
80%b
22%d
9%e
37%f
13%g
3 Nicotetal. (2014).
bNicotetal. (2012).
c Nicotetal. (2012) refer to this region of Texas as the East Texas Basin.
d Estimated proportions are for 2011 (U.S. EPA, 2015c).
e Estimated proportions are for 2012, the most recent estimate for a full calendar year available from West Virginia PEP
(2014). Data from the West Virginia DEP show the proportion of water purchased from commercial brokers as a separate
category and do not specify whether purchased water originated from surface or ground water. Therefore, we excluded
purchased water in calculating the relative proportions of surface and ground water shown in Table 4-3 (West Virginia DEP.
2014).
f Proportion of surface and ground water permitted in 2011 by Oklahoma's 90-day provisional temporary permits for oil and
gas mining. Temporary permits make up the majority of water use permits for Oklahoma oil and gas mining (Taylor. 2012).
g Data from October 1, 2009, to February 23, 2012, for 1,959 Haynesville Shale natural gas wells (LA Ground Water Resources
Commission. 2012).
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Table 4-4. Brackish water use as a percentage of total hydraulic fracturing water use in Texas'
main hydraulic fracturing areas, 2011.
Adapted from Nicot et al. (2012).a
Play
Barnett Shale
Eagle Ford Shale
Texas portion of the TX-LA-MS Salt Basin"
Permian Basin— Far West
Permian Basin— Midland
Anadarko Basin
Percent
3%
20%
0%
80%
30%
30%
a Nicot et al. (2012) present the estimated percentages of brackish, recycled/reused, and fresh water relative to total
hydraulic fracturing water use so that the percentages of the three categories sum to 100%.
Nicot et al. (2012) refer to this region of Texas as the East Texas Basin.
1 The majority of water used in Texas for hydraulic fracturing is self-supplied via direct ground or
2 surface water withdrawals [Nicot etal., 2014]. Less often, water is purchased from local
3 landowners, municipalities, larger water districts, or river authorities [Nicotetal.. 2014).
4 Water use per well: Water use per well varies across Texas' basins, with reported medians of
5 3.9 million gal (14.8 million L) in the Fort Worth Basin, 3.8 million gal (14.4 million L) in the
6 Western Gulf, 3.3 million gal (12.5 million L) in the Anadarko, 3.1 million gal (11.7 million L) in the
7 TX-LA-MS Salt, and 840,000 gal (3.2 million L) in the Permian (see Appendix Table B-5). Relatively
8 low water use in the Permian Basin, which contains roughly half the reported wells in the state, is
9 due to the abundance of vertical wells, mostly for oil extraction (Nicotetal., 2012].
10 Water use per well is increasing in most locations in Texas. In the Barnett Shale, water use per
11 horizontal well increased from a median of 1.25 million gal (4.73 million L) in 2001 to 4.7 million
12 gal (17.8 million L) in 2012, as the number of wells and horizontal lengths increased (Nicotetal.,
13 2014). Similar increases in lateral length and water use per well were reported for the
14 Texas-Haynesville, East Texas, Anadarko, and most of the Permian Basin (Nicotetal., 2012: Nicot
15 andScanlon. 2012].1
1 It should be noted that energy production also increases with lateral lengths, and therefore, water use per unit energy
produced—typically referred to as water intensity—may remain the same or decline despite increases in per-well water
use [Nicot etal.. 2014: Laurenzi and lersey. 2013).
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1 Cumulative water use/consumption: Cumulative water use and consumption for hydraulic fracturing
2 can be significant in some Texas counties. Texas contains five of nine counties nationwide where
3 operators used more than 1 billion gal (3.8 billion L) of water annually for hydraulic fracturing, and
4 five of nine counties nationwide where fracturing water use in 2011 and 2012 was 30% or more
5 compared to total water use in those counties in 2010 (see Table 4-2, Figure 4-2a, and Appendix
6 Table B-21'1'2
7 According to detailed county-level projections, water use for hydraulic fracturing is expected to
8 increase with oil and gas production in the coming decades, peaking around the year 2030 (Nicotet
9 al.. 2012). The majority of counties are expected to have relatively low cumulative water use for
10 fracturing in the future, but cumulative hydraulic fracturing water use could equal or exceed 10%,
11 30%, and 50% compared to 2010 total county water use in 30, nine, and three counties,
12 respectively, by 2030 (see Appendix Table B-7). Thus, potential hydraulic fracturing water
13 acquisition impacts in Texas may be most likely to occur over the next 15-25 years as water
14 demand for fracturing is highest
15 Potential for impacts: Of all locations surveyed in this chapter, the potential for water quantity and
16 quality impacts due to hydraulic fracturing water use appears to be highest in western and
17 southern Texas. This area includes the Anadarko, the Western Gulf (Eagle Ford play), and the
18 Permian Basins. According to Ceres (2014], 28% and 87% of the wells fractured in the Eagle Ford
19 play and Permian Basin, respectively, are in areas of high to extremely high water stress.3 A
20 comparison of hydraulic fracturing water use to water availability at the county scale also suggests
21 the potential for impacts (see Text Box 4-2 and Figure 4-5). The Texas Water Development Board
22 estimates that overall demand for water (including water for hydraulic fracturing) out to the year
23 2060 will outstrip supply in southern and western Texas (TWDB, 2012). Moreover, the state has
24 experienced moderate to extreme drought conditions for much of the last decade (National Drought
25 Mitigation Center. 2015). The 2012 Texas State Water Plan emphasizes that "in serious drought
26 conditions, Texas does not and will not have enough water to meet the needs of its people, its
27 businesses, and its agricultural enterprises" (TWDB. 2012).
28
1 Texas also contains 10 of the 25 counties nationwide where hydraulic fracturing water consumption was greater than or
equal to 30% of 2010 total water consumption (see Table 4-2).
2 Nicotand Scanlon (2012) found similar variation among counties when they compared hydraulic fracturing water
consumption to total county water consumption for the Barnett play. Their cumulative consumption estimates ranged
from 581 million gal (2.20 billion L) in Parker County to 2.7 billion gal (10.2 billion L) in Johnson County, representing
19.3% and 29.7% compared to total water consumption in those counties, respectively. Fracturing in Tarrant County, part
of the Dallas-Fort Worth area, consumed 1.6 billion gal (6.1 billion L) of water, 1.4% compared to total county water
consumption (Nicot and Scanlon. 2012).
3 Ceres (2014) compared well locations to areas categorized by a water stress index, characterized as follows: extremely
high (defined as annual withdrawals accounting for greater than 80% of surface flows); high (40-80% of surface flows);
or medium-to-high (20-40% of surface flows).
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Text Box 4-2. Hydraulic Fracturing Water Use as a Percentage of Water Availability Estimates.
1 Researchers at Sandia National Laboratories assessed county-level water availability across the continental
2 United States [Tidwell et al.. 2013]. Assessments of water availability in the United States are generally
3 lacking at the county scale, and this analysis—although undertaken for siting new thermoelectric power
4 plants—can be used to assess potential impacts of hydraulic fracturing.
5 The authors generated annual availability estimates for five categories of water: unappropriated surface
6 water, unappropriated ground water, appropriated water potentially available for purchase, brackish
7 groundwater, and wastewater from municipal treatment plants (Tidwell et al., 20131. In the western United
8 States, water is generally allocated by the principle of prior appropriation—that is, first in time of use is first
9 in right. New development must use unappropriated water or purchase appropriated water from vested
10 users. In their analysis, the authors assumed 5% of appropriated irrigated water could be purchased; they
11 also excluded wastewater required to be returned to streams and the wastewater fraction already reused.
12 Given regulatory restrictions, they considered no fresh water to be available in California for new
13 thermoelectric plants.
14 Combining their estimates of unappropriated surface and ground water and appropriated water potentially
15 available for purchase, we derived a fresh water availability estimate for each county (except for those in
16 California) and then compared this value to reported water use for hydraulic fracturing fU.S. EPA. 2015b). We
17 also added the estimates of brackish and wastewater to fresh water estimates to derive estimates of total
18 water availability and did a similar comparison. Since the water availability estimates already take into
19 account current water use for oil and gas operations, these results should be used only as indicator of areas
2 0 where shortages might arise in the future.
21 Overall, hydraulic fracturing water use represented less than 1% of fresh water availability in over 300 of the
22 395 counties analyzed (see Figure 4-5a). This result suggests that there is ample water available at the county
23 scale to accommodate hydraulic fracturing in most locations. However, there was a small number of counties
24 where hydraulic fracturing water use was a relatively high percentage of fresh water availability. In 17
25 counties, fracturing water use actually exceeded the index of fresh water available; all of these counties were
26 located in the state of Texas and were associated with the Anadarko, Barnett, Eagle Ford, and Permian
27 basins/plays (see Figure 4-4). In Texas counties with relatively high brackish water availability, hydraulic
28 fracturing water use represented a much smaller percentage of total water availability (fresh + brackish +
29 wastewater) (see Figure 4-5b). This finding illustrates that potential impacts can be avoided or reduced in
30 these counties through the use of brackish water or wastewater for hydraulic fracturing; a case study in the
31 Eagle Ford play in southwestern Texas confirms this (see Text Box 4-3).
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Text Box 4.2 (continued): Hydraulic Fracturing Water Use as a Percentage of Water
Availability Estimates.
Figure 4-5. Annual average hydraulic fracturing water use in 2011 and 2012 compared to
(a) fresh water available and (b) total water (fresh, brackish, and wastewater)
available, by county, expressed as a percentage.
Counties shown with respect to major U.S. EIA shale basins (EIA, 2015b). Orange borders identify
states that required some degree of reporting to FracFocus 1.0 in 2011 and 2012. Data from U.S.
EPA(2015b) and Tidwell et al. (2013); data from Tidwell et al. (2013) supplied from the U.S.
Department of Energy (DOE) National Renewable Energy Laboratory on January 28, 2014 and
available upon request from the U.S. DOE Sandia National Laboratories. The analysis by Tidwell et
al. (2013) was done originally for thermoelectric power generation. As such, it was assumed that
no fresh water could be used in California for this purpose due to regulatory restrictions, and
therefore no fresh water availability data were given for California (a). The total water available
for California is the sum of brackish water plus wastewater only (b).
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1 Surface water availability is generally low in western and southern Texas (Figure 4-6a), and both
2 fracturing operations and residents rely heavily on ground water (Figure 4-6b). Similar to trends
3 nationally, ground water aquifers in Texas have experienced substantial declines caused by
4 withdrawals (Konikow. 2013b: TWDB. 2012: George etal.. 20111. Ground water in the Pecos Valley,
5 Gulf Coast, and Ogallala aquifers in southern and western Texas is estimated to have declined by
6 roughly 5,11, and 43 cubic miles (21, 45.5, and 182 cubic kilometers), respectively, between 1900
7 and 2008 (Konikow, 201 Sb].1 The Texas Water Development Board expects ground water supply in
8 the major aquifers to decline by 30% between 2010 and 2060, mostly due to declines in the
9 Ogallala aquifer (TWDB, 2012].2 Irrigated agriculture is by far the dominantuser of water from the
10 Ogallala aquifer (USGS, 2009], but fracturing operations, along with other uses, now contribute to
11 the aquifer's depletion.
i The estimate of total net volumetric groundwater depletion for the Gulf Coast aquifer is the sum of the individual
depletion estimates for the north (Houston area), central, and southern (Winter Garden area) parts of the Texas Gulf
Coast aquifer. Ground water depletion from the Carrizo-Wilcox aquifer is included in the estimate for the southern
portion of the Gulf Coast aquifer (Konikow. 2013b).
2 TWDB (2012) defines ground water supply as the amount of ground water that can be produced given current permits
and existing infrastructure. By contrast, TWDB (2012) defines ground water availability as the amount of ground water
that is available regardless of legal or physical availability. Total ground water availability in Texas is expected to decline
by approximately 24% between 2010 and 2060 (TWDB. 2012).
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Ratio of Ground Water Pumping
to Stream Flow + Pumping
<0.12 m 0.59-0.70
0,12-0.25
0,25-0.37
0,37-0.59
0.70-1.00
No Data
Figure 4-6. (a) Estimated annual surface water runoff from the USGS; (b) Reliance on ground
water as indicated by the ratio of ground water pumping to stream flow and
pumping.
Estimates for Figure 4-6a were calculated at the 8-digit hydrological unit code (HUC) scale by dividing
annual average daily stream flow (from October 1, 2012 to September 30, 2013) by HUC area. Data
accessed from the USGS (USGS. 2014g). Higher ratios (darker blues) in Figure 4-6b indicate greater
reliance on ground water. Figure redrawn from Tidwell et al. (2012), using data provided by the U.S.
Department of Energy's Sandia National Laboratories on December 12, 2014.
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1 Extensive ground water pumping can induce vertical mixing of high-quality ground water with
2 recharge water from the land surface that has been contaminated by nitrate or pesticides, or with
3 lower-quality ground water from underlying geologic formations [USGS. 2009: Konikow and Kendy.
4 2005]. Ground water quality degradation associated with aquifer pumping is well documented in
5 the southern portion of the Ogallala aquifer in the Texas panhandle. The quality of ground water
6 used by many private, public supply, and irrigation wells is poorest in the aquifer's southern
7 portion, with elevated concentrations of TDS, chloride, nitrate, fluoride, manganese, arsenic, and
8 uranium [Chaudhuri and Ale. 2014a: USGS. 2009. 2007). Elevated levels of these constituents result
9 from both natural processes and human activities such as ground water pumping [Chaudhuri and
10 Ale, 2014a: USGS, 2009]. Similar patterns of ground water quality degradation (i.e., salinization and
11 contamination) have also been observed in other Texas aquifers.1
12 Ground water withdrawals for hydraulic fracturing, along with irrigation and other uses, may
13 contribute to water quality degradation associated with intensive aquifer pumping in western and
14 southern Texas. Areas with numerous high-capacity wells and large amounts of sustained ground
15 water pumping are most likely to experience ground water quality degradation associated with
16 withdrawals [USGS, 2009, 2007]. Given that Texas is prone to drought conditions, ground water
17 recharge is limited, making the already declining aquifers in southern and western Texas especially
18 vulnerable to further ground water depletion and resulting potential impacts to ground water
19 quality [USGS. 2009: Tackson etal.. 2001].
20 This survey of the available literature and data points to the potential for impacts in southern and
21 western Texas, but generally does not indicate whether impacts will occur at the local scale around
2 2 specific withdrawal points. An exception is a case study in the Eagle Ford play of southwestern
2 3 Texas that compared water demand for hydraulic fracturing with water supplies at the scale of the
24 play, county, and one square mile [Scanlon et al.. 2014]. The authors observed generally adequate
25 water supplies for hydraulic fracturing, except in specific locations, where they found excessive
26 drawdown of local ground water in a small proportion (~6% of the area] of the Eagle Ford play
27 (see Text Box 4-3].
i Persistent salinity has also been observed in west Texas, specifically in the southern Ogallala, northwest Edwards-
Trinity (plateau), and Pecos Valley aquifers, largely due to prolonged irrigational ground water pumping and ensuing
alteration of hydraulic gradients leading to ground water mixing [Chaudhuri and Ale. 2014b). High levels of ground water
salinization associated with prolonged aquifer depletion have also been documented in the Carrizo-Wilcox and southern
Gulf Coast aquifers, underlying the Eagle Ford Shale in south Texas [Chaudhuri and Ale. 2014b: Konikow. 2013b: Boghici.
2009). Further, elevated levels of constituents, including nitrate, lead, fluoride, chloride, sulfate, iron, manganese, and
TDS, have been reported in the Carrizo-Wilcox aquifer [Boghici. 2009).
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Text Box 4-3. Case Study: Water Profile of the Eagle Ford Play, Texas.
1 Researchers from the University of Texas published a detailed case study of water supply and demand for
2 hydraulic fracturing in the Eagle Ford play in southwestern Texas [Scanlon et al.. 2014]. This effort assembled
3 detailed information from state and local water authorities, and proprietary industry data on hydraulic
4 fracturing, to develop a portrait of water resources in this 16-county area.
5 Scanlon et al. [2014] compared water demand for hydraulic fracturing currently and over the projected play
6 life (20 years] relative to water supply from ground water recharge, ground water storage (brackish and
7 fresh], and stream flow. Using detailed ground water availability models developed by the Texas Water
8 Development Board, they reported that water demand for hydraulic fracturing in 2013 was 30% of annual
9 ground water recharge in the play area, and over the 20-year play lifespan it was projected to be 26% of
10 groundwater recharge, 5-8% of fresh groundwater storage, and 1% of brackish ground water storage. The
11 dominant water user in the play is irrigation (62 to 65% of water use, 53 to 55% of consumption], as
12 compared with hydraulic fracturing (13% of water use and 16% of consumption]. At the county level,
13 projected water demand for hydraulic fracturing over the 20-year period was low relative to freshwater
14 supply (ranging from 0.6-27% by county, with an average of 7.3%]. Similarly, projected total water demand
15 from all uses was low relative to supply, excluding two counties with high irrigation demands (Frio, Zavala],
16 and one county with no known ground water supplies (Maverick].
17 Although supply was found to be sufficient even in this semi-arid region, there were important caveats
18 especially at sub-county scales. The researchers found no water level declines over much of the play area
19 assessed (69% of the play area], yet in some areas they estimated ground water drawdowns of up to 50 feet
20 (12% of the play area], and in others of 100 feet or more (6% of the play area]. This was corroborated with
21 well monitoring data that showed a sharp decline in water levels in several ground water monitoring wells
22 after hydraulic fracturing activity increased in 2009. The researchers concluded that any impacts in these
23 locations could be minimized if brackish ground water were used. Projected hydraulic fracturing water use
24 represents less than 1% of total brackish ground water storage in the play area. By contrast, they concluded
25 there is limited potential for reuse of wastewater in this play because of small volumes available (less than or
2 6 equal to 5% of hydraulic fracturing water requirements].
27 The potential for water quantity and quality effects appears to be lower in north-central and
28 eastern Texas, in areas including the Barnett and Haynesville plays. Residents obtain water for
29 domestic use—which includes use of water for drinking—from a mixture of ground water and
30 surface water sources (see Appendix Table B-6). Counties encompassing Dallas and Fort Worth rely
31 mostly on publically-supplied surface water [TWDB, 2012] (see Appendix Table B-6].
32 Although the Trinity, the major aquifer in northeast Texas, is projected to decline only slightly
33 between 2010 and 2060 (TWDB. 2012], Beneetal. (2007] estimate that hydraulic fracturing
34 ground water withdrawals will increase from 3% of total ground water use in 2005 to 7%-13% in
35 2025, suggesting the potential for localized aquifer drawdown and potential impacts to water
36 quality. Additionally, ground water quality degradation associated with aquifer drawdown has been
37 documented in the Trinity and Woodbine aquifers underlying much of the Barnett play, with both
38 aquifers showing high levels of salinization (Chaudhuri and Ale, 2013].
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1 Overall, the potential for impacts appears higher in western and southern Texas, compared to the
2 northeast part of the state. Impacts are likely to be localized drawdowns of ground water, as shown
3 by a detailed case study of the Eagle Ford play (see Text Box 4-3). Scanlonetal. [2014] suggested
4 that a shift towards brackish water use could minimize potential future impacts to fresh water
5 resources. This finding is consistent with our county-level data (see Text Box 4-2).
4.5.2. Colorado and Wyoming
6 Colorado had the second highest number of disclosures in the EPA FracFocus project database,
7 (13% of disclosures) (see Figure 4-3 and Appendix Table B-5). We combine Colorado and Wyoming
8 because of their shared geology of the Denver Basin (including the Niobrara play) and the Greater
9 Green River Basin (see Figure 4-7). There are three major basins reported for Colorado: the Denver
10 Basin; the Uinta-Piceance Basin; and the Raton Basin. Together these basins contain 99% of
11 reported wells in the state, although the bulk of the activity in Colorado is in the Denver Basin (see
12 Appendix Table B-5). Fewer wells (roughly 4% of disclosures) are present in Wyoming. There are
13 two major basins reported for Wyoming (Greater Green River and Powder River) that together
14 contain 86% of activity in the state (see Appendix Table B-5).
Figure 4-7. Major U.S. EIA shale plays and basins for Colorado and Wyoming (EIA, 2015).
Source: (EIA, 2015b)
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Types of water used: Water for hydraulic fracturing in Colorado and Wyoming comes from both
2 ground water and surface water, as well as reused wastewater [Colorado Division of Water
3 Resources: Colorado Water Conservation Board: Colorado Oil and Gas Conservation Commission.
4 2014: BLM, 2013b]. The only publicly available information on water sources for each state is a list
5 of potential sources; it does not appear that either state provides more specific information on
6 water sources for hydraulic fracturing. In the Uinta-Piceance Basin of northwestern Colorado, the
7 EPA [2015c] reports that most of the fresh water used for fracturing comes from surface water,
8 although fresh water sources make up a small proportion of the total water used. In the Denver
9 Basin (Niobrara play) of southeastern Wyoming, qualitative information suggests that ground
10 water supplies much of the water used for fracturing, although no data were available to
11 characterize the ratio of ground water to surface water withdrawals [AMEC, 2014: BLM, 2013b:
12 Tyrrell. 20121
13 Non-fresh water sources (e.g., industrial and municipal wastewater, brackish ground water, and
14 reused hydraulic fracturing wastewater) are sometimes listed as potential alternatives to fresh
15 water for fracturing in both Colorado and Wyoming [Colorado Division of Water Resources:
16 Colorado Water Conservation Board: Colorado Oil and Gas Conservation Commission, 2014: BLM,
17 2013b): no data are available to show the extent to which these non-fresh water sources are used at
18 the state or basin level. In northwest Colorado's Garfield County (Uinta-Piceance Basin), the EPA
19 (2015c) reports that fresh water is used solely for drilling and that reused wastewater supplies
20 nearly all the water for hydraulic fracturing (see Table 4-1). This estimate of reused wastewater as
21 a percentage of injected volume is markedly higher than in other locations and results from the
22 geologic characteristics of the Piceance tight sand formation, which has naturally high water
23 content and produces large volumes of relatively high-quality wastewater (U.S. EPA. 2015c).
24 In contrast, a study by Goodwin etal. (2014) assumed no reuse of wastewater for hydraulic
25 fracturing operations by Noble Energy in the Denver-Julesburg Basin of northeastern Colorado (see
26 Table 4-1). It is unclear whether this assumption is indicative of reuse practices of other companies
27 in the Denver-Julesburg Basin. The difference in reused wastewater rates reported by the EPA
28 (2015c) and Goodwin etal. (2014) may indicate an east-west divide in Colorado (i.e., low reuse in
29 the east versus high reuse in the west), due at least in part to differences in wastewater volumes
30 available for reuse. However, further information is needed to adequately characterize reuse
31 patterns in Colorado.
32 Water Use per Well: Water use per well varies across Colorado, with median values of 1.8 million,
33 400,000, and 96,000 gal (6.8 million, 1.5 million, and 363,000 L) in the Uinta-Piceance, Denver, and
34 Raton Basins, respectively according to the EPA FracFocus project database (see Appendix Table B-
35 5). Low water volumes per well are reported in Wyoming (see Appendix Table B-5). Low volumes
36 reported for the Raton Basin of Colorado and the Powder River Basin of Wyoming are due to the
37 prevalence of CBM extraction in these locations fU.S. EPA. 20151: USGS. 2014dl
38 More difficult to explain are the low volumes reported for the Denver Basin in the EPA FracFocus
39 project database. These values are lower than any other non-CBM basin reported in Appendix Table
40 B-5. Goodwin etal. (2014) report much higher water use per well in the Denver Basin, with a
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1 median of 2.8 million gal (10.6 million L) (although only usage for the Wattenberg Field was
2 reported). Indeed, the 10th-90thpercentiles (2.4-3.8 million gal) (9.1 to 14.4 million L) from
3 Goodwin etal. (2014) are almost completely above those from the EPA FracFocus project database
4 for the Denver Basin (see Appendix Table B-5).1 It is difficult to draw clear conclusions because of
5 differences in scale (i.e., field in Goodwin versus basin in the project database) and operators (i.e.,
6 Noble Energy in Goodwin versus all in the project database). However, it seems plausible that the
7 EPA FracFocus project database may be incomplete for estimating the amount of water used per
8 well in the Denver Basin.
9 Trends in water use per well are generally lacking for Colorado, with the exception of those
10 reported by Goodwin etal. (2014). They found that water use per well is increasing with well
11 length in the Denver Basin; however, they also observed that water intensity (gallons of water per
12 unit energy extracted) did not change, since energy recovery increased along with water use.
13 Cumulative water use/consumption: Hydraulic fracturing operations in Colorado cumulatively use
14 billions of gallons of water, but this amount is a small percentage compared to total water used or
15 consumed at the county scale. Operators in both Garfield and Weld Counties, located in the Uinta-
16 Piceance and Denver Basins, respectively, use more than 1 billion gal (3.8 billion L) annually.
17 Fracturing water use and consumption in these counties exceed those in all other Colorado counties
18 combined (see Appendix Table B-2), but the water used for hydraulic fracturing in Garfield and
19 Weld counties is less than 2% and 3% compared to 2010 total water use and consumption,
20 respectively. In comparison, irrigated agriculture accounts for over 90% of the water used in both
21 counties (Maupinetal.. 2014: Kenny etal.. 2009). Overall, hydraulic fracturing accounts for less
22 than 2% compared to 2010 total water use in all Colorado counties represented in the EPA
23 FracFocus project database (see Appendix Table B-2). Water use estimates based on the EPA
24 FracFocus project database may be low relative to literature and state estimates (Text Box 4-1), but
25 even if estimates from the project database were doubled, hydraulic fracturing water use and
26 consumption would still be less than 4% and 5.5% compared to 2010 total water use and
27 consumption, respectively, in each Colorado county.
28 In Wyoming, reported water use for hydraulic fracturing is small compared to Colorado (see
29 Appendix Table B-l). Fracturing water use and consumption did not exceed 1% of 2010 total water
30 use and consumption, respectively, in any county (see Appendix Table B-2). Unlike Colorado,
31 Wyoming did not require disclosure to FracFocus during the time period analyzed by the EPA (U.S.
32 EPA. 2015al (see Appendix Table B-5).
33 The Colorado Division of Water Resources et al. (2014) project that annual water use for hydraulic
34 fracturing in the state will increase by approximately 16% between 2012 and 2015, but demand in
1 Different spatial extents might explain these differences, since Goodwin etal. (2014) focus on 200 wells in the
Wattenberg Field of the Denver Basin; however. Weld County is the center of activity in the Wattenberg Field, and the EPA
FracFocus project database contains 3,011 disclosures reported in Weld County, with a median water use per of 407,442
gal (1,542,340 L), similar to that for the basin as a whole.
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1 later years is unclear. Even with an increase of 16% or more, hydraulic fracturing would still
2 remain a relatively small user of water at the county scale in Colorado.
3 Potential for impacts: The potential for water quantity and quality impacts appears to be low at the
4 county scale in Colorado and Wyoming, because fracturing accounts for a low percentage of total
5 water use and consumption (see Figure 4-2a,b). This conclusion is also supported by the
6 comparison of hydraulic fracturing water use to water availability at the county scale (see Text Box
7 4-2 and Figure 4-5a,b). However, counties in Colorado and Wyoming may be too large to detect the
8 potential for impacts, and local scale studies help provide details at a finer resolution. In a multi-
9 scale case study in western Colorado, the EPA (2015c] also did not observe any impacts in the
10 Upper Colorado River Basin. Due to the high reuse rate of wastewater, they did not identify any
11 locations where fracturing currently contributed to locally high water use intensity. They did
12 conclude, however, that future water use effects were possible (see Text Box 4-4).
Text Box 4-4. Case Study: Impact of Water Acquisition for Hydraulic Fracturing on Local Water
Availability in the Upper Colorado River Basin.
13 The EPA (2015c) conducted a case study to explore the impact of hydraulic fracturing water demand on water availability
14 at the river basin, county, and local scales in the semi-arid Upper Colorado River Basin (UCRB) of western Colorado. The
15 study area overlies the Piceance geologic basin with natural gas in tight sands. Water withdrawal impacts were quantified
16 using a water use intensity index (i.e., the ratio between the volume of water withdrawn at a site for hydraulic fracturing
17 and the volume of available water). Researchers obtained detailed site-specific data on hydraulic fracturing water usage
18 from state and regional authorities, and estimated available water supplies using observations at USGS gage stations and
19 empirical and hydrologic modeling.
20 They found that water supplies accessed for oil and gas demand were concentrated in Garfield County, and most fresh
21 water withdrawals were concentrated within the Parachute Creek watershed (198 mi2). However, fresh water makes up a
22 small proportion of the total water used for fracturing due to large quantities of high-quality wastewater produced from
23 the Piceance tight sands. Fresh water is used only for drilling, and the water used for fracturing is reported to be 100%
24 reused wastewater (see Table 4-1). Due to the high reuse rate. The EPA (2015c) did not identify any locations in the
2 5 Piceance play where fracturing contributed to locally high water use intensity.
26 Scenario analyses demonstrated a pattern of increasing potential impact with decreasing watershed size in the UCRB. The
2 7 EPA (2015c) examined hydraulic fracturing water use intensity under the current rates of both directional (S-shaped) and
2 8 horizontal drilling. They showed that for the more water-intensive horizontal drilling, watersheds had to be larger to
29 meet the same index of water use intensity (0.4) as that for directional drilling (100 mi2 for horizontal drilling, as
30 compared to 30 mi2 for directional drilling). To date, most wells have been drilled directionally into the Piceance tight
31 sands, although a trend toward horizontal drilling is expected to increase annual water use per well by about 4 times.
32 Despite this increase, total hydraulic fracturing water use is expected to remain small relative to other users. Currently,
3 3 irrigated agriculture is the largest water user in the UCRB.
34 Greater water demand could occur in the future if the water-intensive oil shale extraction industry becomes economically
35 viable in the region. Projections for oil shale water demand indicate that the industry could increase water use for energy
36 extraction in Garfield and Rio Blanco counties.
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1 East of the Rocky Mountains in the Denver Basin, sub-county effects may be possible given the
2 combination of high hydraulic fracturing activity and low water availability, but lack of available
3 data and literature at this scale limits our ability to assess the potential for impacts in this location.
4 Ceres [2014] concludes that all fractured wells in the Denver Basin are in high or extremely high
5 water-stressed areas. Furthermore, the development of the Niobrara Shale in southeast Wyoming
6 occurs in areas already impacted by high agricultural water use from the Ogallala aquifer, including
7 the state's only three ground water control areas, which were established as management districts
8 in the southeast portion of the state in response to declining ground water levels [AMEC. 2014:
9 Wyoming State Engineer's Office, 2014: Tyrrell, 2012: Bartos and Hallberg, 2011]. Ground water
10 withdrawals for hydraulic fracturing may have the potential to contribute to water quality
11 degradation particularly in these areas.
12 Overall, the potential for impacts appears low at the county scale in Colorado and Wyoming, but
13 sub-county effects may be possible particularly east of the Rocky Mountains in the Denver Basin.
14 Lack of available data and literature at the local scale limits our ability to assess the potential for
15 impacts in this location.
4.5.3. Pennsylvania, West Virginia, and Ohio
16 Pennsylvania had the third most disclosures in the EPA FracFocus project database (6.5% of
17 disclosures] (see Appendix Table B-5 and Figure 4-3]. We combine West Virginia and Ohio with
18 Pennsylvania because they share similar geology overlying the Appalachian Basin (including the
19 Marcellus, Devonian, and Utica stacked plays] (see Figure 4-8]; however, much less activity is
20 reported in these two states (see Appendix Table B-5].
Marcellus, Devonian,
and Utica Plays
Figure 4-8. Major U.S. EIA shale plays and basins for Pennsylvania, West Virginia, and Ohio
(EIA, 2015).
Source: (EIA, 2015b).
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1 Types of water used: Surface water is the primary water source for hydraulic fracturing in
2 Pennsylvania, West Virginia, and Ohio [Mitchell et al.. 2013a: SRBC. 2013: West Virginia PEP. 2013:
3 Ohio EPA. 2012b]. Available data for Pennsylvania are specific to the Susquehanna River Basin
4 (SRB), where hydraulic fracturing water is sourced mostly from surface water [SRBC, 2013] (see
5 Table 4-3). The industry also uses mostly surface water in West Virginia [West Virginia PEP, 2014,
6 2013] (see Table 4-3]. Although specific data are not available, state reports indicate that most
7 water for hydraulic fracturing in Ohio's Marcellus or Utica Shale formations is sourced from nearby
8 surface water bodies fOhio EPA. 2012b: STRONGER. 2011bl
9 Given that surface water is the primary water source, the water used for hydraulic fracturing is
10 most often fresh water in all three states. In both Pennsylvania's SRB and throughout West Virginia,
11 most water for hydraulic fracturing is self-supplied via direct withdrawals from surface water and
12 ground water fU.S. EPA. 2015a: West Virginia PEP. 20131 Operators also purchase water from
13 public water systems, which may include a variety of commercial water brokers (West Virginia
14 PEP. 2014: SRBC. 2013: West Virginia PEP. 2013]. Municipal supplies may be used as well,
15 particularly in urban areas of Ohio (STRONGER. 2011b1.
16 Reused hydraulic fracturing wastewater accounted for an estimated 18% and 15 % of total water
17 used for fracturing in 2012 in Pennsylvania's SRB and West Virginia, respectively (West Virginia
18 PEP. 2014: Hansenetal.. 2013: SRBC. 2013] (see Table 4-1]. Available data indicate increased reuse
19 of wastewater over time in this region likely due to the lack of nearby disposal options; from 2010-
20 2012 reused wastewater as a percentage of injected water volume ranged from 10% to 18% and
21 6% to 15% in Pennsylvania's SRB and West Virginia, respectively (West Virginia PEP, 2014: Hansen
22 etal.. 2013]. In Ohio's Marcellus and Utica Shales, reuse of wastewater is reportedly uncommon
23 (STRONGER, 2011b], potentially due to the prevalence of disposal wells in Ohio (see Chapter 8].
24 Aside from reused hydraulic fracturing wastewater, other types of wastewaters reused for
2 5 hydraulic fracturing may include wastewater treatment plant effluent, treated acid mine drainage,
2 6 and rainwater collected at various well pads (West Virginia PEP. 2014: SRBC. 2013: West Virginia
27 PEP. 2013: Ziemkiewicz etal.. 2013: Ohio EPA. 2012bl No data are available on the frequency of
28 use of these other wastewaters.
29 Water Use per Well: Operators in these three states reported the third, fourth, and fifth highest
30 median water use nationally in the EPA FracFocus project database, with 5.0, 4.2, and
31 3.9 million gal (18.9,15.9, and 14.8 million L] per well in West Virginia, Pennsylvania, and Ohio,
32 respectively (U.S. EPA. 2015b] (see Appendix Table B-5]. Hansenetal. (2013] report similar water
33 use estimates for Pennsylvania and West Virginia (see Appendix Table B-5]. This correspondence is
34 not surprising, as these estimates are also based on FracFocus data (via Skytruth]. For 2011, the
35 year overlapping with the time frame of the EPA FracFocus report (U.S. EPA, 2015a], Mitchell et al.
36 (2013a] report an average of 2.3 million gal (8.7 million L] for vertical wells (62 wells] and
37 4.6 million gal (17.4 million L] for horizontal wells (612 wells] in the Pennsylvania portion of the
38 Ohio River Basin, based on records from PA PEP. The weighted average water use per well was
39 4.4 million gal (16.7 million L], similar to results based on the EPA FracFocus project database
40 listed above.
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1 Cumulative water use/consumption: In this tri-state region, highest cumulative water use for
2 hydraulic fracturing is in northeastern Pennsylvania counties. On average, operators in Bradford
3 County reported over 1 billion gal (3.8 billion L) used annually in 2011 and 2012 for fracturing;
4 operators in three other counties (Susquehanna, Lycoming, and Tioga Counties) cumulatively
5 reported 500 million gal (1.9 billion L) or more used annually (see Table 4-2). On average,
6 hydraulic fracturing water use is 3.2% compared to 2010 total county water use for counties with
7 disclosures in the EPA FracFocus project database in these three states (see Table 4-2 and
8 Appendix Table B-2). Susquehanna County in Pennsylvania has the highest percentages relative to
9 2010 total water use (47%) and consumption (123%).
10 Potential for impacts: Water availability is higher in Pennsylvania, West Virginia, and Ohio than in
11 many western states, reducing the likelihood of impacts to drinking water quantity and quality. At
12 the county scale, water supplies appear adequate to accommodate this use (Tidwell etal.. 2013)
13 (see Text Box 4-2 and Figure 4-5a,b).
14 However, impacts could still occur at specific withdrawal points. In a second, multi-scale case study,
15 EPA researchers concluded that individual streams in this region can be vulnerable to typical
16 hydraulic fracturing water withdrawals depending on stream size, as defined by contributing basin
17 area (U.S. EPA. 2015c) (see Text Box 4-5). They observed infrequent (in less than 1% of
18 withdrawals) high ratios of hydraulic fracturing water consumption to stream flow (high
19 consumption-to-stream flow events). Passby flows can reduce the frequency of high consumption-
20 to-stream flow events, particularly in the smallest streams (U.S. EPA. 2015C).1
1A passby flow is a prescribed, low stream flow threshold below which withdrawals are not allowed. The SRBC uses
passby flows to protect streams in the Susquehanna River Basin, an area including much of eastern Pennsylvania [U.S.
EPA. 2015cl.
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Text Box 4-5. Case Study: Impact of Water Acquisition for Hydraulic Fracturing on Local Water
Availability in the Susquehanna River Basin.
1 The EPA (2015c) conducted a second case study analogous to that in the UCRB (see Text Box 4-4), to explore
2 the impact of hydraulic fracturing water demand on water availability at the river basin, county, and local
3 scales in the SRB in northeastern Pennsylvania. The study area overlies the Marcellus Shale gas reservoir.
4 Water withdrawal impacts were quantified using a water use intensity index (see Text Box 4-4). Researchers
5 obtained detailed site-specific data on hydraulic fracturing water usage from state and regional authorities,
6 and estimated available water supplies using observations at USGS gage stations and empirical and
7 hydrologic modeling.
8 Most water for fracturing in the SRB is self-supplied from rivers and streams with withdrawal points
9 distributed throughout a wide geographic area. Public water systems provide a relatively small proportion of
10 the water needed. Reuse of wastewater makes up approximately 13% to 18% of injected fluid volume on
11 average, as reported by the EPA (2015c) for 2008 to 2011 and Hansen et al. (2013) for 2012, respectively
12 (see Table 4-1). The Susquehanna River Basin Commission (SRBC) regulates water acquisition for hydraulic
13 fracturing and issues permits that set limits on the volume, rate, and timing of withdrawals at individual
14 withdrawal points; passby flow thresholds halt water withdrawals during low flows.
15 The EPA (2015c) demonstrated that streams can be vulnerable from typical hydraulic fracturing water
16 withdrawals depending on their size, as denned by contributing basin area. Small streams have the potential
17 for impacts (i.e., high water use intensity) for all or most of the year. The EPA (2015c) showed an increased
18 likelihood of impacts in small watersheds (less than 10 mi2). Furthermore, they showed that in the absence of
19 passby flows, even larger watersheds (up to 600 mi2) could be vulnerable during maximum withdrawal
20 volumes and infrequent droughts. However, high water use intensity calculated from observed hydraulic
21 fracturing withdrawals occurred at only a few withdrawal locations in small streams; local high water use
2 2 intensity was not found at the majority of withdrawal points.
2 3 Without management of the rate and timing of withdrawals, surface water withdrawals for
24 hydraulic fracturing have the potential to affect both water quantity and quality [Mitchell etal..
25 2013a). Potential effects are generally applicable, but are especially relevant in this region because
26 surface water is the primary water source for hydraulic fracturing in Pennsylvania, West Virginia,
27 and Ohio. Of greatest concern are small, unregulated streams, particularly under drought
28 conditions or during seasonal low flows [U.S. EPA, 2015c: Vengosh etal., 2014: Mitchell etal.,
29 2013a: Vidic etal.. 2013: Rahm and Riha. 2012: Rolls etal.. 2012: Kargbo etal.. 2010: McKay and
30 King. 2006). Surface water quality impacts may be of concern if a pollution discharge point (e.g.,
31 sewage treatment plant, agricultural runoff, or chemical spill) is immediately downstream of a
32 hydraulic fracturing withdrawal [U.S. EPA. 2015c: NYSDEC. 2011).* Water quality impacts
1 Aside from direct surface water withdrawals, unmanaged withdrawals from public water systems can cause cross-
contamination if there is a loss of pressure, allowing the backflow of pollutants from tank trucks into the distribution
system. The state of Ohio has issued a fact sheet relevant to this potential concern, intended specifically for public water
systems providing water to oil and gas companies [Ohio EPA. 2012a). To prevent potential cross-contamination, Ohio
requires a backflow prevention device at cross-connections. For example, bulk loading stations that provide public supply
water directly to tank trucks are required to have an air-gap device at the cross-connection to prevent the backflow of
contaminants into the public water system [Ohio EPA. 2012a).
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1 associated with reduced water levels may also include possible interference with the efficiency of
2 drinking water treatment plant operations, as increased contaminant concentrations in drinking
3 water sources may necessitate additional treatment and ultimately impact drinking water quality
4 [Water Research Foundation. 2014: Benottletal.. 20101.1
5 Overall, there appears to be adequate surface water for hydraulic fracturing, but there is the
6 potential for impacts to both drinking water quantity and quality, particularly in small streams, if
7 withdrawals are not managed [U.S. EPA. 2015c).
4.5.4. North Dakota and Montana
8 North Dakota was fourth in the number of disclosures in the EPA FracFocus project database (5.9%
9 of disclosures) (see Appendix Table B-5 and Figure 4-3). We combine Montana with North Dakota
10 because both overlie the Williston Basin (which contains the Bakken play, shown in Figure 4-9),
11 although many fewer wells are reported for Montana (see Appendix Table B-5). The Williston Basin
12 is the only basin with significant activity reported for either state, though other basins are also
13 present in Montana (e.g., the Powder River Basin).
Figure 4-9. Major U.S. EIA shale plays and basins for North Dakota and Montana (EIA, 2015b).
Source: (EIA, 2015b).
1 For instance, an increased proportion of organic matter entering a treatment plant may increase the formation of
trihalomethanes, byproducts of the disinfection process formed as chlorine react with organic matter in the water being
treated [Water Research Foundation. 2014).
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1 Types of water used: Hydraulic fracturing of the Bakken play underlying much of western North
2 Dakota and northeastern Montana depends on both ground and surface water resources. Surface
3 water from the Missouri River system provides the largest source of fresh water in the center of
4 Bakken oil development [North Dakota State Water Commission. 2014: EERC. 2011. 2010: North
5 Dakota State Water Commission, 2010]. Apart from the Missouri River system, regional surface
6 waters (i.e., small streams) do not provide a consistent supply of water for the oil industry due to
7 seasonal stream flow variations. Sufficient stream flows generally occur only in the spring after
8 snowmelt [EERC. 2011). Ground water from glacial and bedrock aquifer systems has traditionally
9 supplied much of the water needed for Bakken development, but concerns over limited ground
10 water supplies have led to limits on the number of new ground water withdrawal permits issued
11 [Ceres. 2014: Plummer etal.. 2013: EERC. 2011. 2010: North Dakota State Water Commission.
12 20101
13 The water used for Bakken development is described as mostly fresh. The EPA FracFocus report
14 shows that "fresh" was the only source of water listed in almost all disclosures reporting a source of
15 water in North Dakota [U.S. EPA. 2015a].1 Reuse of Bakken wastewater is limited due to its quality
16 of high TDS, which presents challenges for treatment and reuse. However, the industry is
17 researching treatment technologies for reuse of this wastewater [Ceres. 2014: EERC. 2013. 2011).
18 Water for hydraulic fracturing is commonly purchased from municipalities or other public water
19 systems in the region. The water is often delivered to trucks at water depots or transported directly
20 to well pads via pipelines fEERC. 2011).
21 Water Use per Well: Water use per well is intermediate compared with other areas, with a median
22 of 2.0 and 1.6 million gal (7.6 and 6.1 million L) per well in the Williston Basin in North Dakota and
23 Montana, respectively according to the EPA's FracFocus project database (see Appendix Table B-5).
24 The North Dakota State Water Commission reports similar volumes (2.2 million gal (8.3 million L)
25 per well on average for North Dakota) in a summary fact sheet (North Dakota State Water
26 Commission. 2014).2
27 A presentation by the North Dakota Department of Mineral Resources (NDDMR) suggests that
28 Bakken wells require an average of 600 gal (2,300 L) per day of "maintenance water" in addition to
29 the initial water for hydraulic fracturing (North Dakota Department of Mineral Resources. 2013).3
30 This extra water is reportedly needed because of the relatively high salt content of Bakken brine,
31 potentially leading to salt buildup, pumping problems, and restriction of oil flow. According to the
32 NDDMR, maintenance water can contribute to large additional volumes over a typical well life span
33 (6.6-8.8 million gal (25-33 million L) over 30-40 years). It is unclear whether this phenomenon is
34 restricted to the Bakken play.
i However, 25% of North Dakota disclosures included information related to water sources [U.S. EPA. 2015a).
2_The fact sheet is a stand-alone piece, and it is not accompanied by an underlying report.
The NDDMR's presentation that mentions the issue of maintenance water was later picked up and reported on by
National Geographic fhttp://news.nationalgeographic.com/news/energy/2013/ll/131111-north-dakota-wells-
maintenance-water/) and by Ceres (2014). Peer-reviewed studies on the Bakken also report on maintenance water [e.g..
Scanlon etal.. 2014). but they refer to the same original sources.
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1 Cumulative water use/consumption: Cumulative water use for fracturing in this region is greatest in
2 the northwestern corner of North Dakota. In counties with 2011 and 2012 disclosures to FracFocus,
3 fracturing water use averaged approximately 123 million gal (466 million L) per county annually in
4 the two-state area, with use in McKenzie and Williams Counties in North Dakota exceeding
5 500 million gal (1.9 billion L) per year (see Appendix Table B-2). There are four counties where
6 2011 and 2012 average hydraulic fracturing water use was 10% or more of 2010 total water use.
7 Mountrail and Dunn Counties showed the highest percentages. Outside of North Dakota's northwest
8 corner, the rest of the state and Montana showed little cumulative water use from hydraulic
9 fracturing (see Table 4-2 and Appendix Table B-2).
10 Potential for impacts: In this region, there are concerns about over-pumping ground water
11 resources, but the potential for impacts appears to be low provided the Missouri River is
12 determined to be a sustainable and usable source. This finding of a low potential for impacts is also
13 supported by the comparison of hydraulic fracturing water use to water availability at the county
14 scale (see Text Box 4-2 and Figure 4-5a,b.) This area is primarily rural, interspersed with small
15 towns. Residents use a mixture of surface water and ground water for domestic use depending on
16 the county, with most water supplied by local municipalities (see Appendix Table B-6).
17 The state of North Dakota and the U.S. Army Corps of Engineers concluded that ground water
18 resources in western North Dakota are not sufficient to meet the needs of the oil and gas industry
19 (U.S. Army Corps of Engineers. 2011: North Dakota State Water Commission. 20101 All users
20 combined currently withdraw approximately 6.2 billion gal (23.5 billion L) of water annually in an
21 11-county region in western North Dakota, already stressing ground water supplies (U.S. Army
22 Corps of Engineers. 2011]. By contrast, the total needs of the oil and gas industry are projected to
23 range from approximately 2.2 and 8.8 billion gal (8.3 and 33.3 billion L) annually by the year 2020
24 (U.S. Army Corps of Engineers. 2011).
2 5 Due to concerns for already stressed ground water supplies, the state of North Dakota limits
26 industrial ground water withdrawals, particularly from the Fox Hills-Hell Creek aquifer (Ceres,
27 2014: Plummer et al.. 2013: EERC. 2011. 2010: North Dakota State Water Commission. 20101
28 Currently, the oil industry is the largest industrial user of water from the Fox Hills-Hell Creek
29 aquifer in western North Dakota (North Dakota State Water Commission, 2010]. Many farms,
30 ranches, and some communities in western North Dakota rely on flowing wells from this artesian
31 aquifer, particularly in remote areas that lack electricity for pumping; however, low recharge rates
32 and prolonged withdrawals throughout the last century have resulted in steady declines in the
33 formation's hydraulic pressure (North Dakota State Water Commission, 2010]. Declines in
34 hydraulic pressure do not appear to be associated with impacts to ground water quality; rather, the
35 state is concerned with maintaining flows for users through conservation (North Dakota State
36 Water Commission. 2010].
37 To reduce pressure on ground water, the state is encouraging the industry to seek surface water
38 withdrawals from the Missouri River system, which if used, may be an adequate resource. The
39 North Dakota State Water Commission concluded the Missouri River and its dammed reservoir,
40 Lake Sakakawea, are the only plentiful and dependable water supplies for the oil industry in
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1 western North Dakota [North Dakota State Water Commission. 20101. In 2011, North Dakota
2 authorized the Western Area Supply Project, by which Missouri River water (via the water
3 treatment plant in Williston, North Dakota) will be supplied to help meet water demands, including
4 for oil and gas development, of the state's northwest counties [WAWSA, 2011]. Industrial surface
5 water withdrawals are presently allowed in Lake Sakakawea on a temporary and controlled basis
6 while the U.S. Army Corps of Engineers conducts a multi-year study to determine whether surplus
7 water is available to meet the demands of regional municipal and industrial users [U.S. Army Corps
8 of Engineers. 2011).
4.5.5. Oklahoma and Kansas
9 Oklahoma had the fifth most disclosures in the EPA FracFocus project database (5.0% of
10 disclosures) (see Appendix Table B-5, and Figure 4-3). Three major basins— the Anadarko, which
11 includes the Woodford play; the Arkoma, which includes the Fayetteville play; and the Ardmore,
12 which includes the Woodford play—contain 67% of the disclosures in Oklahoma (see Figure 4-9
13 and Appendix Table B-5). Few wells were reported for Kansas (Kansas disclosures comprise 0.4%
14 of the EPA FracFocus project database), but because of the shared geology of the Cherokee Platform
15 across the two states, we group Kansas with Oklahoma. Oklahoma and Kansas were two of the
16 three states where a large fraction of wells were not associated with a basin defined by the U.S. EIA
17 (U.S. EPA. 2015b) (see Appendix Table B-5).1
18 Types of water used: Water for hydraulic fracturing in Oklahoma and Kansas comes from both
19 surface and ground water (Kansas Water Office, 2014: Taylor, 2012). Data on temporary water use
20 permits in Oklahoma (which make up the majority of water use permits for Oklahoma oil and gas
21 mining) show that, in 2011, approximately 63% and 37% of water for hydraulic fracturing came
22 from surface and ground water, respectively (Taylor. 2012] (see Table 4-3). General water use in
23 Oklahoma follows an east-west divide, with the eastern half dependent on surface sources and the
24 western half relying heavily on ground water (OWRB, 2014). Water obtained for fracturing is
25 assumed to fit this pattern as well. No data are available on the proportion of hydraulic fracturing
26 water that is sourced from surface versus ground water resources in Kansas.
27 For both Oklahoma and Kansas, no data are available to describe the extent to which reused
28 wastewater is used as a percentage of total injected volume. However, the quality of Oklahoma's
29 Woodford Shale wastewater has been described as low in TDS, and thus reuse could reduce the
30 demand for fresh water fKuthnertetal.. 20121
1 Alaska was the other state in the EPA FracFocus project database where the U.S. EIA shale basins did not adequately
describe well locations, with all 37 wells in Alaska not associated with a U.S. EIA basin. For all other states, U.S. EIA shale
basins captured 86%-100% of the wells in the EPA FracFocus project database [U.S. EPA. 2015b).
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Figure 4-10. Major U.S. EIA shale plays and basins for Oklahoma and Kansas (EIA, 2015).
Source: (EIA, 2015b)
1 Water Use per Well: State-level estimates of median water use per well in Oklahoma include 2.6
2 million gal (9.8 million L) and 3 million gal (11 million L) [U.S. EPA(2015b] and, Murray [2013],
3 respectively]. Water use for hydraulic fracturing increased from 2000 to 2011, driven by volumes
4 required for fracturing horizontal wells across the state [Murray, 2013]. Within the state there are
5 wide ranges in water use for different formations. According to the EPA FracFocus project database,
6 the Ardmore and Arkoma Basins of Oklahoma, had the highest median water use in the country,
7 with medians of 8.0 and 6.7 million gal (30.3 and 25.4 million L) per well, respectively; whereas the
8 Anadarko Basin had lower median water use per well and higher disclosure counts (3.3 million gal
9 (12.5 million L), 935 disclosures) (see Appendix Table B-5). Wells not associated with a U.S. EIA
10 basin had a median of 1.9 million gal (7.2 million L) per well (592 disclosures) (see Appendix Table
11 B-5). It is not clear why lower water volumes were reportedly used in unassociated wells, but
12 Oklahoma has several CBM deposits in the eastern part of the state where very low water use has
13 been reported (Murray. 2013). Median water use per well in Kansas was 1.5 million gal (5.7 million
14 L), focused mostly in a five-county area in the south-central and southwest portions of the state
15 (see Appendix Table B-5).
16 Cumulative water use/consumption: Cumulatively, operators reported using an average of
17 71.9 million gal (272.2 million L) of water annually in Oklahoma counties with disclosures; in
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1 Kansas, this value is only 3.5 million gal (13.2 million L) (see Appendix Table B-2). Average
2 hydraulic fracturing water use in 2011 and 2012 did not exceed 10% of 2010 total water use in any
3 county in Oklahoma or Kansas (see Appendix Table B-2). However, there were six counties in
4 Oklahoma (Alfalfa, Canadian, Coal, Pittsburg, Rogers Mills, and Woods) where fracturing water
5 consumption exceeded 10% of 2010 total county water consumption.
6 Potential for impacts: The potential for effects on drinking water resources appears to be low in
7 Oklahoma and Kansas, since hydraulic fracturing water use and consumption are generally low as a
8 percentage of total water use and consumption. This finding is generally supported by the
9 comparison of cumulative fracturing water use to water availability at the county scale (see Text
10 Box 4-2 and Figure 4-5a,b). If impacts to water quantity or quality do occur, however, they are more
11 likely to happen in western Oklahoma than in the eastern half of the state or Kansas. Of the six
12 Oklahoma counties where fracturing consumption exceeded 10% of 2010 water consumption,
13 three (Alfalfa, Canadian, and Roger Mills) are in the western half of the state where surface water
14 availability is lowest (Figure 4-6a). Surface water is fully allocated in the Panhandle and West
15 Central regions, encompassing much of the state's northwestern quadrant (OWRB. 2014). As a
16 result, residents generally rely on ground water in western Oklahoma (see Appendix Table B-6),
17 and it is likely that fracturing does as well.
18 Projecting out to 2060, Oklahoma's Water Plan concludes that aquifer storage depletions are likely
19 in the Panhandle and West Central regions due to over-pumping, particularly for irrigation (OWRB.
20 2014). Ground water depletions are anticipated to be small relative to storage, but will be the
21 largest in summer months and may lead to higher pumping costs, the need for deeper wells, lower
22 water yields, and detrimental effects on water quality (OWRB, 2014). Drought conditions are likely
23 to exacerbate this problem, and Oklahoma's Water Plan specifically mentions the potential for
24 climate change to affect future water supplies in the state (OWRB. 2014). In the adjacent Texas
25 Panhandle, future irrigation needs may go unmet (TWDB. 2012). and this may be the case in
26 western Oklahoma as well.
2 7 Aquifer depletions in western Oklahoma may be associated with ground water quality degradation,
2 8 particularly under drought conditions. The central portion of the Ogallala aquifer underlying the
29 Oklahoma Panhandle and western Oklahoma contains elevated levels of some constituents (e.g.,
3 0 nitrate) due to over-pumping, although generally it is of better quality than the southern portion of
31 the aquifer (USGS. 2009). Additional ground water withdrawals for hydraulic fracturing in western
32 Oklahoma may add to these water quality issues, particularly in combination with other substantial
33 water uses (e.g., irrigation) (USGS, 2009).
4.5.6. Arkansas and Louisiana
34 Arkansas and Louisiana were ranked seventh and tenth in the number of disclosures in the EPA
35 FracFocus project database, respectively (see Appendix Table B-5). Hydraulic fracturing activity in
36 Louisiana occurs primarily in the TX-LA-MS Salt Basin, which contains the Haynesville play; activity
37 in Arkansas is dominated by the Arkoma Basin, which contains the Fayetteville play (Figure 4-11).
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1 Types of water used: Surface water is reported as the primary source of water for hydraulic
2 fracturing operations in both Arkansas and Louisiana fANRC. 2014; LA Ground Water Resources
3 Commission. 2012; STRONGER. 20121 Quantitative information is lacking for Arkansas on the
4 proportion of water sourced from surface versus ground water. However, data are available for
5 Louisiana, where an estimated 87% of water for hydraulic fracturing in the Haynesville Shale is
6 sourced from surface water [LA Ground Water Resources Commission, 2012] (see Table 4-3). In
7 2008, during the early stages of development, hydraulic fracturing in Louisiana relied heavily on
8 ground water from the Carrizo-Wilcox aquifer, although concerns for the sustainability of ground
9 water resources have more recently prompted the state to encourage surface water withdrawals
10 [LA Ground Water Resources Commission, 2012].
11 The EPAFracFocus report suggests that significant reuse of wastewater may occur in Arkansas to
12 offset total fresh water used for hydraulic fracturing; 70% of all disclosures reporting a water
13 source indicated a blend of "recycled/surface," whereas only 3% of disclosures reporting a water
14 source noted "fresh" as the exclusive water source [U.S. EPA. 2015a].1According to Veil [2011],
15 Arkansas' Fayetteville Shale wastewater is of relatively good quality (i.e., low TDS], potentially
16 facilitating reuse. Data are generally lacking on the extent to which hydraulic fracturing wastewater
17 is reused to offset total fresh water use in Louisiana.
1 93% of Arkansas disclosures included information related to water sources [U.S. EPA. 2015a).
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Figure 4-11. Major U.S. EIA shale plays and basins for Arkansas and Louisiana (EIA. 2015b).
Source: (EIA.2015bl.
1 Water Use per Well: Arkansas and Louisiana have the highest median water use per well in the
2 nation, at 5.3 million and 5.1 million gal (20.1 million and 19.3 million L), respectively based on the
3 EPA FracFocus project database (see Appendix Table B-5).1
4 Cumulative water use/consumption: On average, hydraulic fracturing operations cumulatively use
5 408 million gal (1.54 billion L) of water each year in Arkansas counties reporting activity, or 9.3%
6 of 2010 total county water use (26.9% of total county consumption) (see Appendix Table B-2). In
7 2011 and 2012, five counties dominated fracturing water use in Arkansas: Cleburne, Conway,
8 Faulkner, Van Buren, and White Counties (see Appendix Table B-2). Van Buren, which is sparsely
9 populated and thus has relatively low total water use and consumption, is by far the county highest
According to STRONGER (2012) and STRONGER (2011a). both states require disclosure of information on water use per
well, but this has not been synthesized into state level reports.
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1 in hydraulic fracturing water use and consumption relative to 2010 total water use and
2 consumption (56% and 168%, respectively) (see Table 4-2).
3 In Louisiana, fracturing water use is concentrated in six parishes in the far northwestern corner of
4 the state, associated with the Haynesville play.1 On average in 2011 and 2012, hydraulic fracturing
5 used 117 million gal (443 million L) of water annually per parish, representing approximately 3.6%
6 and 10.8% of 2010 total water use and consumption, respectively (see Appendix Table B-2).
7 Operators in De Soto Parish used the most water (over 1 billion gal (3.8 billion L) annually).
8 Fracturing water use and consumption was highest relative to 2010 total water use and
9 consumption (35.5% and 83.2%, respectively) in Red River Parish (see Table 4-2). These numbers
10 may be low estimates since Louisiana required disclosures to the state or FracFocus and Arkansas
11 required disclosures to the state, but not FracFocus, during the time period analyzed (U.S. EPA,
12 2015al (see Appendix Table B-5).
13 Potential for impacts: Water availability is generally higher in Arkansas and Louisiana than in states
14 farther west, reducing the potential for impacts to drinking water quantity and quality (Figure 4-6a,
15 Text Box 4-2, and Figure 4-5). There are, however, concerns about over-pumping of ground water
16 resources in northwestern Louisiana. Prior to 2008, most operators in the Louisiana portion of the
17 Haynesville Shale used ground water, withdrawing from the Carrizo-Wilcox, Upland Terrace, and
18 Red River Alluvial aquifer systems (LA Ground Water Resources Commission. 2012). To mitigate
19 stress on ground water, the state issued a water use advisory to the oil and gas industry that
20 recommended Haynesville Shale operators seek alternative water sources to the Carrizo-Wilcox
21 aquifer, which is predominantly used for public supply (LDEQ. 2008). Operators then transitioned
22 to mostly surface water, with a smaller ground water component (approximately 12% of all
23 fracturing water used) (LA Ground Water Resources Commission, 2012). Of this ground water
24 component, the majority (approximately 74%) still came from the Carrizo-Wilcox aquifer (LA
25 Ground Water Resources Commission, 2012).
26 Although the potential for hydraulic fracturing withdrawals to affect water supplies and water
27 quality in the aquifer appears greatly reduced, it is not entirely eliminated. Despite Louisiana's
28 water use advisory, a combination of drought conditions and higher than normal withdrawals (for
29 all uses, not solely hydraulic fracturing) from the Carrizo-Wilcox and Upland Terrace aquifers
30 caused several water wells to go dry in July 2011. In August 2011, a ground water emergency was
31 declared for southern Caddo Parrish (LA Ground Water Resources Commission. 2012). There are
32 hydraulic fracturing wells in southern Caddo Parrish (U.S. EPA, 2015b), and so it is possible that
33 fracturing withdrawals contributed to the problem of declines in ground water in this instance.
4.5.7. Utah, New Mexico, and California
34 Together, Utah, New Mexico, and California accounted for approximately 9% of disclosures in the
35 EPA FracFocus project database (3.8%, 3.1% and 1.9% of disclosures, respectively) (see Appendix
36 Table B-5 and Figure 4-3). Almost all reported hydraulic fracturing in Utah and California were in
1 Louisiana is divided into parishes, which are similar to counties in other states.
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1 the Uinta-Piceance Basin (99%) and San Joaquin Basin (95%), respectively. Activity in New Mexico
2 mostly occurs in the Permian and San Juan Basins, which together comprised 96% of reported
3 disclosures in that state (see Figure 4-12).
Figure 4-12. Major U.S. EIA shale plays and basins for Utah, New Mexico, and California
(EIA, 2015).
Source: (EIA, 2015b).
4 Types of water used: Of these three states, California has the most information available on the
5 sources of water used for hydraulic fracturing. Most current and proposed fracturing activity is
6 focused in Kern County in the San Joaquin Basin, where well stimulation notices indicate that
7 operators depend mainly on surface water purchased from nearby irrigation districts (CCST. 2014).
8 California irrigation districts receive water allocated by the State Water Project, and deliveries may
9 be restricted or eliminated during drought years (CCST, 2014).l In addition to publicly-supplied
10 surface water, operators also may self-supply a smaller proportion of water from on-site ground
11 water wells (CCST, 2014). Operators use primarily fresh water for hydraulic fracturing (96% of well
i The California State Water Project is water storage and distribution system maintained by the California Department of
Water Resources, which provides water for urban and agricultural water suppliers in Northern California, the San
Francisco Bay Area, the San Joaquin Valley, the Central Coast, and Southern California [California Department of Water
Resources. 2015).
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1 stimulation notices reported); reused wastewater (sometimes blended with fresh water) is used in
2 small amounts relative to total water use (4% of well stimulation notices reported) (CCST. 2014) (see
3 Table 4-1).
4 The source, quality, and provisioning of water used for hydraulic fracturing in Utah and New
5 Mexico are not well characterized. The 2010 New Mexico water use report summarizes
6 withdrawals for a variety of water use categories. In 2010, mining water use (which includes water
7 used for oil and gas production) consisted of 26% and 74% of surface and ground water
8 withdrawals, respectively (NM OSE. 2013). Assuming that hydraulic fracturing follows the same
9 pattern as other mining water uses (e.g., for metals, coal, geothermal), water for hydraulic
10 fracturing in New Mexico would be supplied primarily by ground water withdrawals. To our
11 knowledge, no data are available to characterize the source of water for hydraulic fracturing
12 operations in Utah. In addition, no data are available to describe the extent to which reused
13 wastewater is used as a proportion of total water injected for either Utah or New Mexico.
14 Water use per well: Median water use per well in Utah, New Mexico, and California is lower than in
15 other states in the EPA FracFocus project database: Utah ranks 13th (approximately 302,000 gal
16 (1.14 million L)), New Mexico ranks 14th (approximately 175,000 gal (662,000 L)), and California
17 ranks 15th (approximately 77,000 gal (291,000 L)) out of the 15 states (see Appendix Table B-5). A
18 likely explanation for the low water use per well in Utah and New Mexico is the prevalence of CBM
19 in the Uinta (Utah) and San Juan (New Mexico) Basins. Low water use per well in California is
20 attributed to the prevalence of vertical wells and the use of crosslinked gels. Vertical wells
21 dominate because the complex geology precludes long horizontal drilling and fracturing (CCST.
22 20141
23 For California, the California Council on Science and Technology (CCST) reports average water use
24 per well of 130,000 gal (490,000 L), which agrees with the state average of approximately 131,700
25 gal (498,500 L) according to the EPA FracFocus project database (CCST, 2014) (see Appendix Table
26 B-5); this is expected because estimates from CCST are also based on data submitted to FracFocus.
27 Cumulative water use/consumption: Operators in Utah, New Mexico, and California report using low
28 cumulative amounts of water compared to most other states (see Appendix Table B-l). Only four
29 counties (Duchesne and Uintah Counties in Utah, and Eddy and Lea Counties in New Mexico)
30 required more than 50 million gal (189 million L) annually (see Appendix Table B-2). Fracturing
31 water use and consumption did not exceed 1% of 2010 total water use and consumption in any
32 county.
33 Potential for impacts: The potential for water quantity and quality impacts from hydraulic
34 fracturing water withdrawals in Utah, New Mexico, and California appears to be low at present (see
35 Text Box 4-2 and Figure 4-5a,b). Hydraulic fracturing does not use or consume much water
36 compared to other users or consumers in these states. As in other states, this does not preclude
37 sub-county effects, and this finding of low potential for impacts could change if fracturing activities
38 increase beyond present levels. This is particularly the case because these states generally have low
39 surface water availability (see Figure 4-6a) and high ground water dependence (see Figure 4-6b),
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1 and have experienced frequent periods of drought over the last decade [National Drought
2 Mitigation Center. 2015].
4.6. Chapter Synthesis
3 In this chapter we examine the potential for water acquisition for hydraulic fracturing to affect
4 drinking water quantity and quality. The potential for impacts largely depends on water use,
5 consumption, and availability. Water management—in terms of the type of water used, the timing
6 or location of water withdrawals, or other factors—also can play a role. Because all of these factors
7 vary considerably from place-to-place, any impacts that occur will be location-specific and occur at
8 the spatial scale of the specific drinking water resource (i.e., the particular stream, watershed, or
9 local ground water aquifer). Therefore, it is important to consider the potential for hydraulic
10 fracturing impacts by location.
11 We examine the potential for impacts by considering (1) the types of water used for hydraulic
12 fracturing; (2) the amounts of water used per well; (3) cumulative estimates of water used and
13 consumed for hydraulic fracturing; and (4) a state-by-state assessment of the potential for impacts
14 based on water use, consumption, and availability. We often could not assess the potential for
15 impacts at a finer resolution than the county scale due to lack of available local-scale data for most
16 areas. Thus, our assessment suggests areas that are more likely than others to experience impacts,
17 but does not necessarily indicate that these impacts will occur. Three case studies (southern Texas,
18 western Colorado, and eastern Pennsylvania), provide an in-depth examination at finer scales, and
19 we rely on those where possible (see Text Boxes 4-3, 4-4, and 4-5).
4.6.1. Major Findings
20 Water for hydraulic fracturing typically comes from surface water, ground water, or reused
21 wastewater. Because trucking can be a major expense, operators often use water sources as close to
22 well pads as possible. Operators usually self-supply surface or ground water directly, but also may
23 obtain water secondarily through public water systems or other suppliers. Hydraulic fracturing
24 operations in the eastern United States generally rely on surface water, whereas operations in more
25 semi-arid to arid western states use mixed surface and ground water supplies. In areas that lack
26 available surface water (e.g., western Texas), ground water supplies most of the water needed for
27 fracturing unless alternative sources, such as reused wastewater, are available and utilized.
28 The vast majority of water used for hydraulic fracturing nationally comes from fresh water sources,
29 although some operators also use lower-quality water (e.g., hydraulic fracturing wastewater,
30 brackish ground water, or small proportions of acid mine drainage and wastewater treatment plant
31 effluent). The use of non-fresh sources can reduce competition for current drinking water
32 resources. Nationally, the proportion of reused wastewater is generally low as a percentage of
33 injected volume; based on available data, the median reuse of wastewater as a percentage of
34 injected volume is 5% nationally, but this percentage varies by location (see Table 4-1).1 Available
1 Note that reused water as a percentage of total water injected differs from the percentage of wastewater that is reused
(see Section 4.2 and Chapter 8).
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1 data on reuse trends indicate increasing reuse of wastewater over time in both Pennsylvania and
2 West Virginia, likely due to the lack of nearby disposal options. Reuse as a percentage of water
3 injected appears to be low in other areas, likely in part because of the relatively high availability of
4 disposal wells (see Chapter 8).
5 The median amount of water used per hydraulically fractured well, based on national disclosures to
6 FracFocus, is approximately 1.5 million gal (5.7 million L) of water (U.S. EPA, 2015a, b). This
7 estimate represents a variety of fractured well types, including types that use much less water per
8 well than horizontal shale gas wells. Thus, published estimates for horizontal shale gas wells are
9 typically higher (e.g., approximately 4 million gal (15 million L) per well (Vengosh etal., 2014]].
10 There is also wide variation within and among states and basins in the median water volumes
11 reported per disclosure, from more than 5 million gal (19 million L] in Arkansas and Louisiana to
12 less than 1 million gal (3.8 million L] in Colorado, Wyoming, Utah, New Mexico, and California (U.S.
13 EPA, 2015b]. This variation results from several factors, including well length, formation geology,
14 and fracturing fluid formulation (see Section 4.3.3].
15 Cumulatively, hydraulic fracturing uses billions of gallons of water every year at the national and
16 state scales, and even in some counties. When expressed as a percentage compared to total water
17 use or consumption at these scales, however, hydraulic fracturing water use and consumption is
18 most often a small percentage, generally less than 1%. This percentage may be higher in specific
19 areas. Annual hydraulic fracturing water use was 10% or more compared to 2010 total water use in
20 6.5% of counties with FracFocus disclosures in 2011 and 2012, 30% or more in 2.2% of counties,
21 and 50% or more in 1.0% of counties (U.S. EPA. 2015a]. Consumption estimates followthe same
22 general pattern, but with slightly higher percentages in each category. In these counties, hydraulic
23 fracturing represents a relatively large user and consumer of water.
24 High hydraulic fracturing water use or consumption alone does not necessarily result in impacts to
25 drinking water resources. Rather, the potential for impacts depends on both water use or
26 consumption and water availability at a given withdrawal point Our state-by-state assessment
27 examines the intersection between water use or consumption and availability at the county scale.
28 This approach suggests where the potential for impacts exists, but does not indicate where impacts
29 will occur at the local scale. Where possible, we use local-scale case studies in Texas, Pennsylvania,
30 and Colorado to provide details at finer spatial scales.
31 In our survey of the published literature, we did not find a case where hydraulic fracturing water
32 use by itself caused a drinking water well or stream to run dry. This could indicate an absence of
33 hydraulic fracturing effects on water availability; alternatively, it could reflect that these events are
34 not typically documented in the types of literature we reviewed. Water availability is rarely
35 impacted by just one use or factor alone. For example, drinking water wells in an area overlapping
36 with the Haynesville Shale in northwest Louisiana ran out of water in 2011, due to higher than
37 normal withdrawals and drought (LA Ground Water Resources Commission. 2012]. Hydraulic
38 fracturing water use in the area may have contributed to these conditions, along with other water
39 uses and the lack of precipitation. Other impacts to drinking water quantity or quality (e.g.,
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1 declining aquifer levels, decreased stream flow, increased pollutant concentrations) also may occur
2 before wells and streams actually go dry.
3 The potential for impacts due to hydraulic fracturing water withdrawals is highest in areas with
4 relatively high fracturing water use and low water availability. Southern and western Texas are two
5 locations where hydraulic fracturing water use combined with low water availability, drought, and
6 reliance on declining ground water sources has the potential to affect the quantity and quality of
7 drinking water resources. Fracturing withdrawals combined with other intensive uses, particularly
8 irrigation, could contribute to ground water quality degradation. Any impacts are likely to be
9 realized locally within these areas. In a detailed case study of southern Texas, Scanlonetal. [2014]
10 observed generally adequate water supplies for hydraulic fracturing, except in specific locations.
11 They found excessive drawdown of local ground water in a small proportion (~6% of the area) of
12 the Eagle Ford play. They suggested water management, particularly a shift towards brackish water
13 use, could minimize potential future impacts to fresh water resources (see Text Box 4-3). County-
14 level data confirm that high brackish water availability in Texas may help offset hydraulic
15 fracturing water demand (see Text Box 4-2).
16 Comparatively, the potential for hydraulic fracturing water acquisition impacts to drinking water
17 quantity and quality appears to be lower—but not entirely eliminated—in other areas of the United
18 States. Detailed case studies in western Colorado and northeastern Pennsylvania did not show
19 impacts, despite indicating that streams could be vulnerable to water withdrawals from hydraulic
20 fracturing (U.S. EPA. 2015c). High wastewater reuse rates in western Colorado eliminated the need
21 for more fresh water withdrawals. In northeast Pennsylvania, water withdrawals for hydraulic
22 fracturing could result in high water consumption-to-stream flow events, but water management
23 (e.g., passby flows) limited the potential for impacts, especially on small streams (U.S. EPA, 2015c).
24 In western North Dakota, ground water is limited, but the industry may have sufficient supplies of
25 surface water from the Missouri River system. These location-specific examples emphasize the
26 need to focus on regional and local dynamics when considering the potential impacts of hydraulic
27 fracturing water acquisition on drinking water resources.
4.6.2. Factors Affecting Frequency or Severity of Impacts
28 The potential for hydraulic fracturing water use to affect drinking water resource quantity or
29 quality depends primarily on the amount of water used or consumed versus water availability at a
30 given withdrawal point Potential impacts to drinking water resources reflect all uses, including
31 hydraulic fracturing demands, compared to available water. Areas with high water use, low water
32 availability, slowly replenishing sources, and/or episodic water shortages (e.g., seasonal or longer-
33 term droughts) are more vulnerable to potential impacts. Areas with high water availability relative
34 to existing uses, high rainfall distributed throughout the year, or high storage capacity, are less
3 5 likely to be affected.
3 6 Water management can alter this dynamic between water use and availability. The type of water
37 used (e.g., fresh, brackish, reused hydraulic fracturing wastewater, other wastewaters) is a major
38 factor that can either increase or decrease the potential for impacts. Replacing a fresh water source
39 with another type of water can reduce the demand for fresh water and decrease potential
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1 competition for drinking water. Brackish ground water use may reduce the demand for fresh water
2 and decrease competition for drinking water currently, but this may change if desalinization for
3 drinking water becomes more prevalent in the future (see Chapter 3).
4 The timing and location of water withdrawals can also affect the potential for impacts, particularly
5 for surface water withdrawals. Withdrawing water from small streams is more likely to result in a
6 high-consumption-to-stream flow event than removing water from larger streams [U.S. EPA,
7 2015c). Withdrawals during periods of low stream flow are also more likely to result in impacts
8 than withdrawals during high flow periods. Hydraulic fracturing operations may have the ability to
9 withdraw water during periods of high stream flow, and store it for future use during drier periods.
4.6.3. Uncertainties
10 There are several uncertainties inherent in our assessment of hydraulic fracturing water use and
11 potential effects on drinking water quantity and quality. The largest uncertainties stem from the
12 lack of literature and data on this subject at local scales, and the question of whether any impacts
13 would be documented in the types of literature we reviewed.
14 We used a state-by-state approach to identify areas where potential impacts are likely, based on
15 relatively high fracturing water use and low water availability. Typically, only data at the county-
16 scale were available. Because impacts occur at smaller spatial scales (i.e., at water withdrawal
17 sites), our assessment suggests the potential for impacts, but does not indicate whether impacts
18 will occur. In only a few places could we use local case studies to determine if potential impacts
19 were realized; these case studies show that local factors can greatly affect whether drinking water
20 resources are impacted.
21 In our survey of the published literature, we did not find a case where hydraulic fracturing water
22 use alone caused a drinking water well or stream to run dry. This could indicate an absence of
23 hydraulic fracturing effects on water availability, or it could reflect that these events are not
24 typically documented in the types of literature we reviewed. Water availability is rarely impacted
25 by just one use or factor alone. These issues may have limited our findings.
26 Other uncertainties arise from data limitations regarding the volume and types of water used or
27 consumed for hydraulic fracturing, future water use projections, and water availability estimates.
28 There are no nationally consistent data sources, and therefore water use estimates must be based
29 on multiple, individual pieces of information. For example, in their National Water Census, the USGS
30 includes hydraulic fracturing in the broader category of "mining" water use, but hydraulic
31 fracturing water use is not reported separately (Maupinetal., 2014]. There are locations where
32 annual average hydraulic fracturing water use in 2011 and 2012 exceeded total mining water use in
33 2010, and one county where it exceeded all water use (U.S. EPA, 2015b: Maupinetal., 2014]. This
34 could be due to a rapid increase in hydraulic fracturing water use, differences in methodology
35 between the two databases (i.e., the USGS 2010 National Water Census and the EPA FracFocus
36 project database), or both.
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1 The EPA FracFocus project database represents the most extensive database currently available to
2 estimate hydraulic fracturing water use. However, estimates based on the project database form an
3 incomplete picture of hydraulic fracturing water use because most states with data in the project
4 database did not require disclosure to FracFocus during the time period analyzed [U.S. EPA, 2015a]
5 (see Text Box 4-1). We conclude that this likely does not change the overall hydraulic fracturing
6 water use patterns observed across the United States, but could affect our assessment of the
7 potential impacts in specific locations.
8 Hydraulic fracturing water use data are often provided in terms of water use per well. While this is
9 valuable information, the potential impacts of water acquisition for hydraulic fracturing could be
10 better assessed if data were also available at the withdrawal point If the total volume, date, and
11 location of each water withdrawal were documented, the quality of the water used and potential
12 effects on availability could be better estimated. For example, surface withdrawal points could be
13 aggregated by watershed to estimate effects on downstream flow. Alternatively, if the location and
14 depth of ground water pumping were documented, these could be aggregated to assess effects on a
15 given aquifer. Some of this information is available in disparate forms, but the lack of nationally
16 consistent data on water withdrawal locations, timing, and amounts—data that are publicly
17 available, easy to access, and easy to analyze—limits our assessment of hydraulic fracturing water
18 use.
19 Future hydraulic fracturing water use is also a source of uncertainty. Because water withdrawals
20 and potential impacts are concentrated in certain localized areas, water use projections need to
21 match this scale. Projections are available for Texas at the county scale, but more information at the
22 county or sub-county scale is needed in other states with high hydraulic fracturing activity and
23 water availability concerns (e.g., northwest North Dakota, eastern Colorado). Due to a lack of data,
24 we generally could not assess future cumulative water use and the potential for impacts in most
25 areas of the country, nor could we examine these in combination with other relevant factors (e.g.,
26 climate change, population growth).
4.6.4. Conclusions
2 7 Water acquisition for hydraulic fracturing has the potential to impact drinking water resources by
28 affecting drinking water quantity and quality (see Text Box 4-6). In our survey of the published
29 literature, we did not find a case where hydraulic fracturing water use by itself caused a drinking
30 water well or stream to run dry. However, the potential for impacts to drinking water quantity and
31 quality exists and is highest in areas with relatively high fracturing water use and low water
32 availability. Southern and western Texas are two locations where the potential appears highest due
33 to the combined effects of high hydraulic fracturing activity, low water availability, drought, and
34 reliance on declining ground water sources. Even in locations where water is generally plentiful,
35 localized impacts can still occur in certain instances. Excessive ground water pumping can cause
36 localized drawdowns; surface water withdrawals can affect stream flow, particularly in smaller
37 streams or during low flow periods. These findings emphasize the need to focus on regional and
38 local dynamics when examining potential impacts of hydraulic fracturing water acquisition on
39 drinking water quantity and quality.
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Text Box 4-6. Research Questions Revisited.
1 What are the types of water used for hydraulic fracturing?
2 • Water for hydraulic fracturing typically comes from surface, ground water, or reused wastewater.
3 Operators often use water sources as close to well pads as possible as trucking is a major expense.
4 Operators usually self-supply surface or ground water directly, but also may obtain water secondarily
5 through public water systems or other suppliers. Hydraulic fracturing operations in the eastern United
6 States generally rely on surface water, whereas operations in more semi-arid to arid western states use
7 mixed surface and ground water supplies. In areas that lack available surface water (e.g., western Texas),
8 ground water supplies most of the water needed for fracturing unless alternative sources, such as reused
9 wastewater, are available and utilized.
10 • The vast majority of water used nationally comes from fresh water sources, although some operators also
11 use lower-quality water (e.g., hydraulic fracturing wastewater, brackish ground water, or small
12 proportions of acid mine drainage and wastewater treatment plant effluent). The use of non-fresh
13 sources can reduce competition for current drinking water resources. Nationally, the proportion of
14 reused wastewater is generally low as a percentage of injected volume; based on available data, median
15 reuse of wastewater across all basins and plays is 5% of injected volume (see Table 4-1). Available data
16 on reuse trends indicate increasing reuse of wastewater over time in both Pennsylvania and West
17 Virginia, likely due to the lack of nearby disposal options. Reuse as a percentage of water injected appears
18 to be low in other areas, likely in part because of the relatively high availability of disposal wells (see
19 Chapter 8).
2 0 How m uch water is used per well?
21 • The median amount of water used per hydraulically fractured well, based on national disclosures to
22 FracFocus, is approximately 1.5 million gal (5.7 million L) of water (U.S. EPA. 2015a. b). This estimate
23 represents a variety of fractured well types. There is also wide variation within and among states and
24 basins in the median water volumes reported per disclosure, from more than 5 million gal (19 million L)
25 in Arkansas and Louisiana to less than 1 million gal (3.8 million L) in Colorado, Wyoming, Utah, New
26 Mexico, and California (U.S. EPA. 2015b). This variation results from several factors, including well
27 length, formation geology, and fracturing fluid formulation (see Section 4.3.3).
28 • Trends indicate that water use per well is increasing in certain locations as horizontal well lengths
29 increase. This may not, however, increase water use per unit energy extracted.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 How might cumulative water withdrawals for hydraulic fracturing affect drinking water quantity?
2 • Cumulatively, hydraulic fracturing uses billions of gallons of water every year at the national and state
3 scales, and even in some counties. When expressed as a percentage compared to total water use or
4 consumption at these scales, however, hydraulic fracturing water use and consumption is most often a
5 small percentage, generally less than 1%. This percentage may be higher in specific areas. Annual
6 hydraulic fracturing water use was 10% or more compared to 2010 total water use in 6.5% of counties
7 with FracFocus disclosures in 2011 and 2012, 30% or more in 2.2% of counties, and 50% or more in
8 1.0% of counties [U.S. EPA. 2015a). Consumption estimates follow the same general pattern, but with
9 slightly higher percentages in each category. In these counties, hydraulic fracturing represents a
10 relatively large user and consumer of water.
11 • High hydraulic fracturing water use or consumption alone does not necessarily result in impacts to
12 drinking water resources. Rather, the potential for impacts depends on both water use or consumption
13 and water availability at a given withdrawal point. Our state-by-state assessment examines the
14 intersection between water use or consumption and availability at the county scale. This approach
15 suggests where the potential for impacts exists, but does not indicate where impacts will occur at the
16 local scale. Local-scale case studies help provide details at finer spatial scales.
17 • In our survey of the published literature, we did not find a case where hydraulic fracturing water use by
18 itself caused a drinking water well or stream to run dry. This could indicate an absence of hydraulic
19 fracturing effects on water availability, or it could reflect that these events are not typically documented
20 in the types of literature we reviewed. Water availability is rarely impacted by just one use or factor
21 alone. For example, drinking water wells in an area overlapping with the Haynesville Shale in northwest
22 Louisiana ran out of water in 2011, due to higher than normal withdrawals and drought (LA Ground
23 Water Resources Commission. 2012]. Hydraulic fracturing water use in the area may have contributed to
24 these conditions, along with other water uses and the lack of precipitation. Other impacts to drinking
25 water quantity or quality (e.g., declining aquifer levels, decreased stream flow, increased pollutant
26 concentrations) also may occur before wells and streams actually go dry.
27 • The potential for impacts due to hydraulic fracturing water withdrawals is highest in areas with
2 8 relatively high fracturing water use and low water availability. Southern and western Texas are two
29 locations where hydraulic fracturing water use combined with low water availability, drought, and
3 0 reliance on declining ground water sources has the potential to affect the quantity of drinking water
31 resources. Any impacts are likely to be realized locally within these areas. In a detailed case study of
32 southern Texas, Scanlon etal. (2014) observed generally adequate water supplies for hydraulic
33 fracturing, except in specific locations. They found excessive drawdown of local ground water in a small
34 proportion (~6% of the area) of the Eagle Ford play. They suggested water management, particularly a
35 shift towards brackish water use, could minimize potential future impacts to fresh water resources (see
36 Text Box 4-3). County-level data confirm that high brackish water availability in Texas may help offset
37 hydraulic fracturing water demand (see Text Box 4-2).
38 • The potential for hydraulic fracturing water acquisition impacts to drinking water quantity and quality
39 appears to be lower—but not entirely eliminated—in other areas of the United States. Detailed case
40 studies in western Colorado and northeastern Pennsylvania did not show impacts, despite indicating that
41 streams could be vulnerable to water withdrawals from hydraulic fracturing (U.S. EPA. 2015c). High
42 wastewater reuse rates in western Colorado eliminated the need for more fresh water withdrawals. In
43 northeast Pennsylvania, water withdrawals for hydraulic fracturing could result in high water
44 consumption-to-stream flow events, but water management (e.g., passby flows) limited the potential for
45 impacts, especially on small streams (U.S. EPA, 2015c). In western North Dakota, ground water is limited,
46 but the industry may have sufficient supplies of surface water from the Missouri River system. These
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1 location-specific examples emphasize the need to focus on regional and local dynamics when considering
2 the potential impacts of hydraulic fracturing water acquisition on drinking water resources.
3 What are the possible impacts of water withdrawals for hydraulic fracturing on water quality?
4 • Water withdrawals for hydraulic fracturing, similar to all water withdrawals, have the potential to alter
5 the quality of drinking water resources. Ground water withdrawals exceeding natural recharge rates
6 decrease water storage in aquifers, potentially mobilizing contaminants or allowing the infiltration of
7 lower-quality water from the land surface or adjacent formations. Withdrawals could also decrease
8 ground water discharge to streams, potentially affecting surface water quality. Areas with numerous
9 high-capacity wells and large amounts of sustained ground water pumping are most likely to experience
10 impacts, particularly in drought-prone regions with limited ground water recharge.
11 • Surface water withdrawals also have the potential to affect water quality. Withdrawals may lower water
12 levels and alter stream flow, potentially decreasing a stream's capacity to dilute contaminants. Case
13 studies by the EPA show that streams can be vulnerable to changes in water quality due to water
14 withdrawals, particularly smaller streams and during periods of low flow fU.S. EPA. 2015c). Management
15 of the rate and timing of surface water withdrawals can help mitigate potential impacts of fracturing
16 withdrawals on water quality.
17 • Like water quantity effects, any effects of water withdrawals on water quality will likely occur nearest the
18 withdrawal point, again emphasizing the need for location specific assessments.
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OWRB (Oklahoma Water Resources Board). (2014). The Oklahoma comprehensive water plan. Available
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Plummer. M: Wood. T: Huang. H: Guo. L: Reiten. I: Chandler. K: Metesh. I. (2013). Water needs and availability
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Rahm. BG: Riha. SI. (2012). Toward strategic management of shale gas development: Regional, collective
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This document is a draft for review purposes only and does not constitute Agency policy.
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STRONGER (State Review of Oil and Natural Gas Environmental Regulations). (2012). Arkansas hydraulic
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http://seo.wvo.gov/ground-water/groundwater-control-areas-advisorv-boards
This document is a draft for review purposes only and does not constitute Agency policy.
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Yang. Y: Robart. Cl: Ruegamer. M. (2013). Analysis of U.S. Hydraulic Fracturing Design Trends. SPE Hydraulic
Fracturing Technology Conference, The Woodlands, Texas, USA.
Ziemkiewicz. P: Donovan. I: Hause. I: Gutta. B: Fillhart. I: Mack. B: O'Neal. M. (2013). Water quality literature
review and field monitoring of active shale gas wells: Phase II for Assessing Environmental Impacts of
Horizontal Gas Well Drilling Operations. Charleston, WV: West Virginia Department of Environmental
Protection.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 5
Chemical Mixing
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Hydraulic Fracturing Drinking Water Assessment
Chapter 5 - Chemical Mixing
5. Chemical Mixing
5.1. Introduction
1 This chapter addresses the potential for on-site spills of chemicals used in the chemical mixing
2 process to affect the quality of drinking water resources. Chemical mixing is a complex process that
3 requires the use of specialized equipment and a range of different additives to produce the
4 hydraulic fracturing fluid that is injected into the well. The number, type, and volume of chemicals
5 used vary from well to well based on site- and company-specific factors. Spills may occur at any
6 point in the hydraulic fracturing process. Chemicals may spill from on-site storage and containment
7 units; from interconnected hoses and pipes used to transfer chemicals to and from mixing and
8 pumping units, and tanker trucks; and from the equipment used to mix and pressurize chemical
9 mixtures that are pumped down the well. The potential for a spill to affect the quality of a drinking
10 water resource is governed by three overarching factors: (1) fluid characteristics (e.g., chemical
11 composition and volume), (2) chemical management and spill characteristics, and (3) chemical fate
12 and transport (see Figure 5-1). This chapter is organized around the three factors.
POTENTIAL
IMPACT
Figure 5-1. Factors governing potential impact to drinking water resources.
Factors include (1) fluid characteristics (e.g., chemical composition and volume), (2) chemical
management and spill characteristics, and (3) chemical fate and transport.
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Hydraulic Fracturing Drinking Water Assessment Chapter 5 - Chemical Mixing
1 Section 5.2 provides an introductory overview of the chemical mixing process. The number and
2 volume of chemicals used and stored on-site are affected by such variables as the type, size, and
3 goals of the operation; formation characteristics; depth of the well; the length of the horizontal leg;
4 and the number of fracturing phases and stages.
5 Section 5.3 describes the different components of the hydraulic fracturing fluid, generally
6 comprised of the base fluid, proppant, and additives, which may be either individual chemicals or
7 mixtures. The composition of the hydraulic fracturing fluid is engineered to meet specific criteria.
8 The total amount and types of additives vary according to the characteristics of the well, site
9 geology, economics, availability, and the production goals [e.g.. Maule etal.. 2013]. Section 5.4
10 presents the wide range of different chemicals used and their classes, the most frequently used
11 chemicals nationwide and from state-to-state, and volumes used.1 Appendix A provides a list of
12 chemicals that the EPA identified as being used in hydraulic fracturing fluids based on eight
13 sources.
14 Sections 5.5 to 5.7 discuss how chemicals are managed on-site, how spills may occur, and the
15 different approaches for addressing spills. Section 5.5 describes how the potential impact of a spill
16 on drinking water resources depends upon chemical management practices, such as storage, on-
17 site transfer, and equipment maintenance. Section 5.6 discusses spill prevention, containment, and
18 mitigation. A summary analysis of reported spills and their common causes at hydraulic fracturing
19 sites is presented in Section 5.7.
20 Section 5.8 discusses the fate and transport of spilled chemicals. Spilled chemicals may react and
21 transform into other chemicals, travel from the site of release to a nearby surface water, or leach
22 into the soils and reach ground water. Chemical fate and transport after a release depend on site
23 conditions, environmental conditions, physicochemical properties of the released chemicals, and
24 the volume of the release.
25 Section 5.9 provides an overview of on-going changes in chemical use in hydraulic fracturing, with
26 an emphasis on efforts by industry to reduce potential impacts from surface spills by using fewer
27 and safer chemicals. A synthesis and a discussion of limitations are presented in Section 5.10.
28 Factors affecting the frequency and severity of impacts to drinking water resources from surface
29 spills include size and type of operation, employee training and experience, standard operating
30 procedures, quality and maintenance of equipment, type and volume of chemical spilled,
31 environmental conditions, proximity to drinking water resources, spill prevention practices, and
32 spill mitigation measures. Due to the limitations of available data and the scope of this assessment,
33 it is not possible to provide a detailed analysis of all of the factors listed above. Data limitations also
34 preclude a quantitative analysis of the likelihood or magnitude of chemical spills or impacts. Spills
35 that occur off-site, such as those during transportation of chemicals or storage of chemicals in
36 staging areas, are out of scope. This chapter qualitatively characterizes the potential for impacts to
1 Chemical classes are groupings of different chemicals based on similar features, such as chemical structure, use, or
physical properties. Examples of chemical classes include hydrocarbons, pesticides, acids, and bases.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 5 - Chemical Mixing
1 drinking water resources given the current understanding of overall operations and specific
2 components of the chemical mixing process.
5.2. Chemical Mixing Process
3 An understanding of the chemical mixing process is necessary to understand how, why, and when
4 spills that may affect drinking water resources might occur. This description provides a general
5 overview of chemical mixing in the context of the overall hydraulic fracturing process [Carter etal..
6 2013: Knappe and Fireline. 2012: Spellman. 2012: Arthur etal.. 2008].
7 Figure 5-2 shows a hydraulic fracturing site during the chemical mixing process. The discussion
8 focuses on the types of additives used at each phase of the process. While similar processes are
9 used to fracture horizontal and vertical wells, a horizontal well treatment is described here because
10 it is likely to be more complex and because horizontal hydraulic fracturing has become more
11 prevalent over time with advances in hydraulic fracturing technology. A water-based system is
12 described because water is the most commonly used base fluid, appearing in more than 93% of
13 FracFocus disclosures between January 1, 2011 and February 28, 2012 [U.S. EPA, 2015a].
Figure 5-2. Hydraulic fracturing site showing equipment used on-site during the chemical
mixing process.
Source: Industry source.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 5 - Chemical Mixing
1 While the number and types of additives may widely vary, the basic chemical mixing process is
2 similar across sites. The on-site layout of hydraulic fracturing equipment is also similar from site to
3 site [BT Services Company. 2009). Equipment used in the chemical mixing process typically consists
4 of chemical storage trucks, water supply tanks, proppant supply, slurry blenders, a number of high-
5 pressure pumps, a manifold, surface lines and hoses, and a central control unit Detailed
6 descriptions of specific additives and the equipment used in the process are provided in Sections
7 5.3 and 5.5, respectively.
8 The chemical mixing process begins after the drilling, casing, and cementing processes are finished
9 and hydraulic fracturing equipment has been set up and connected to the well. The process can
10 generally be broken down into sequential phases with specific chemicals added at each phase to
11 achieve a specific purpose [Knappe and Fireline, 2012: Fink, 2003]. Phases may overlap. The
12 process for water-based hydraulic fracturing is outlined in Figure 5-3 below.
Chemical Mixing Phases
Pre-Pad: Acid
and/or chemicals
may be injected
into clean wellbore
Steps repeated for each stage:
.^ Perforation: Initiate fractures with physical impact
_/ Pad: Inject base fluid and additives into the formation to grow fractures
Proppant: Inject base fluid, additives and proppant to prop open fractures
Flush: Fluid may be injected to facilitate hydrocarbon flow
//
' //
/ /
Hydraulic Fracturing Stages //
II
i
& \> V V
Chemicals & K. Chemicals & •. K
Proppant Injected L
Proppant
gradient
^
Proppant Injected ' /
Proppant
gradient
Chemicals & K
Proppant Injected ' J
Proppant
gradient
-^^'n
ChemicalsS
I
n>
o
OJ
ff
00
1
lit
Proppant Injected
Proppant
gradient
_
'
,,
i= Horizontal Leg
Figure 5-3. Overview of a chemical mixing process of the hydraulic fracturing water cycle.
This figure outlines the chemical mixing process for a generic water-based hydraulic fracture of a
horizontal well. The chemical mixing phases outline the steps in the overall fracturing job, while the
hydraulic fracturing stages outline how each section of the horizontal well would be fractured
beginning with the toe of the well, shown on left-side. The proppant gradient represents how the
proppant size may change within each stage of fracturing as the fractures are elongated. The chemical
mixing process is repeated depending on the number of stages used for a particular well. The number
of stages is determined in part by the length of the horizontal leg. In this figure, four stages are
represented, but typically, a horizontal fracturing treatment would consist of 10 to 20 stages per well
(Lowe et al., 2013). Fracturing has been reported to be done in as many as 59 stages (Pearson et al.,
2013).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 5 - Chemical Mixing
1 The first phase of the process consists of the cleaning and preparation of the well. The fluid used in
2 this phase is often referred to as the pre-pad fluid or pre-pad volume. Acid is typically the first
3 chemical introduced. Acid, with a concentration of 3%-28% (typically hydrochloric acid, HC1), is
4 used to adjust pH, clean any cement left inside the well from cementing the casing, and dissolve any
5 pieces of rock that may remain in the well and could block the perforations. Acid is typically
6 pumped directly from acid storage tanks or tanker trucks, without being mixed with other
7 additives. The first, or pre-pad, phase may also involve mixing and injection of additional chemicals
8 to facilitate the flow of fracturing fluid introduced in the next phase of the process. These additives
9 may include biocides, corrosion inhibitors, friction reducers, and scale inhibitors [Carter etal.,
10 2013: King. 2012: Knappe andFireline. 2012: Spellman. 2012: Arthur etal.. 20081.
11 In the second phase, a hydraulic fracturing fluid, typically referred to as the pad or pad volume, is
12 mixed, blended, and pumped down the wellbore to create fractures in the formation. The pad is a
13 mixture of base fluid, typically water, and additives. The pad is designed to create, elongate, and
14 enlarge fractures along the natural channels of the formation when injected under high pressure
15 [Gupta and Valko. 2007]. A typical pad consists of, at minimum, a mixture of water and friction
16 reducer. The operator may also add other additives (see U.S. EPA (2015a] and Table 5-1) used to
17 facilitate flow and kill bacteria (Carter etal.. 2013: King. 2012: Knappe andFireline. 2012:
18 Spellman, 2012: Arthur etal., 2008]. The pad is pumped into the formation through perforations in
19 the well casing (see Text Box 5-1].
20
21
22
23
24
Text Box 5-1. Perforation.
Prior to the injection of the pad, the well casing is typically perforated to provide openings through which the
pad fluid can enter the formation. A perforating gun is typically used to create small holes in the section of the
wellbore being fractured. The perforating gun is lowered into position in the horizontal portion of the well.
An electrical current is used to set off small explosive charges in the gun, which creates holes through the well
casing and out a short, controlled distance into the formation [Gupta and Valko, 20071.
25 In the third phase, proppant, typically sand, is mixed into the hydraulic fracturing fluid. The
26 proppant volume, as a proportion of the injected fluid, is increased gradually until the desired
27 concentration in the fractures is achieved. Gelling agents, if used, are also mixed in with the
28 proppant and base fluid in this phase to increase the viscosity and carry the proppant. Additional
29 chemicals may be added to gelled fluids, initially to maintain viscosity and later to break the gel
30 down into a more readily removable fluid. (Carter etal.. 2013: King. 2012: Knappe and Fireline.
31 2012: Spellman. 2012: Arthur etal.. 20081.
32 A final flush or clean-up phase may be conducted after the stage is fractured, with the primary
3 3 purpose of maximizing well productivity. The flush is a mixture of water and chemicals that work to
34 aid the placement of the proppant, clean out the chemicals injected in previous phases, and prevent
35 microbial growth in the fractures (Knappe and Fireline. 2012: Fink. 2003].
36 The second, third, and fourth phases are repeated multiple times in a horizontal well, as the
37 horizontal section, or leg, of the wellbore is typically fractured in multiple segments referred to as
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 5 - Chemical Mixing
1 stages. For each stage, the well is typically perforated and fractured beginning at the end, or toe, of
2 the wellbore and proceeding backwards toward the vertical section. Each fractured stage is isolated
3 before the next stage is fractured. The number of stages corresponds directly to the number of
4 times the chemical mixing process is repeated at the site surface (see Figure 5-3). The number of
5 stages depends upon the length of the leg [Carter etal.. 2013: King. 2012: Knappe and Fireline,
6 2012: Spellman. 2012: Arthur etal.. 20081.
7 The number of stages per well can vary, with several sources suggesting between 10 and 20 is
8 typical [GNB, 2015: Lowe etal., 2013].' The full range reported in the literature is much wider, with
9 one source documenting between 1 and 59 stages per well [Pearson et al., 2013] and others
10 reporting values within this range [NETL. 2013: STO. 2013: Allison etal.. 2009]. It also appears that
11 the number of stages per well has increased over time. For instance, in the Williston Basin the
12 average number of stages per horizontal well rose from approximately 10 in 2008 to 30 in 2012
13 [Pearsonetal.. 2013].
14 In each of these phases, water is the primary component of the hydraulic fracturing fluid, though
15 the exact composition of the fluid injected into the well changes over the duration of each stage. In
16 water-based hydraulic fracturing, water typically comprises between 90% and 94% of the
17 hydraulic fracturing fluid, proppant comprises 5% to 9%, and additives comprise the remainder,
18 typically 2% or less [Carter etal.. 2013: Knappe and Fireline. 2012: SWN. 2011]. The exception to
19 this typical fluid composition may be when a concentrated acid is used in the initial cleaning phase
20 of the fracturing process.
5.3. Overview of Hydraulic Fracturing Fluids
21 Hydraulic fracturing fluids are formulated to perform specific functions: create and extend the
22 fracture, transport proppant, and place the proppant in the fractures [Montgomery. 2013:
23 Spellman, 2012: Gupta and Valko, 2007]. The hydraulic fracturing fluid generally consists of three
24 parts: [1] the base fluid, which is the largest constituent by volume, [2] the additives, which can be
25 a single chemical or a mixture of chemicals, and [3] the proppant Additives are chosen to serve a
26 specific purpose in the hydraulic fracturing fluid (e.g., friction reducer, gelling agent, crosslinker,
27 biocide] [Spellman. 2012]. Throughout this chapter, "chemical" is used to refer to individual
28 chemical compounds (e.g., methanol]. Proppants are small particles, usually sand, mixed with
29 fracturing fluid to hold fractures open so that the target hydrocarbons can flow from the formation
30 through the fractures and up the wellbore. The combination of chemicals, and the mixing and
31 injection process, varies based on a number of factors as discussed below. The chemical
32 combination determines the amount and what type of equipment is required for storage and,
33 therefore, contributes to the determination of the potential for spills and impacts of those spills.
34 The particular composition of hydraulic fracturing fluids is selected by a design engineer based on
35 empirical experience, the formation, economics, goals of the fracturing process, availability of the
1 The number of stages has been reported to be 6 to 9 in the Huron in 2009 [Allison etal.. 2009). 25 and up in the
Marcellus [NETL. 2013). and up to 40 by STO (2013).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 5 - Chemical Mixing
1 desired chemicals, and preference of the service company or operator [Montgomery, 2013: ALL
2 Consulting. 2012: Klein etal.. 2012: Ely. 1989]. No single set of specific chemicals is used at every
3 site. Multiple types of fracturing fluids may be appropriate for a given site and any given type of
4 fluid may be appropriate at multiple sites. For the same type of fluid formulation, there can be
5 differences in the additives, chemicals, and concentrations selected. There are broad criteria for
6 hydraulic fracturing fluid selection based on the fracturing temperatures, formation permeability,
7 fracturing pressures, and formation water sensitivity, as shown in Figure 5-4 [Gupta and Valko,
8 2007: Elbel and Britt. 2000). One of the most important properties in designing a hydraulic
9 fracturing fluid is the viscosity [Montgomery, 2013].x
10 Figure 5-4 provides a general overview of which fluids can be used in different situations. As an
11 example, crosslinked fluids with 25% nitrogen foam (titanate or zirconate crosslink + 25% N2) can
12 be used in both gas and oil wells with high temperatures with variation in water sensitivity.
1 Viscosity is a measure of the internal friction of fluid that provides resistance to shear within the fluid, informally
referred to as how "thick" a fluid is. For example, custard is thick and has a high viscosity, while water is runny with a low
viscosity. Sufficient viscosity is needed to create a fracture and transport proppant [Gupta and Valko. 2007). In lower-
viscosity fluids, proppant is transported by turbulent flow and requires more hydraulic fracturing fluid. Higher-viscosity
fluids allows the fluid to carry more proppant, requiring less fluid but necessitating the reduction of viscosity after the
proppant is placed [Rickman etal.. 2008: Gupta and Valko. 2007).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 5 - Chemical Mixing
Gas Well
Oil Well
u
N
"
Less
|
Low pressure
or
No - water sensitiv
'
ss - 150°F -(More
7
c
Surface-delayed
borate c
corsslinkedguar +
or HPG
~I
., J kfW > 1000 md-ft + x,
Linear fluids
175°F
Low pressure
e Yes
or
No - water sensitive ~ Yes
~L
Foamed
fluids
0% - 75%
uality or
lowpH
rosslinked
25% CO2
Delays
titanate
crossli
Less -300°F1 More Less -| 250°F \ More
"L ~T
i \ i
LowpH
crosslinked Titanate
+ or
25% CO2 zirconate
Super crosslinked
foam +
id borate, Zirconate borate 25% Nj
or zirconate crosslinked + N
nkedguar HPG
> 300 ft .
-Yes
'
Low
No - Pressure
{See gas
well guide
Low
No PressL
1
Less -200°F- More
]
.
polymer cr<
emulsion
Very water sensitive _ ^
'
Low
Yes No • Pressu
T
lore
re Yes
T
P
Gelled oil Gelled oil + N2
re - Yes
A—,
Less -200°F- More
rconate 200°F
clinked Less~ -Mor
HPG
-] f-
Low pH Titanat
crosslinked cr
25% CO2
e
6 1
e or zirconate
osslinked
25% N2
Figure 5-4. Example fracturing fluid decision tree for gas and oil wells.
Adapted from Elbel and Britt (2000).
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
5-8
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1 Table 5-1 provides a list of common types of additives, their functions, and the most frequently
2 used chemicals for each purpose based on the EPA's analysis of disclosures to FracFocus 1.0
3 (hereafter EPA FracFocus report; U.S. EPA[2015a]]. the EPA's project database of disclosures to
4 FracFocus 1.0 [hereafter EPA FracFocus database; U.S. EPA[2015b]], and other literature sources.
5 Additional information on more additives can be found in U.S. EPA f2015al.
Table 5-1. Examples of common additives, their function, and the most frequently used
chemicals reported to FracFocus for these additives.
The list of examples of common additives was developed from information provided in multiple
sources (U.S. EPA, 2015a, b; Stringfellow et al., 2014; Montgomery, 2013; Vidicetal., 2013; Spellman,
2012; GWPC and ALL Consulting, 2009; Arthur et al., 2008; Gupta and Valko, 2007; Gidleyet al., 1989).
The additive functions are based on information the EPA received from service companies (U.S. EPA,
2013a).
Additives
Acid
Biocide
Breaker
Clay control
Corrosion
inhibitor
Crosslinker
Emulsifier
Foaming agent
Function
Dissolves cement, minerals, and clays to
reduce clogging of the pore space
Controls or eliminates bacteria, which
can be present in the base fluid and may
have detrimental effects on the
fracturing process
Reduces the viscosity of specialized
treatment fluids such as gels and foams
Prevents the swelling and migration of
formation clays in reaction to water-
based fluids
Protects the iron and steel components
in the wellbore and treating equipment
from corrosive fluids
Increases the viscosity of base gel fluids
by connecting polymer molecules
Facilitates the dispersion of one
immiscible fluid into another by reducing
the interfacial tension between the two
liquids to achieve stability
Generates and stabilizes foam fracturing
fluids
Chemicals reported in >20% of
FracFocus disclosures for additive3'15
Hydrochloric acid
Glutaraldehyde;
2,2-dibromo-3-nitrilopropionamide
Peroxydisulfuric acid diammonium salt
Choline chloride
Methanol; propargyl alcohol; isopropanol
Ethylene glycol; potassium hydroxide;
sodium hydroxide
2-Butoxyethanol;
polyoxyethylene(10)nonylphenyl ether;
methanol; nonyl phenol ethoxylate
2-Butoxyethanol; Nitrogen, liquid;
isopropanol; methanol; ethanol
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Additives
Function
Chemicals reported in >20% of
FracFocus disclosures for additive3'15
Friction reducer
Reduces the friction pressures
experienced when pumping fluids
through tools and tubulars in the
wellbore
Hydrotreated light petroleum distillates
Gelling agent
Increases fracturing fluid viscosity
allowing the fluid to carry more proppant
into the fractures and to reduce fluid loss
to the reservoir
Guargum; hydrotreated light petroleum
distillates
Iron control
agent
Controls the precipitation of iron from
solution
Citric acid
Nonemulsifier
Separates problematic emulsions
generated within the formation
Methanol; isopropanol; nonyl phenol
ethoxylate
pH control
Affects the pH of a solution by either
inducing a change (pH adjuster) or
stabilizing and resisting change (buffer)
to achieve desired qualities and optimize
performance
Carbonic acid, dipotassium salt; potassium
hydroxide; sodium hydroxide; acetic acid
Resin curing
agents
Lowers the curable resin coated
proppant activation temperature when
bottom hole temperatures are too low to
thermally activate bonding
Methanol; nonyl phenol ethoxylate;
isopropanol; alcohols, C12-14-secondary,
ethoxylated
Scale inhibitor
Controls or prevents scale deposition in
the production conduit or completion
system
Ethylene glycol; methanol
Solvent
Controls the wettability of contact
surfaces or prevents or breaks emulsions
Hydrochloric acid
a Chemicals (excluding water and quartz) listed as reported to FracFocus in more than 20% of disclosures for a given purpose
when that purpose was listed as used on a disclosure. These are not necessarily the active ingredients for the purpose, but
rather are listed as being commonly present for the given purpose. Chemicals may be disclosed for more than a single
purpose (e.g., 2-butoxyethanol is listed as being used as an emulsifier and a foaming agent).
Analysis considered 32,885 disclosures and 615,436 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; valid CASRN; valid concentrations; and valid purpose. Disclosures that did not meet quality
assurance criteria (5,645) or other, query-specific criteria were excluded from analysis.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 A general description of typical hydraulic fracturing fluid formulations nationwide is difficult
2 because fracturing fluids vary from well to well. Based on the FracFocus report, the median number
3 of chemicals reported for each disclosure was 14, with the 5th to 95th percentile ranging from four to
4 28. The median number of chemicals per disclosure was 16 for oil wells and 12 for gas wells [U.S.
5 EPA, 2015b]. Other sources have stated that between three and 12 additives and chemicals are
6 used [Schlumberger. 2015: Carter etal.. 2013: Spellman. 2012: GWPC and ALL Consulting. 2009]. 1
7 Water, the most commonly used base fluid for hydraulic fracturing, is inferred to be used as a base
8 fluid in more than 93% of FracFocus disclosures. Alternatives to water-based fluids, such as
9 hydrocarbons and gases, including carbon dioxide or nitrogen-based foam, may also be used based
10 on formation characteristics, cost, or preferences of the well operator or service company [ALL
11 Consulting, 2012: GWPC and ALL Consulting, 2009]. Non-aqueous base fluid ingredients were
12 identified in 761 [2.2%] of FracFocus 1.0 disclosures fU.S. EPA. 2015a). Gases and hydrocarbons
13 may be used alone or blended with water; more than 96% of the disclosures identifying non-
14 aqueous base fluids are blended [U.S. EPA, 2015a]. There is no standard method to categorize the
15 different fluid formulations [Patel etal., 2014: Montgomery, 2013: Spellman, 2012: Gupta and
16 Valko, 2007]. Therefore, we broadly categorize the fluids as water-based or alternative fluids.
5.3.1. Water-Based Fracturing Fluids
17 The advantages of water-based fracturing fluids are low cost, ease of mixing, and ability to recover
18 and recycle the water. The disadvantages are low viscosity, the narrowness of the fractures created,
19 and they may not provide optimal performance in water-sensitive formations (see Section 5.3.2]
20 [Montgomery. 2013: Gupta and Valko. 2007]. Water-based fluids can be as simple as water with a
21 few additives to reduce friction, such as "slickwater," or as complex as water with crosslinked
22 polymers, clay control agents, biocides, and scale inhibitors [Spellman, 2012].
2 3 Gels may be added to water-based fluids to increase viscosity, which assists with proppant
24 transport and results in wider fractures. Gelling agents include natural polymers, such as guar,
25 starches, and cellulose derivatives, which requires the addition of biocide to minimize bacterial
26 growth [Spellman. 2012: Gupta and Valko. 2007]. Gels may be linear or crosslinked. Crosslinking
27 increases viscosity without adding more gel. Gelled fluids require the addition of a breaker, which
28 breaks down the gel after it carries in the proppant, to reduce fluid viscosity to facilitate fluid
29 flowing back after treatment [Spellman, 2012: Gupta and Valko, 2007]. The presence of residual
30 breakers may make it difficult to reuse recovered water [Montgomery. 2013].
5.3.2. Alternative Fracturing Fluids
31 Alternative hydraulic fracturing fluids can be used for water-sensitive formations (i.e., formations
32 where permeability is reduced when water is added] or as dictated by production goals
33 (Halliburton. 1988]. Examples of alternative fracturing fluids include acid-based fluids; non-
34 aqueous-based fluids; energized fluids, foams or emulsions; viscoelastic surfactant fluids; gels;
1 Sources may differ based on whether they are referring to additives or chemicals.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 methanol; and other unconventional fluids [Montgomery, 2013: Sabaetal., 2012: Gupta and Hlidek,
2 2009: Gupta and Valko. 2007: Halliburton. 19881.
3 Acid fracturing removes the need for a proppant and is generally used in carbonate formations.
4 Fractures are initiated with a viscous fracturing fluid, and the acid (gelled, foamed, or emulsified) is
5 added to irregularly etch the wall of the fracture and prop open the formation for a higher
6 conductivity fracture [Spellman, 2012: Gupta and Valko, 2007].
7 Non-aqueous fluids are used in water-sensitive formations. Non-aqueous fluids may also contain
8 additives, such as gelling agents, to improve performance [Gupta and Valko. 2007]. The use of non-
9 aqueous fluids has decreased due to safety concerns, and because water-based and emulsion fluid
10 technologies have improved [Montgomery. 2013: Gupta and Valko. 2007]. Methanol, for example,
11 was previously used as a base fluid in water-sensitive reservoirs beginning in the early 1990s, but
12 was discontinued in 2001 for safety concerns and cost [Sabaetal., 2012: Gupta and Hlidek, 2009:
13 Gupta and Valko, 2007]. Methanol is still used as an additive or in additive mixtures in hydraulic
14 fracturing fluid formulations.
15 Energized fluids, foams, and emulsions minimize fluid leakoff, have high proppant-carrying
16 capacity, improve fluid recovery, and are sometimes used in water-sensitive formations [Barati and
17 Liang. 2014: Gu andMohanty. 2014: Spellman. 2012: Gupta and Valko. 2007: Martin and Valko.
18 2007].* However, these treatments tend to be expensive, require high pressure, and pose potential
19 health and safety concerns fMontgomery. 2013: Spellman. 2012: Gupta and Valko. 20071
20 Energized fluids are mixtures of liquid and gas [Patel etal., 2014: Montgomery, 2013]. Nitrogen
21 (N2] or carbon dioxide (C02], the gases used, make up less than 53% of the fracturing fluid volume,
22 typically ranging from 25% to 30% by volume [Montgomery. 2013: Gupta and Valko. 2007:
23 Mitchell, 1970]. Energized foams are liquid-gas mixtures, with N2 or C02 gas comprising more than
24 53% of the fracturing fluid volume, with a typical range of 70% to 80% by volume [Mitchell, 1970].
25 Emulsions are liquid-liquid mixtures, typically a hydrocarbon (e.g., condensate or diesel] with
26 water, with the hydrocarbon typically 70% to 80% by volume.2 Both water-based fluids, including
27 gels, and non-aqueous fluids can be energized fluids or foams.
28 Foams and emulsions break easily using gravity separation and are stabilized by using additives
29 such as foaming agents (Gupta and Valko. 2007]. Emulsions may be used to stabilize active chemical
30 ingredients or to delay chemical reactions, such as the use of carbon dioxide-miscible, non-aqueous
31 fracturing fluids to reduce fluid leakoff in water-sensitive formations (Taylor et al.. 2006].
3 2 Other types of fluids not addressed above include viscoelastic surfactant fluids, viscoelastic
3 3 surfactant foams, crosslinked foams, liquid carbon dioxide-based fluid, and liquid carbon dioxide-
34 based foam fluid, and hybrids of other fluids fKing. 2010: Brannon etal.. 2009: Curtice etal.. 2009:
1 Leakoff is the fraction of the injected fluid that infiltrates into the formation (e.g., through an existing natural fissure) and
is not recovered during production [Economides et al.. 2007). See Chapter 6, Section 6.3 for more discussion on leakoff.
2 Diesel is a mixture typically of C8 to C21 hydrocarbons.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
1 Tudoretal..20Q9: Gupta and Valko. 2007: Coulter etal.. 2006: Boyer etal.. 2005: Freddetal.. 2004:
2 MacDonaldetal.. 20031.
3 Alternative fluids have been developed to work in tight formations, shales, and coalbeds, where
4 production is based on desorption of the natural gas, or in formations where the fracturing fluid
5 must displace a fluid that is already in place.
5.3.3. Proppants
6 Proppants are small particles carried down the well and into fractures by fracturing fluid. They hold
7 the fractures open after hydraulic fracturing fluid has been removed [Brannon and Pearson, 2007].
8 The propped fractures provide a path for the hydrocarbon to flow from the reservoir. Sand is most
9 commonly used, but other proppants include man-made or specially engineered particles, such as
10 resin-coated sand, high-strength ceramic materials, or sintered bauxite [Schlumberger, 2014:
11 Brannon and Pearson, 2007]. Proppant types can be used individually or in combinations.
5.4. Frequency and Volume of Hydraulic Fracturing Chemical Use
12 This section highlights the different chemicals used in hydraulic fracturing and discusses the
13 frequency and volume of use. Based on the U.S. EPA analysis of the FracFocus 1.0 database (see Text
14 Box 5-2], we focus our analysis on individual chemicals rather than mixtures of chemicals used as
15 additives. Chemicals are reported to FracFocus by using the chemical name and the Chemical
16 Abstract Services Registration Number (CASRN], which is a unique number identifier for every
17 chemical substance.1 The information on specific chemicals, particularly those most commonly
18 used, can be used to assess potential impacts to drinking water resources. The volume of chemicals
19 stored on-site provides information on the potential volume of a chemical spill.
1 A CASRN and chemical name combination identify a chemical substance, which can be a single chemical (e.g.,
hydrochloric acid, CASRN 7647-01-0) or a mixture of chemicals (e.g., hydrotreated light petroleum distillates (CASRN
64742-47-8), a complex mixtures of C9to C16 hydrocarbons). For simplicity, we refer to both pure chemicals and
chemical substances that are mixtures, which have a single CASRN, as "chemicals."
This document is a draft for review purposes only and does not constitute Agency policy.
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Text Box 5-2. The FracFocus Registry and EPA FracFocus Report.
The Ground Water Protection Council (GWPC) and the Interstate Oil and Gas Compact Commission (IOGCC)
developed a national hydraulic fracturing chemical registry, FracFocus [www.fracfocus.org]. Well operators
can use the registry to disclose information about chemicals they use during hydraulic fracturing. The EPA
accessed data from FracFocus 1.0 from January 1, 2011 to February 28, 2013, which included more than
39,000 disclosures from 20 states that had been submitted by operators prior to March 1,2013.
Submission to FracFocus was initially voluntary and varied from state to state. During the timeframe of the
EPA's study, six of the 20 states with data in the project database began requiring operators to disclose
chemicals used in hydraulic fracturing fluids to FracFocus (Colorado, North Dakota, Oklahoma, Pennsylvania,
Texas, and Utah). Three other states started requiring disclosure to either FracFocus or the state (Louisiana,
Montana, and Ohio), and five states required or began requiring disclosure to the state (Arkansas, Michigan,
New Mexico, West Virginia, and Wyoming). Alabama, Alaska, California, Kansas, Mississippi, and Virginia did
not have reporting requirements during the period of the EPA's study.
Disclosures from the five states reporting the most disclosures to FracFocus (Texas, Colorado, Pennsylvania,
North Dakota, and Oklahoma) comprise over 78% of the disclosures in the database; nearly half (47%) of the
disclosures are from Texas. Thus, data from these states are most heavily represented in the EPA's analyses.
The EPA's analysis may or may not be nationally representative.
The EPA summarized information on the locations of the wells in the disclosures, water volumes used, and
the frequency of use and concentrations (% by mass, reported as maximum ingredient concentration) of the
chemicals in the additives and the hydraulic fracturing fluid. Additional information can be found in the EPA
FracFocus report (U.S. EPA. 2015a).
21 The EPA compiled a list of 1,076 chemicals known to be have been used in the hydraulic fracturing
22 process (see a full list, methodology, and the source citations in Appendix A). The chemicals used in
23 hydraulic fracturing fall into different chemical classes and include both organic and inorganic
24 chemicals. The chemical classes of commonly used hydraulic fracturing chemicals include but are
25 not limited to:
26 • Acids (e.g., hydrochloric acid, peroxydisulfuric acid, acetic acid, citric acid).
27 • Alcohols (e.g., methanol, isopropanol, ethylene glycol, propargyl alcohol, ethanol).
28 • Aromatic hydrocarbons (e.g., benzene, naphthalene, heavy aromatic petroleum solvent
29 naphtha).
30 • Bases (e.g., sodium hydroxide, potassium hydroxide).
31 • Hydrocarbon mixtures (e.g., petroleum distillates).
32 • Polysaccharides (e.g., guar gum).
33 • Surfactants (e.g., poly(oxy-l,2-ethanediyl)-nonylphenyl-hydroxy, 2-butoxyethanol).
34 • Salts (e.g., sodium chlorite, dipotassium carbonate).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
2
3
4
5
6
7
8
10
11
12
13
14
15
16
17
18
19
20
21
Text Box 5-3. Confidential Business Information (CBI)
This assessment relies in large part upon information provided to the EPA or to other organizations. The
submitters of that information (e.g., businesses that operate wells or perform services to hydraulically
fracture the well) may view some of the information as confidential business information (CBI), and
accordingly asserted CBI claims to protect such information. Information deemed to be CBI may include
information such as trade secrets or other proprietary business information, entitled to confidential
treatment under Exemption 4 of the Freedom of Information Act (FOIA) and other applicable laws. FOIA and
the EPA's CBI regulations may allow for information claimed as CBI provided to the EPA to be withheld from
the public, including in this document.
The EPA evaluated data from FracFocus 1.0, a national hydraulic fracturing chemical registry used and relied
upon by some states, industry groups and non-governmental organizations. A company submitting a
disclosure to FracFocus may choose to not report the identity of a chemical it considers CBI. As part of the
EPA's analysis, more than 39,000 FracFocus 1.0 disclosures over the period January 1, 2013 to March 1,2013
were analyzed and more than 70% of disclosures contained at least one chemical designated as CBI. Of the
disclosures containing CBI chemicals, there was an average of five CBI chemicals per disclosure (U.S. EPA.
2015a). The prevalence of CBI claims in FracFocus 1.0 limits completeness of the data set.
Consistent with the hydraulic fracturing study plan, data were submitted by nine service companies to the
EPA regarding chemicals used in hydraulic fracturing from 2005 to 2009. Because this submission was to the
EPA, the EPA was given the actual names and CASRNs of any chemicals the company considered CBI. This
included a total of 381 CBI chemicals, with a mean of 42 CBI chemicals per company and a range of 7 to 213
(U.S. EPA. 2013a).
5.4.1. National Frequency of Use of Hydraulic Fracturing Chemicals
22 The EPA reported that 692 chemicals were reported to FracFocus 1.0 for use in hydraulic fracturing
23 from January 1, 2011, to February 28, 2013, with a total of 35,957 disclosures [U.S. EPA. 20153].!
24 Table 5-2 presents the 35 chemicals (5% of all chemicals identified in the EPA's study) that were
25 reported in at least 10% of the FracFocus 1.0 disclosures for all states reporting to FracFocus
26 during this time. This table also includes the top four additives that were reported to include the
27 given chemical in FracFocus disclosures from January 1, 2011 to February 28, 2013.
1 The EPA reported that 692 chemicals were reported to FracFocus 1.0 for use in hydraulic fracturing from January 1,
2011, to February 28,2013, with a total of 35,957 disclosures. Chemicals may be pure chemicals (e.g., methanol) or
chemical mixtures (e.g., hydrotreated light petroleum distillates), and they each have a single CASRN. Of these 692
chemicals, 598 had valid fluid and additive concentrations (34,675 disclosures). Sixteen chemicals were removed because
they were minerals listed as being used as proppants. This left a total of 582 chemicals (34,344 disclosures).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Table 5-2. Chemicals reported to FracFocus 1.0 from January 1, 2011 to February 28, 2013 in
10% or more disclosures, with the percent of disclosures for which each chemical is
reported and the top four reported additives for the chemical.
For chemicals with fewer than four reported additives, the table presents all additives (U.S. EPA,
2015b).
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Chemical name3
Methanol
Hydrotreated light
petroleum distillates
Hydrochloric acid
Water
Isopropanol
Ethylene glycol
Peroxydisulfuric acid,
diammonium salt
Sodium hydroxide
Guar gum
Quartz6
Glutaraldehyde
Propargyl alcohol
Potassium hydroxide
Ethanol
CASRN
67-56-1
64742-47-8
7647-01-0
7732-18-5
67-63-0
107-21-1
7727-54-0
1310-73-2
9000-30-0
14808-60-7
111-30-8
107-19-7
1310-58-3
64-17-5
Percent of
disclosures'3
72%
65%
65%
48%
47%
46%
44%
39%
37%
36%
34%
33%
29%
29%
Chemical used in these additives
(four most common, FracFocus database)0
corrosion inhibitors, surfactants, non-
emulsifiers, scale control
friction reducers, gelling agents and gel
stabilizers, crosslinkers and related additives,
viscosifiers
acids, solvents, scale control, clean
perforations
acids, biocides, clay control, scale control
corrosion inhibitors, non-emulsifiers,
surfactants, biocides
crosslinkers and related additives, scale
control, corrosion inhibitors, friction reducers
breakers and breaker catalysts, oxidizer,
stabilizers, clean perforations
crosslinkers and related additives, biocides,
pH control, scale control
gelling agents and gel stabilizers, viscosifiers,
clean perforations, breakers and breaker
catalysts
breakers and breaker catalysts, gelling agents
and gel stabilizers, scale control, crosslinkers
and related additives
biocides, surfactants, crosslinkers and related
additives, sealers
corrosion inhibitors, inhibitors, acid inhibitors,
base fluid
crosslinkers and related additives, pH control,
friction reducers, gelling agents and gel
stabilizers
surfactants, biocides, corrosion inhibitors,
fluid foaming agents and energizers
This document is a draft for review purposes only and does not constitute Agency policy.
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No.
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Chemical name3
Acetic acid
Citric acid
2-Butoxyethanol
Sodium chloride
Solvent naphtha,
petroleum, heavy arorn/
Naphthalene
2,2-Dibromo-3-
nitrilopropionamide
Phenolic resin
Choline chloride
Methenamine
Carbonic acid,
dipotassium salt
1,2,4-Trimethylbenzene
Quaternary ammonium
compounds, benzyl-C12-
16-alkyldimethyl,
chlorides8
Poly(oxy-l,2-ethanediyl)-
nonylphenyl-hydroxy
(mixture)h
Formic acid
Sodium chlorite
Nonyl phenol ethoxylate
CASRN
64-19-7
77-92-9
111-76-2
7647-14-5
64742-94-5
91-20-3
10222-01-2
9003-35-4
67-48-1
100-97-0
584-08-7
95-63-6
68424-85-1
127087-87-0
64-18-6
7758-19-2
9016-45-9
Percent of
disclosures'3
24%
24%
21%
21%
21%
19%
16%
14%
14%
14%
13%
13%
12%
12%
12%
11%
11%
Chemical used in these additives
(four most common, FracFocus database)0
pH control, iron control agents, acids, gelling
agents and stabilizers
iron control agents, scale control, gelling
agents and gel stabilizers, pH control
surfactants, corrosion inhibitors, non-
emulsifiers, fluid foaming agents and
energizers
breakers/breaker catalysts, friction reducers,
scale control, clay control
surfactants, non-emulsifiers, inhibitors,
corrosion inhibitors
surfactants, non-emulsifiers, corrosion
inhibitors, inhibitors
biocides, clean perforations, breakers and
breaker catalysts, non-emulsifiers
proppants, biocides, clean perforations, base
fluid
clay control, clean perforations, base fluid,
biocides
proppants, crosslinkers and related additives,
biocides, base fluid
pH control, proppants, acids, surfactants
surfactants, non-emulsifiers, corrosion
inhibitors, inhibitors
biocides, non-emulsifiers, corrosion inhibitors,
scale control
surfactants, friction reducers, non-emulsifiers,
inhibitors
corrosion inhibitors, acids, inhibitors, pH
control
breakers/breaker catalysts, biocides, oxidizer,
proppants
non-emulsifiers, resin curing agents,
activators, friction reducers
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
No.
32
33
34
35
Chemical name3
Tetrakis(hydroxymethyl)p
hosphonium sulfate
Polyethylene glycol
Ammonium chloride
Sodium persulfate
CASRN
55566-30-8
25322-68-3
12125-02-9
7775-27-1
Percent of
disclosures'3
11%
11%
10%
10%
Chemical used in these additives
(four most common, FracFocus database)0
biocides, scale control, clay control
biocides, non-emulsifiers, surfactants, clay
control
friction reducers, crosslinkers and related
additives, scale control, clay control
breakers and breaker catalysts, oxidizer, pH
control
a Chemical refers to chemical substances with a single CASRN, these may be pure chemicals (e.g., methanol) or chemical
mixtures (e.g., hydrotreated light petroleum distillates).
b Analysis considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet quality assurance criteria
(3,855) or other, query-specific criteria were excluded from analysis.
c Analysis considered 32,885 disclosures and 615,436 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; valid CASRN; valid concentrations; and valid purpose. Disclosures that did not meet quality
assurance criteria (5,645) or other, query-specific criteria were excluded from analysis.
Hydrotreated light petroleum distillates (CASRN 64742-47-8) is a mixture of hydrocarbons, in the C9 to C16 range.
e Quartz (CASRN 14808-60-7) the proppant most commonly reported, was also reported as an ingredient in other additives
U.S. EPA(2015a).
Heavy aromatic solvent naphtha (petroleum) (CASRN 64742-94-5) is mixture of aromatic hydrocarbons, in the C9 to C16
range.
5 Quaternary ammonium compounds, benzyl-C12-16-alkyldimethyl, chlorides (CASRN 68424-85-1) is a mixture of
benzalkonium chloride with carbon chains between 12 and 16.
Poly(oxy-l,2-ethanediyl)-nonylphenyl-hydroxy (mixture) (CASRN 127087-87-0) is mixture with varying length ethoxy links.
1 There is no single chemical used at all wells across the nation. Methanol is the most commonly used
2 chemical, reported at 72.1% of wells in FracFocus 1.0, and is associated with 33 types of additives,
3 including corrosion inhibitors, surfactants, non-emulsifiers, and scale control [U.S. EPA. 2015b).
4 Table 5-2 also shows the variability in different chemicals reported to FracFocus 1.0. The
5 percentage of disclosures reporting a given chemical suggests the likelihood of that chemical's use
6 at a site. Only three chemicals (methanol, hydrotreated light petroleum distillates, and hydrochloric
7 acid) were used at more than half of the sites nationwide, and only 12 were used at more thanone-
8 third.
9 In addition to providing information on frequency of use, FracFocus 1.0 data provides the
10 maximum concentration by mass of a given chemical in an additive. For example, for the most
11 frequently used chemical, methanol, the median maximum additive concentration reported in
12 FracFocus disclosures is 30%, by mass, with a range of 0.44% to 100% (5th to 95th percentile). This
13 suggests that methanol is generally used as part of a mixture of chemicals in the hydraulic
14 fracturing fluid, and may be stored in a mixture of chemicals or as pure methanol. This wide range
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
1 of possible concentrations of methanol further complicates assessing the potential impact of spills,
2 as the properties of the fluid will depend on the different chemicals present and on their
3 concentrations. For all chemicals, spills of a highly concentrated chemical can have different
4 potential impacts than spills of dilute mixtures.
5.4.2. Nationwide Oil versus Gas
5 FracFocus 1.0 data also can elucidate the differences between the chemicals used for oil production
6 and those used for gas production, providing a better understanding of potential spill impacts from
7 each. Table C-l and C-2 in Appendix C present the chemicals reported in at least 10% of all gas (34
8 chemicals) and oil (39 chemicals) disclosures nationwide.
9 Many of the same chemicals are used for oil and gas, but some chemicals are used more frequently
10 in oil production and others more frequently in gas.1 For example, hydrochloric acid is the most
11 commonly reported chemical for gas wells (73% of disclosures); it is the fifth most frequently
12 reported chemical for oil wells (58% of disclosures). However, both oil and gas operators each
13 reports using methanol in 72% of disclosures. Methanol is the most common chemical used in
14 hydraulic fracturing fluids at oil wells and the second most common chemical in hydraulic
15 fracturing fluids at gas wells.
5.4.3. State-by-State Frequency of Use of Hydraulic Fracturing Chemicals
16 We conducted a state-by-state analysis of chemical use based on FracFocus 1.0 disclosures (U.S.
17 EPA. 2015b). Some states reported more disclosures than other states, because they have relatively
18 more hydraulic fracturing activity and/or greater numbers of disclosures to FracFocus 1.0.
19 Reporting can bias national numbers towards those states with a disproportionate number of
20 disclosures. For example, the EPA (2015a) reported that Texas had 16,405 of the 34,675
21 disclosures with parsed ingredients and valid CASRNs and concentrations, making up almost half
22 (47%) of all disclosures for the 20 states reporting to FracFocus 1.0. We attempt to account for the
23 possible effect of having a large number of disclosures in Texas by looking at a compilation of the
24 top 20 chemicals reported to FracFocus for all states.
25 Table 5-3 presents and ranks chemicals reported most frequently to FracFocus 1.0 for each state
26 (U.S. EPA. 2015b). There are 94 unique chemicals comprising the top 20 chemicals for each state,
27 indicating similarity in chemical usage among states.
28 Methanol is reported in 19 of the 20 (95%) states. Alaska is the only state in which methanol is not
29 reported (based on the state's 20 disclosures to FracFocus). The percentage of disclosures
30 reporting use of methanol ranges from 38% (Wyoming) to 100% (Alabama, Arkansas).
31 Ten chemicals (excluding water) are among the 20 most frequently reported in 14 of the 20 states.
32 These chemicals are: methanol; hydrotreated light petroleum distillates; ethylene glycol;
1 This separation was done solely based on whether it was an oil or gas disclosure. The analysis did not separate out
reservoir factors, such as temperature, pressure, or permeability, which may be important factors for which chemicals are
used.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
1 isopropanol; quartz; sodium hydroxide; ethanol; guar gum; hydrochloric acid; and peroxydisulfuric
2 acid, diammonium salt1 These 10 chemicals are also the most frequently reported chemicals
3 nationwide.
4 By performing this analysis by state, we observed that methanol is used across the continental U.S.
5 (not Alaska), and there are 9 other chemicals that are frequently used across the U.S. Beyond those,
6 however, there are a number of different chemicals that are used in one state more commonly than
7 others and many may not be used at all in other states. This suggests that there is regional
8 variability in some chemicals and a common set of the same chemicals that are frequently used.
1 Quartz was the most commonly reported proppant and also reported as an ingredient in other additives [U.S. EPA.
20153).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 5 - Chemical Mixing
Table 5-3. The percentage of disclosures of the 20 most commonly reported chemical by state, where a chemical is reported in at
least three states.
The 20 most frequently reported chemicals were identified for all 20 states that reported to FracFocus 1.0 (U.S. EPA, 2015b). The chemicals were
ranked by counting the number of states where that chemical was in the top 20. Chemicals were then ranked so that chemicals used most widely
among the most states come first. Methanol is reported in 19 of 20 states, so methanol is ranked first. A chemical was only presented on the list if
it were reported in at least three states, resulting in 33 chemicals. The full table of top 20 chemicals (91 chemicals) is presented in Appendix C.
Chemical name
Methanol
Distillates, petroleum,
hydrotreated light
Ethylene glycol
Isopropanol
Quartz
Sodium hydroxide
Ethanol
Guargum
Hydrochloric acid
Peroxydisulfuric acid,
diammonium salt
Propargyl alcohol
Glutaraldehyde
Naphthalene
2-Butoxyethanol
CASRN
67-56-1
64742-47-8
107-21-1
67-63-0
14808-60-7
1310-73-2
64-17-5
9000-30-0
7647-01-0
7727-54-0
107-19-7
111-30-8
91-20-3
111-76-2
Percentage of disclosures per state3
AL
100%
100%
100%
100%
100%
100%
AK
45%
100%
65%
100%
100%
50%
50%
100%
AR
100%
56%
22%
44%
21%
45%
99%
61%
55%
CA
39%
55%
60%
89%
69%
93%
83%
CO
63%
74%
57%
23%
22%
50%
53%
30%
KS
79%
90%
63%
25%
23%
28%
80%
85%
22%
71%
75%
42%
LA
59%
84%
34%
51%
37%
53%
42%
49%
57%
27%
30%
36%
29%
Ml
93%
100%
71%
79%
57%
36%
86%
79%
MS
75%
100%
75%
50%
50%
100%
50%
50%
MT
63%
60%
49%
64%
64%
54%
43%
23%
62%
49%
NM
91%
63%
45%
62%
68%
30%
47%
63%
79%
75%
68%
57%
37%
ND
53%
47%
36%
37%
46%
52%
27%
55%
55%
43%
OH
52%
84%
57%
49%
45%
60%
51%
99%
64%
49%
72%
OK
70%
70%
47%
42%
27%
27%
46%
25%
76%
39%
41%
55%
25%
PA
69%
60%
34%
31%
17%
16%
23%
96%
58%
34%
21%
TX
78%
66%
59%
48%
43%
46%
21%
43%
71%
54%
39%
40%
24%
UT
79%
75%
85%
53%
40%
37%
43%
85%
39%
36%
38%
53%
VA
61%
28%
54%
63%
86%
28%
9%
89%
WV
64%
82%
59%
31%
22%
54%
23%
96%
54%
58%
71%
26%
WY
38%
51%
43%
30%
57%
25%
69%
64%
22%
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 5 - Chemical Mixing
Chemical name
Citric acid
Sodium chloride
Solvent naphtha,
petroleum, heavy
aromatics
Quaternary ammonium
compounds, benzyl-C12-
16-alkyldimethyl,
chlorides
2,2-Dibromo-3-
nitrilopropionamide
Potassium hydroxide
Acetic acid
Choline chloride
Polyethylene glycol
1,2,4-Trimethylbenzene
Ammonium chloride
CASRN
77-92-9
7647-14-5
64742-94-5
68424-85-1
10222-01-2
1310-58-3
64-19-7
67-48-1
25322-68-3
95-63-6
12125-02-9
Diatomaceous earth, 91053.39.3
calcined
Didecyl dimethyl
ammonium chloride
Sodium chlorite
Sodium erythorbate
N,N-Dimethylformamide
7173-51-5
7758-19-2
6381-77-7
68-12-2
Percentage of disclosures per state3
AL
100%
100%
AK
100%
AR
28%
21%
24%
33%
CA
71%
CO
35%
33%
49%
21%
27%
27%
28%
KS
46%
43%
54%
40%
30%
LA
41%
34%
28%
35%
Ml
71%
50%
MS
50%
50%
100%
50%
100%
MT
70%
36%
60%
36%
NM
40%
34%
38%
ND
25%
49%
59%
29%
25%
24%
OH
66%
37%
73%
38%
32%
47%
OK
36%
31%
33%
24%
20%
PA
29%
16%
34%
29%
31%
TX
24%
21%
17%
39%
31%
UT
79%
52%
35%
33%
VA
80%
9%
9%
28%
57%
9%
13%
WV
41%
22%
22%
21%
21%
32%
WY
23%
35%
31%
23%
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 5 - Chemical Mixing
Chemical name
Nonyl phenol ethoxylate
Poly(oxy-l,2-ethanediyl)-
nonylphenyl-hydroxy
(mixture)
Sodium persulfate
Tetramethylammonium
chloride
CASRN
9016-45-9
127087-87-0
7775-27-1
75-57-0
Percentage of disclosures per state3
AL
AK
AR
CA
CO
25%
KS
40%
LA
Ml
MS
100%
MT
44%
NM
30%
ND
29%
OH
OK
PA
16%
TX
UT
36%
VA
32%
9%
WV
WY
26%
26%
a Analysis considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria, including: completely parsed; unique combination of
fracture date and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet quality
assurance criteria (3,855) or other, query-specific criteria were excluded from analysis.
June 2015
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5.4.4. Volumes of Chemicals Used
1 Understanding the volume of chemicals used at each hydraulic fracturing site is important for
2 understanding potential impacts of chemicals to drinking water resources, because the chemical
3 volume governs how much will be stored on-site, the types of containers required, and the total
4 amount that could spill. While the on-site operator has precise knowledge of the composition and
5 volume of chemicals stored on-site, this information is generally not publicly available. We
6 conducted a comprehensive review of publicly available sources and found two sources [OSHA.
7 2014a. bj Sjolander et al.. 2 011 ] that identify specific chemicals used at a hydraulic fracturing site
8 and provide information on volumes. These are presented in Table 5-4. The volume of chemicals
9 totaled 7,500 gal (28,000 L) and 14,700 gal (56,000 L) for the two sources, with a mean volume for
10 an individual chemical of 1,900 gal (7,000 L) and 1,225 gal (4,600 L), respectively. The range of
11 volumes for each chemical used is 30 to 3,690 gal (114 to 14,000 L).
Table 5-4. Example list of chemicals and volumes used in hydraulic fracturing.
Volumes are for wells with and unknown number of stages and at least one perforation zone. Every
well and fluid formation is unique. Volumes may be larger for longer horizontal laterals and with a
greater number of stages.
Ingredient
Water
Proppant
Acid
Friction
reducer
Surfactant
Potassium
chloride
Gelling agent
Scale
inhibitor
Examples
Sand
Hydrochloric acid or
muriatic acid
Polyacrylamide,
mineral oil
Isopropanol
Guar gum or
hydroxymethyl
cellulose
Ethylene glycol,
alcohol, and sodium
hydroxide
Siolander et al. (2011) '
Volume (gal) or
mass (Ibs)
4,000,000 gal
~ 1,500,000 lbsd
1,338 gal
2,040 gal
e
Percent
overall
94.62
5.17
0.03
0.05
e
Occupational Safety and Health
Administration
(OSHA, 2014a, b)b
Volume (gal)
2,700,000
285,300
3,690
2,640
2,550
1,800
1,680
1,290
Percent by
volume
90
9.51
0.123
0.088
0.085
0.06
0.056
0.043
This document is a draft for review purposes only and does not constitute Agency policy.
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Ingredient
pH buffer
Preservative
Crosslinker
Iron control
Corrosion
inhibitor
Biocide/
antimicrobial
agent
Gel-breaker
Examples
Carbonate
Ammonium persulfate
Borate salts
Citric acid
n,n-Dimethyl
formamide
Glutaraldehyde,
ethanol, methanol
Ammonium persulfate
All chemicals
Chemical Volume:
Mean
(full range)
Siolander et al. (2011V
Volume (gal) or
mass (Ibs)
e
e
e
2,040 gal
e
7,458 gal
1,864.5 gal
(1,338-
2,040 gal)
Percent
overall
e
e
e
0.05
e
0.21
Occupational Safety and Health
Administration
(OSHA. 2014a. b)b
Volume (gal)
330
300
210
120
60
30
14,700
1,225
(30-3,690)
Percent by
volume
0.011
0.01
0.007
0.004
0.002
0.001
0.49
a Adapted from Penn State "Water Facts" publication entitled "Introduction to Hydrofracturing" (Siolander et al., 2011).
Composite from two companies: Range Resources, LLC, and Chesapeake Energy, which released in July 2010 the chemistry
and volume of materials typically used in their well completions and stimulations.
Adapted from a table generated by the OSHA for use in a training module (OSHA, 2014a, b).
c As presented in Siolander et al. (2011); does not explicitly state percent by mass or by volume.
d The Penn State publication presented proppant in pounds instead of gallons.
e Listed as an ingredient, but no information on volume or percentage.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Because of the limited information on chemical volumes publicly available, we estimated chemical
2 volumes used across the nation based on the information provided in the FracFocus database.
3 Figure 5-5 plots median estimated chemical volumes, ranked from high to low, with the range of 5th
4 to 95th percentiles.1 Volumes used are presented for the 74 chemicals that were reported to
5 FracFocus in at least 100 disclosures and for which density data were available.2 The estimated
6 median volumes vary widely among the different chemicals, covering a range of near zero to 27,000
7 gal (98,000 L). The mean of the estimated median volumes was 650 gal (2,500 L).3
8 With the median chemical volume, we can estimate total chemical volume for all chemicals used.
9 Based on the above mean of median chemical volumes of 650 gal (2,500 L) per chemical, and given
10 that the median number of chemicals used at a site is 14 (U.S. EPA. 2015a], an estimated 9,100 gal
1 Volumes were estimated using FracFocus disclosures. The total hydraulic fracturing fluid volume reported was used to
calculate the total fluid mass by assuming the fluid has a density of 1 g/mL. This is a simplifying assumption based on the
fact that more than 93% of disclosures are inferred to use water as a base fluid. Water had a median concentration of 88%
by mass in the fracturing fluid. Some disclosures reported using brine, which has a density between 1.0 and 1.1 g/mL.
This would introduce at most an error of 10% for the fluid calculation (the difference of a chemical being present at 10
versus 9 gal, 1,000 versus 900 gal). We also assume that the mass of chemicals present in calculating the total fluid mass
is negligible. Given that <2% of the fluid volume is non-water chemicals, and assuming the density of which is 3 mg/L, the
error introduced is approximately 6%. For reference, for the chemicals we are calculating volumes, chlorine dioxide is the
densest at 2.757 mg/L. Chemical with densities less than 1 mg/L introduce approximately <1% error.
Next, the mass of each chemical per disclosure was calculated. Each chemical is reported to FracFocus 1.0 as a maximum
concentration by mass in the hydraulic fracturing fluid. This introduces error, as we only know that it is equal to or less
than this mass fraction. In the U.S. EPA(2015a) EPA's analysis of the FracFocus 1.0 database, an additive is comprised of
three chemicals with maximum ingredient concentration of 60% in the additive and a maximum concentration of 0.22%
in the hydraulic fracturing fluid. Each of the three chemicals cannot be present at 60%. We have no way to know the
actual proportions of each chemical in the additive and thus must calculate chemical mass based on the given information.
Therefore, our calculations likely overestimate actual volumes. However, in some cases, the concentration in the additive
that is given is less than 100% and only one chemical is listed in the additive. In these cases, it appears that the disclosure
is reporting the concentration of that chemical in water. Hydrogen chloride is listed as the sole ingredient in the acid
additive, and the maximum concentration is 40% by mass. In this case, the HC1 is diluted down to 40%, so the total
volume would be underestimated.
After all the chemical masses are calculated, the volume is calculated by dividing chemical mass by density.
Given the limited information available, due to the limits of the FracFocus database and general lack of publicly available
data, and despite the errors associated with these calculations, these calculations provide context for the general
magnitude of volumes for each of the chemicals used on-site. These calculations are used to calculate median volumes for
each chemical. These volume calculations are for the chemicals themselves, not the additives.
Analysis considered 34,495 disclosures and 672,358 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28,2013; criteria for water volumes; valid CASRN; and valid concentrations. Disclosures that did not
meet quality assurance criteria (4,035) or other, query-specific criteria were excluded from analysis.
2 Density data were gathered from Reaxys® and other sources as noted. Reaxys® (http://www.elsevier.com/online-
tools/reaxys) is an online database of chemistry literature and data. Direct density source, as provided by Reaxys®, is
provided in Table C-7 in Appendix C.
3 Reporting records to FracFocus 1.0 was required in six of the 20 states between January 1,2011 and February 28,2013.
An additional three states required disclosure to either FracFocus or the state, and five states required reporting to the
state. Reporting to FracFocus 1.0 was optional in other states. Some states changed their reporting requirements during
the course of the study. The FracFocus 1.0 database therefore does not encompass all data on chemicals used in hydraulic
fracturing. As stated in Text Box 4-2, this mix of voluntary versus mandatory disclosure requirements limits the
completeness of data extracted from FracFocus 1.0 for estimating hydraulic fracturing fluid. According to a comparison
between FracFocus reported fluid volumes and literature values, water use per well was reported to be about 86% of the
actual used (median of estimated values. See Chapter 4, Text Box 4-1). If the fluid volume is underreported, then
estimated chemical volumes based on fluid volume would be similarly underestimated. Using the underreporting of 86%,
then the estimated median chemical volume would be 760 gal.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 (34,000 L) of chemicals maybe used per well. Given that the number of chemicals per well ranges
2 from 4 to 28 [U.S. EPA. 2015a], the total volume of chemicals per well may range from 2,600 to
3 18,000 gal (9,800 to 69,000 L).
4 Another way to estimate total volume of chemicals per well is to use the estimated median volume
5 of 1.5 million gal (5.7 million L) of fluid used to fracture a well (see Chapter 4) (U.S. EPA. 2015a]
6 and assume that up to 2% of that volume are chemicals added to base fluid (Carter etal., 2013:
7 Knappe and Fireline. 2012). resulting in up to 30,000 gal (114,000 L) of chemicals used per well.
100000
Median of median volumes: 21 gal
Mean of median volumes: 650 gal
Maximum of median volumes: 27,000 gal
0.01
0.001 -=-
0.0001 -=-
Figure 5-5. Estimated median volumes for chemicals reported in at least 100 FracFocus
disclosures by February 28, 2013 for use in hydraulic fracturing from
January 1, 2011 to February 28, 2013.
Shaded area represents the zone of 5% and 95% confidence limits. Derived from (U.S. EPA, 2015b).
8 Using the mean of the median chemical volumes from disclosures in FracFocus 1.0, we can also
9 estimate volume per additive and extrapolate to estimate on-site chemical storage. If we assume
10 three to five chemicals per additive, then total volume per additive stored on-site would
11 approximate 1,900 to 3,200 gal (7,400 to 12,000 L). On-site containers generally store 20% to
This document is a draft for review purposes only and does not constitute Agency policy.
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1 100% more additive volume than needed [Houston etal.. 2009: Malone and Ely. 2007]. This would
2 suggest that 2,300 to 6,500 gal (8,800 to 25,000 L) per additive are stored on-site.
3 The volume that may be released during a spill depends on where in the chemical mixing process
4 the spill occurs. Spills from chemical or additive containers may result in higher volume spills than
5 the estimated volumes in Figure 5-5 suggest However, if the spill is of the hydraulic fracturing fluid
6 downstream of the blender, then the total volume of chemical spilled may be less than the
7 estimated total volumes held on site.
5.5. Chemical Management and Spill Potential
8 This section provides a description of the primary equipment used in the chemical mixing and well
9 injection processes, along with a discussion of the spill vulnerabilities specific to each piece of
10 equipment. Equipment breakdown or failure can trigger a spill itself, and it can also lead to a
11 suspension of activity and the disconnection and reconnection of various pipes, hoses, and
12 containers. Each manipulation of equipment poses additional potential for a spill. The EPA found
13 that approximately one-third of chemical spills on or near the well pad related to hydraulic
14 fracturing resulted from equipment failure [U.S. EPA. 2015n). When possible, we describe
15 documented spills associated with or attributed to specific pieces of equipment, in text boxes in the
16 relevant subsections.
17 Hydraulic fracturing operations are mobile and must be assembled at each well site, and each
18 assembly and disassembly presents a potential for spills. Equipment used in the chemical mixing
19 and well injection processes typically consists of chemical storage trucks, oil storage tanks/tanker
20 trucks; a slurry blender; one or more high-pressure, high-volume fracturing pumps; the main
21 manifold; surface lines and hoses; and a central control unit There are many potential sources for
22 leaks and spills in this interconnected system.
23 Equipment varies in age and technological advancement depending upon service company
24 standards and costs associated with purchase and maintenance. Older equipment may have
25 experienced wear and tear, which may be a factor in spills caused by equipment failure. New
26 equipment may be more automated, reducing opportunities for human error. Information detailing
27 the extent of technological and age differences in fracturing equipment across sites and operators is
28 limited. Table 5-5 provides a description of typical hydraulic fracturing equipment.
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Table 5-5. Examples of typical hydraulic fracturing equipment and their functions.
Equipment
Acid transport truck
Chemical storage truck
Base fluid tanks
Proppant storage units
Blender
High-pressure fracturing pumps
Manifold trailer with hoses and
pipes
Fracturing wellhead or frac head
Function
Transports acids to job sites, the truck has separate compartments for
multiple acids or additives.
Transport chemicals to the site in separate containment units or totes.
Chemicals are typically stored on and pumped from the chemical storage
truck.
Store the required volume of base fluid to be used in the hydraulic fracturing
process.
Hold proppant and feed it to the blender via a large conveyor belt.
Takes fluid (e.g., water) from the fracturing tanks and proppant (e.g., sand)
from the proppant storage unit and combines them with additives before
transferring the mixture to the fracturing pumps
Pressurize mixed fluids received from the blender and injected into the well.
A transfer station for all fluids. Includes a trailer with a system of hoses and
pipes connecting the blender, the high-pressure pumps, and the fracturing
wellhead.
A wellhead connection that allows fracture equipment to be attached to the
well.
1 While the primary equipment and layout is generally the same across well sites, the type, size, and
2 number of pieces of equipment may vary depending on a number of factors [Malone and Ely. 2007]:
3 • The size and type of the fracture treatment;
4 • The number of wells drilled per well pad;
5 • The location, depth, and length of the fractures;
6 • The volumes and types of additives, proppants, and fluids used; and
7 • The operating procedures of the well operator and service company (e.g., some companies
8 require backup systems in case of mechanical failure, while others do not).
9 Figure 5-6 provides a schematic diagram of a typical layout of hydraulic fracturing equipment
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Water Tanks
/ /
III II
High Pressure Pumps
Flowback
Tanks
I
11
II
High Pressure Pumps
'' ''
Manifold
Frac
Head
> low pressure lines » high pressure lines
Figure 5-6. Typical hydraulic fracturing equipment layout.
This illustration shows how the various components of a typical hydraulic fracturing site fit together.
Numbers of pumps and tanks vary from site to site. Some sites do not use a hydration unit as the gel is
batch mixed prior to the treatment (Olson, 2011; BJ Services Company, 2009).
5.5.1. Storage
1 This section provides an overview of publicly available information on storage and containment of
2 chemicals used in the hydraulic fracturing process. Most public sources provide general
3 information on the types and sizes of containment units. While operators maintain a precise
4 inventory of volumes of chemicals stored and used for each site, this information is typically not
5 made public.
6 The volumes of each chemical used are based on the size and site-specific characteristics of each
7 fracture treatment Sites often store an excess of the design volume of chemicals for contingency
8 purposes. Malone and Ely [2007] indicate that companies typically store an excess of 20% of the
9 required chemical inventories on location. Houston etal. [2009] recommends maintaining an on-
10 site chemical reserve of 100% extra beyond what is necessary for the fracturing treatment
11 [Houston et al., 2009]. See Text Box 5-4 for documented spills from storage units.
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1
2
3
4
5
6
7
Text Box 5-4. Spills from Storage Units.
Of the 151 spills of chemicals, additives, or fracturing fluid discussed and evaluated in fU.S. EPA. 2015n) (see
Text Box 5-13 for more information), 54 spills were from storage units. Storage units include smaller totes or
tanks used for storing individual chemicals or additives, and larger tanks containing fracturing fluid. These
spills resulted from equipment failure, failure of storage integrity, or human error. Sixteen of these spills were
due to failure of container integrity, which includes holes and cracks in containers, demonstrating the need
for properly constructed and maintained storage units. The remaining spills from storage containers resulted
from human error or equipment malfunctions, or had an unknown cause.
5.5.1.1. Hydraulic Fracturing Base Fluid Storage
8 Base fluids used in hydraulic fracturing are typically stored on-site in large volume tanks. Non-
9 water-based fluids may be stored in specialized containment units designed to prevent or minimize
10 releases. For example, nitrogen and carbon dioxide must be stored in compressed gas or cryogenic
11 liquid cylinders, as required by U.S. Department of Transportation (DOT) and OSHA regulations.
12 Due to the large volume of base fluid storage tanks (about 21,000 gal (80,000 L) (Halliburton.
13 1988), uncontrolled spills could damage other storage units and equipment, which could result in
14 additional spills. Fresh water used as a base fluid is generally not a source of concern for spills.
15 Reused wastewater, brine, and non-aqueous base fluids have the potential to adversely impact
16 drinking water resources in the event of a spill. An example of a documented spill of hydraulic
17 fracturing fluid is presented in Text Box 5-5.
18
19
20
21
22
Text Box 5-5. Spills of Fracturing Fluid Documented to Impact Surface Water.
In September 2009, two spills of hydraulic fracturing fluid occurred at the same site in Pennsylvania. A total
of approximately 7,350 gal (28,000 L) of fluid comprised of a mixture of water, gel, and friction reducer
leaked and migrated to Stevens Creek. While the causes of the spills are not clear, it appears that a
pressurized line may have broken and a seal may have failed (U.S. EPA. 2015n. Appendix B Line 307:
Lustgarten. 2009).
5.5.1.2. Chemical Additive Storage
23 Additives are typically stored on-site in the containers in which they were transported and
24 delivered. The chemical additive trailer typically consists of a flatbed truck or van enclosure that
2 5 holds a number of chemical totes, described below, and is equipped with metering pumps that feed
26 chemicals to the blender. Depending on the size and type of the fracturing operation, there may be
27 one or more chemical additive trailers per site (ALL Consulting. 2012: NYSDEC. 2011). Additives
28 constitute a relatively small portion of fluids used in a hydraulic fracturing fluid, although they can
29 still be used in volumes ranging from the tens to tens of thousands of gallons.
3 0 The storage totes generally remain on the transportation trailers, but they also may be unloaded
31 from the trailers and transferred to alternative storage areas before use. Our investigation did not
3 2 find much information on how often, when, or why these transfers occur. Additional transfers and
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1 movement can increase the likelihood of a spill. See Text Box 5-6 for documented spills from an
2 additive storage unit.
Text Box 5-6. Spill from Additive (Crosslinker) Storage Tote.
3 During a tote transfer in Pennsylvania, a tote of crosslinker fell off a forklift, spilling approximately 15-20 gal
4 (60-80 L) onto the well pad. The area was scraped clean with a backhoe and placed in a lined containment
5 area fU.S. EPA. 2015n. Line 3091
6 The most commonly used chemical totes are 200-400 gal (760-1,500 L) capacity polyethylene
7 containers that may be reinforced with steel or aluminum mesh (NYSDEC. 2011]. Metal containers
8 of the same capacity may also be used (ALL Consulting. 2012: UWS. 2008). The totes are typically
9 equipped with bottom release ports, which enable the direct feed of the additives to the blending
10 equipment (NYSDEC, 2011]. Spills may occur if lines are improperly connected to these ports or if
11 the connection equipment is faulty.
Figure 5-7. Metal and high-density polyethylene (HOPE) chemical additive units.
The image on the left depicts metal totes (industry source). The image on the right depicts plastic
totes (NYSDEC, 2011).
12 Certain additives require specialized containment units with added spill prevention measures. For
13 example, additives containing methanol may be subject to federal safety standards, and industry
14 has developed guidance on methanol's safe storage and handling (Methanol Institute. 2013].
15 Dry additives are typically transported and stored on flatbed trucks in 50 or 55 Ib (23 or 25 kg]
16 bags, which are set on pallets containing 40 bags each (NYSDEC. 2011: UWS. 2008: Halliburton.
17 1988]. Proppants are stored on-site in large tanks or bins with typical capacities of 220 to 440 Ib
18 (100 to 200 kg] (ALL Consulting. 2012: BT Services Company. 2009: Halliburton. 1988].
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5.5.1.3. Acid Storage
1 Acids are generally stored on-site in the containment units in which they are transported and
2 delivered. Atypical acid transport truck holds 3,000 to 5,000 gal (11,400 to 19,000 L) of acid and
3 can have multiple compartments to hold different kinds of acid [Arthur etal.. 2009b). Acids such as
4 hydrochloric acid and formic acid are corrosive and can be extremely hazardous in concentrated
5 form. Therefore, acid transport trailers and fracture tanks must be lined with chemical-resistant
6 coating designed to prevent leakage and must meet applicable DOT regulatory standards (pursuant
7 to 40 CFR 173) designed to prevent or minimize spills.
8 Acid fracture treatments may use thousands of gallons (thousands of liters) of acid per treatment
9 (Spellman. 2012). Given the large volumes used, failure of containment vessels during storage or
10 failure of connections and hoses during pumping could result in high-volume acid spills. Eight spills
11 (out of 105 spills from state data sources) of acid or fracturing fluid containing acid were reported
12 to state data sources examined by the EPA (2015n). The median volume of these acid spills was
13 approximately 1,600 gal (6,000 L) (Lines 240, 241, 248, 258, 264, 272, 278, and 281 in Appendix B
14 of U.S. EPA(2015n)).
15 Details of a documented acid spill are presented in Text Box 5-7.
16
17
18
19
Text Box 5-7. Spill of Acid from Storage Container.
In July 2014, over 20,000 gal (76,000 L) of hydrochloric acid spilled from a storage container when a flange
malfunctioned. The acid spilled into a nearby alfalfa field, where it was contained with an emergency berm
(Phillips. 2014: Wertz. 2 0141.There is no information on how much leached into soils or if the spill reached
drinking water resources.
5.5.1.4. Gel Storage
20 Gels can be added to hydraulic fracturing fluid using either batch or continuous (also called "on-the-
21 fly") mixing systems. Gelling agents and gel slurries are stored differently on-site and may pose
2 2 different potential spill scenarios depending on whether the site is using batch or continuous
23 mixing processes (BJ Services Company. 2009).
5.5.1.5. Batch Mixing
24 In a typical batch mixing process, powdered gelling agents and related additives (e.g., buffers,
25 surfactants, biocides) are mixed on-site with base fluid water in large tanks (typically 20,000 gal or
26 76,000 L) (BJ Services Company. 2009: Halliburton. 1988).
27 The number of gel slurry tanks used varies based on site-specific conditions and the size of the
28 fracture job. These tanks may be subject to leaks or overflow during the batch mixing process and
29 during storage prior to injection. One of the disadvantages of batch mixing is the need for multiple
30 suction hoses to draw pre-gelled fluids from storage tanks into the blender, which may increase the
31 potential for spills. Yeager and Bailey (2013) state that a drawback of batch mixing is the "fluid
32 spillage and location mess encountered when pre-mixing tanks," suggesting that small spills are not
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1 uncommon during batch mixing. Details of a documented gel slurry spill are presented in Text Box
2 5-8.
3
4
5
6
Text Box 5-8. Spill of Gel during Mixing.
On April 9, 2010, a company was mixing a gel slurry for an upcoming fracture job. The tank had developed a
crack, which allowed approximately 10,000 gal (38,000 L] of water mixed with 60 gal (230 L] of gel to leak
out. The mixture did not reach a water receptor, and absorbents were used to clean up the gel (U.S. EPA.
2015n. Appendix B Line 220].
5.5.1.6. Continuous Mixing (On-the-Fly)
7 In continuous mixing operations, powdered gels are typically replaced with liquid gel concentrates
8 [Allen. 2013: BJ Services Company. 2009]. Operators prepare dilute gelling agents as needed using
9 specialized hydration units [BT Services Company, 2009]. Liquid gel concentrates may be stored on-
10 site in single-purpose tanker trucks [Harms and Yeager. 1987]. but are more often stored in
11 specialized mixing and hydration units [Ayalaetal., 2006]. Continuous mixing requires less
12 preparation than batch mixing but typically requires more equipment [BT Services Company, 2009:
13 Browne and BD, 1999], which may increase the possibility for spills resulting from equipment
14 malfunctions or human error.
5.5.2. Hoses and Lines
15 High- and low-pressure hoses and lines are used to transfer hydraulic fracturing fluids from storage
16 units to specialized mixing and pumping equipment and ultimately to the wellhead. A discussion of
17 the different types of hoses and lines and possible points of failure is provided below. The following
18 photograph shows an example of hoses and lines at a hydraulic fracturing site.
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Figure 5-8. A worker adjusts hoses at a hydraulic fracturing site near Mead, Colorado.
Source: AP Photo/Brennan Linsley.
1 Suction pumps and hoses move large volumes of base fluid to the blender. Incomplete or damaged
2 seals in inlet or outlet connections can cause fluid leaks at the connection points. Improperly fitted
3 seals also severely limit or eliminate suction lift, which may impair the suction pump and increase
4 spill potential. Suction hoses themselves are susceptible to leaks due to wear and tear. Equipment
5 providers recommend hoses be closely inspected to ensure they are in good operating condition
6 prior to use [Upstream Pumping. 2015: BJ Services Company. 2009: Malone and Ely. 2007].
7 Discharge hoses transfer additives from containment vessels or totes to the blender. Given the
8 potential for concentrated chemicals to spill during transfer from storage totes to the blender, it is
9 particularly important that these hoses are in good condition and that connector seals or washers
10 fit properly and are undamaged. Discharge hoses are also used to carry fracturing fluid pumped
11 from the blender via the low-pressure manifold to the high-pressure pumps. Proppant-heavy fluids
12 are pumped through discharge hoses at relatively low rates. If a sufficient flow rate is not
13 maintained, proppant may settle out, damaging pumps and creating potential for spills or leaks
14 [Upstream Pumping. 2015: BT Services Company. 2009: Malone and Ely. 20071.
15 High-pressure flow lines convey pressurized fluids from the high-pressure pumps into the high-
16 pressure manifold, and from the manifold into the wellbore. High-pressure flow lines are subject to
17 erosion caused by the high-velocity movement of abrasive, proppant-laden fluid. Curved sections of
18 flow lines (e.g., swivel joints) where abrasive fluids are forced to turn corners are particularly
19 subject to erosion and are more likely to develop stress cracks or other defects that may result in a
2 0 leak or spill. Safety restraints are typically used to prevent movement of flow lines in the event of
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1 failure and to help control spills. High-pressure flow lines are pressure-tested to detect fatigue or
2 stress cracks prior to the fracturing treatment [OSHA. 2015: BJ Services Company. 2009: Arthur et
3 al.. 2008: Malone and Ely. 2007: Halliburton. 19881
4 Nineteen spills of chemicals or fracturing fluids associated with leaks from hoses or lines had a total
5 spill volume of 12,756 gal (48,300 L), with a median volume of 420 gal (1,600 L) (U.S. EPA. 2015n1.
5.5.3. Blender
6 The blender is the central piece of equipment used to create the fracturing fluid for injection. It
7 moves, meters, and mixes precise amounts of the base fluid, additives, and proppant and pumps the
8 mixed slurry to high-pressure pumping equipment (BT Services Company. 2009: Malone and Ely.
9 2007: Halliburton, 1988]. A typical blender consists of a centrifugal suction pump for pulling base
10 fluid, one or more chemical metering pumps to apportion the additives, one or more proportioners
11 to measure and feed proppant, and a central agitator tank where fluid components are mixed
12 together.
13 The blending process is monitored to ensure that a uniform mixture is maintained regardless of
14 injection rates and volumes. Excessive or reduced rates of flow during treatment can cause the
15 blender to malfunction or to shut down, which may result in spills. (Malone and Ely. 2007:
16 Halliburton. 1988). For aqueous hydraulic fracturing fluid blends, spills that occur downstream of
17 the blender will be a dilute mixture comprised primarily of water with a low concentration (less
18 than or equal to 2%) of chemicals. Details of a spill from a blender are presented in Text Box 5-9.
19
20
21
Text Box 5-9. Spill of Hydraulic Fracturing Fluid from Blender.
In May 2006, a blender malfunctioned during a fracture job in Oklahoma. Approximately 294 gal (1,100 L) of
fluid spilled into a nearby wheat field. The fluid consisted of hydrochloric acid, clay stabilizer, diesel, and
friction reducer. Contaminated soil was removed by the operator (U.S. EPA. 2015n. Appendix B Line 249].
5.5.4. Manifold
22 A trailer-mounted manifold and pump system functions as a central transfer station for all fluids
23 used to fracture the well. The manifold is a collection of low- and high-pressure pipes equipped
24 with multiple fittings for connector hoses. Fluids are pumped from the blender through the low-
25 pressure manifold hoses, which distribute it to high-pressure pump trucks. Pressurized slurry is
26 sent from the pump trucks through high-pressure manifold lines and into additional high pressure
27 lines that lead to the wellhead (Malone and Ely. 2007).
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Figure 5-9. Manifold (pointed to by the white arrow).
Source: Halliburton.
1 Manifold and pump system components require varying amounts of manual assembly and undergo
2 varying amounts of pre-testing [Malone and Ely. 2007). Improperly tested parts may be more likely
3 to break or lose functionality, leading to a spill. In manifolds requiring more manual assembly, there
4 may be more opportunities for human error. The EPA [U.S. EPA, 2015n] identified seven spills
5 sourced from manifolds. Three of these spills, out of the 105 chemical or hydraulic fracturing fluid
6 spills reported to state data sources, were fracturing fluid that resulted from either human error of
7 equipment failure. These three spills were responsible for approximately 5,000 gal (19,000 L) of
8 spilled fluids (U.S. EPA. 2015n. Appendix B Lines 35.141.1601
5.5.5. High-Pressure Fracturing Pumps
9 High-pressure fracturing pumps take the fracturing fluid mixture from the blender, pressurize it,
10 and propel it down the well. Typically, multiple high-pressure, high-volume fracturing pumps are
11 needed for hydraulic fracturing [Upstream Pumping. 2015]. Such pumps come in a variety of sizes.
12 Bigger pumps move greater volumes of fluid at higher pressures; therefore, spills from these pumps
13 may be larger. Smaller pumps may require more operators and more maintenance [BT Services
14 Company. 2009). and therefore may result in more frequent spills.
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Figure 5-10. High-pressure pumps on either side of the manifold.
Source: http://drillingahead.com/roger-payne/gallery/14826/20000-psi-frac-near-
caldwelltexas-2005#gallery img.
1 The "fluid ends" of hydraulic fracturing pumps are the pump components through which fluids are
2 moved and pressurized. Pump fluid ends must withstand enormous pressure and move a large
3 volume of abrasive fluid high in solids content. They have multiple parts (e.g., seals, valves, seats
4 and springs, plungers, stay rods, studs) that can wear out under the stress of high-pressure
5 pumping [Upstream Pumping. 2015). Given the sustained pressures involved, careful maintenance
6 of fluid ends is necessary to prevent equipment failure [Upstream Pumping, 2015: API, 2011].
7 Details of a documented spill from a fracture pump are presented in Text Box 5-10.
Text Box 5-10. Spill of Fluid from Fracture Pump.
8 In December 2011, a fluid end on a fracture pump developed a leak, spilling approximately 840 gal (3,200 L)
of fracturing fluid. A vacuum truck was used to recover the spilled fluid, and all affected soils were scheduled
10 to be neutralized and taken to a landfill at the end of the job, after removal of the equipment (U.S. EPA, 2015n,
11 Appendix B Line 14).
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5.5.6. Surface Wellhead for Fracture Stimulation
1 A wellhead assembly, often referred to as a frac head or frac stack, is temporarily installed on the
2 wellhead during the fracture treatment. The frac head assembly allows high volumes of high-
3 pressure proppant-laden fluid to be injected into the formation [OSHA. 2015: Halliburton. 2014:
4 Stinger Wellhead Protection, 2010]. The temporary frac head is equipped with specialized isolation
5 tools so that the wellhead is protected from the effects of pressure and abrasion.
Figure 5-11. Multiple fracture heads.
Source: DOE/NETL
6 As with all components of hydraulic fracturing operations, repeated and prolonged stress from
7 highly pressurized, abrasive fluids may lead to equipment damage. The presence of minute holes or
8 cracks in the frac head may result in leaks when pressurized fluids are pumped. In addition, surface
9 blowouts or uncontrolled fluid releases may occur at the frac head because of valve failure or
10 failure of other components of the assembly. Details of a documented frac head failure are
11 presented in Text Box 5-11. Details on the Killdeer, ND, blowout and associated spill are presented
12 in Text Box 5-12.
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Text Box 5-11. Spill from Frac Head Failure.
1 On March 2,2011, a frac head failed during fracturing operations in Colorado. Approximately 8,400 gal
2 (32,000 L) of slickwater fracturing fluid leaked. The majority of the spill was contained on-site, though a small
3 amount ran off into a nearby cornrow. Some of the fluid was recovered, and saturated soils were scraped and
4 stockpiled on the well pad [U.S. EPA, 2015n, Appendix B Line 751.
Text Box 5-12. The Killdeer Case Study.
5 In September 2010, a blowout occurred in the Franchuk 44-20 SWH well, in Dunn County near Killdeer, ND.
6 Hydraulic fracturing fluids, oil, and flowback water spilled onto the land and possibly entered the Killdeer
7 aquifer, which is a source of drinking water. The EPA investigated a reported blowout event at the Killdeer
8 site as part of a retrospective case study. The study area is comprised of historical oil and gas production and
9 current hydraulic fracturing. The discussion below was taken from the EPA Killdeer case study [U.S. EPA.
10 2015J).
11 Methods
12 Water quality samples were collected from three domestic wells, nine monitoring wells (installed by
13 Terracon), two supply wells, one municipal well, and one state well during three rounds in July 2011, October
14 2011, and October 2012. The geochemistry of water samples was investigated by analyzing major ions, trace
15 metals, methane/ethane gas concentrations, volatile organic compounds, semivolatile organic compounds,
16 glycol ethers, diesel- and gasoline-range organics, low-molecular-weight acids, and selected stable isotopes.
17 Data collected from this study were statistically compared with historical water quality data retrieved from
18 the literature and national water quality databases. To help determine whether hydraulic fracturing
19 processes were a cause of alleged impacts on water quality, detailed environmental record searches were
20 conducted to help identify other potential contaminant sources.
21 Results
22 Three study wells, NDGW09, NDGW08, and NDGW07, were excluded from the comparisons with historical
23 data. NDGW09 was excluded since it was screened in the Sentinel Butte aquifer so a comparison with
24 historical Killdeer aquifer water quality data was not appropriate. NDGW08 and NDGW07 had significant
25 differences in water quality compared to the remaining study wells. These two wells showed differences in
26 ion concentrations (e.g., chloride, calcium, magnesium, sodium, strontium) as well as tert-butyl alcohol (TEA).
27 The remaining study wells were then compared with historical data to determine if these wells represented
28 background water quality of the Killdeer aquifer. This comparison between the remaining study wells and
29 Killdeer aquifer historical water quality data indicated that these remaining study wells were in general
30 consistent with the historical background data and then used for the data analysis as background wells. There
31 were limited detections of other organic compounds in the study wells. In most cases, with the exception
32 of TEA, the detected organic compounds could not be directly linked to the blowout or hydraulic fracturing,
33 as these chemicals could have originated from other sources including vehicular traffic, generators used to
34 power well pumps, flaring of methane from the pad production wells, and cement used to repair a well the
3 5 day prior to sampling.
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Comparisons of TEA between the study data and historical data could not be made since no historical data for
TEA were found for the Killdeer aquifer. TEA data were compared with the background study wells and were
found to be different. Based on the analysis of other potential sources of contamination, the EPA determined
that the only other potential sources of TEA were gasoline spills, leaky underground storage tanks, and
hydraulic fracturing fluids. The data from this study suggest the TEA resulted from the degradation of tert-
butyl hydroperoxide used during the hydraulic fracturing of the Franchuk well since MTBE and other
signature compounds associated with gasoline or fuels were not present in NDGW08 and NDGW07.
Conclusion
The analysis of data from NDGW008 and NDGW07 indicated that the main impact on water quality was from
briny water and TEA mixing with Killdeer aquifer water in these wells. In all cases, the fingerprinting
techniques used indicated that the impacts on NDGW07 and NDGW08 were consistent with deep formation
brines underlying the Killdeer study location. Based on the data analysis performed for the Killdeer case
study, the observed impacts on NDGW07 and NDGW08 were likely caused by the blowout that occurred at
the Franchuk 44-20. This evidence, along with the absence of another plausible candidate cause, strongly
suggests impact on a drinking water resource from the blowout during the hydraulic fracturing of the
Franchuk 44-20 SWH well.
5.6. Spill Prevention, Containment, and Mitigation
17 Several factors influence spill prevention, containment, and mitigation, including Federal, State, and
18 local regulations and company practices. State regulations governing spill prevention, containment,
19 and mitigation at hydraulic fracturing facilities vary in scope and stringency [Powell. 2013: GWPC.
20 2009]. Employee training and equipment maintenance are also factors in effective spill prevention,
21 containment, and mitigation. Analysis of these factors was outside the scope of this assessment
22 Hydraulic fracturing operating companies themselves may develop and implement spill prevention
23 and containment procedures. The American Petroleum Institute has a guidance document Practices
24 for Mitigating Surface Impacts Associated with Hydraulic Fracturing [API. 2011]. The document
25 describes practices currently used in the oil and natural gas industry to minimize potential surface
26 environmental impacts. As another example, the province of New Brunswick, Canada, released
27 rules for industry on responsible environmental management of oil and natural gas activities [GNB.
28 2013]. It was beyond the scope of this assessment to evaluate the efficacy of the practices in these
29 documents or the extent to which they are implemented.
30 Spill containment systems include primary, secondary, and emergency containment systems.
31 Primary containment systems are the storage units, such as tanks or totes, in which fluids are
32 intentionally kept Secondary containment systems, such as liners and berms installed during site
33 set-up, are intended to contain spilled fluids until they can be cleaned up. Emergency containment
34 systems, such as berms, dikes, and booms, can be implemented temporarily in response to a spill.
35 The EPA investigated spill containment and mitigation measures in an analysis of spills related to
36 hydraulic fracturing activities [U.S. EPA. 2015n]. Of the approximately 25% of reports thatincluded
37 information on containment, the most common types of containment systems referenced in the
38 hydraulic fracturing-related spill records included berms, booms, dikes, liners, and pits, though
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1 many of the spill reports did not indicate specific containment measures. Some spills were reported
2 to breach the secondary containment systems. Breaches of berms and dikes were most commonly
3 reported.
4 In cases where secondary containment systems were not present or were inadequate, operators
5 sometimes built emergency containment systems. The most common were berms, dikes, and
6 booms, but there were also instances where ditches, pits, or absorbent materials were used to
7 contain the spilled fluid. Absorbent materials were generally used when small volumes (10-200 gal
8 or 40-800 L) of additives or chemicals were spilled [U.S. EPA. 2015n]. There was not enough
9 information to detail the regularity of emergency containment systems or their effectiveness.
10 Remediation is the action taken to clean up a spill and its affected environmental media. The most
11 commonly reported remediation activity, mentioned in approximately half of the hydraulic
12 fracturing-related spill records evaluated by the EPA, was removal of spilled fluid and/or affected
13 media, typically soil [U.S. EPA. 2015n). Other remediation methods reported by the EPA [U.S. EPA.
14 2015n) included the use of absorbent material, vacuum trucks, flushing the affected area with
15 water, and neutralizing the spilled material.
5.7. Overview of Chemical Spills Data
16 Spills of hydraulic fracturing fluids have occurred across the country and have affected the quality
17 of drinking water resources fU.S. EPA. 2015n: Brantley etal.. 2014: COGCC. 2014: Gradient. 20131
18 Spills may infiltrate drinking water resources by reaching surface water, or by leaching into the
19 ground water. Potential impacts depend upon a variety of factors including the chemical spilled,
20 environmental conditions, and actions taken in response to the spill. However, due to a lack of
21 available data, little is known about the prevalence and severity of actual drinking water impacts.
5.7.1. EPA Analysis of Spills Associated with Hydraulic Fracturing
22 The EPA f2015nl (see Text Box 5-13 for additional information) evaluated 457 spills related to
23 hydraulic fracturing activities on or near the well pad. Of these spills, 151 spills were of chemicals,
24 additives, or fracturing fluids. Information in the spill reports included: spill causes (e.g., human
25 error, equipment failure), sources (e.g., storage tank, hose or line), volumes, and environmental
26 receptors.
27
28
29
30
31
32
33
34
Text Box 5-13. EPA Review of State and Industry Spill Data: Characterization of Hydraulic
Fracturing-Related Spills.
The EPA [2015n] used data gathered from select state and industry sources to characterize hydraulic
fracturing-related spills with respect to volumes spilled, materials spilled, sources, causes, environmental
receptors, containment, and responses. For the purposes of the study, hydraulic fracturing-related spills were
denned as those occurring on or near the well pad before or during the injection of hydraulic fracturing fluids
or during the post-injection recovery of fluids. Because the main focus of this study is to identify hydraulic
fracturing-related spills on the well pad that may reach surface or ground water resources, the following
topics were not included in the scope of this project: transportation-related spills, drilling mud spills, and
spills associated with disposal through underground injection control wells.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 Data on spills that occurred between January 2006 and April 2012 were obtained from nine states with
2 online spill databases or other data sources, nine hydraulic fracturing service companies, and nine oil and gas
3 production well operators. The data sources used in this study contained over 36,000 spills. The EPA
4 searched each spill report for keywords related to hydraulic fracturing (e.g., frac, glycol, flowback). Spill
5 records from approximately 12,000 spills (33 percent of the total number of spills reviewed) contained
6 insufficient information to determine whether the event was related to hydraulic fracturing. Of the spills with
7 sufficient information, the EPA identified approximately 24,000 spills (66%) as not related to hydraulic
8 fracturing on or near the well pad. The remaining 457 spills (approximately 1%) occurred on or near the well
9 pad and were definitively related to hydraulic fracturing. These 457 spills occurred in 11 different states over
10 six years (January 2006 and April 2 012).
11 The EPA categorized spills according to the following causes: equipment failure, human error,
12 failure of container integrity, other (e.g., well communication, weather, vandalism), and unknown.
13 Figure 5-12 presents the percent distribution of chemical or fracturing fluid spills associated with
14 each cause. Over half of the spills were collectively caused by equipment failure (34%) and human
15 error (25%). Approximately one-quarter of the spill causes were unknown or not reported. A
16 report analyzing spills in Colorado is generally consistent with the EPA's findings (COGCC. 2014).*
17 Colorado found that equipment failure was the dominant spill cause, accounting for over 60% of
18 spills between 2010 and 2013, followed by human error accounting for 20%-25% of spills.
1 The COGCC report included all materials related to oil and gas production and were therefore not specific to chemical
and fracturing fluid spills.
This document is a draft for review purposes only and does not constitute Agency policy.
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Equipment failure
I Failure of container integrity
i Human error
I Unknown
I Other
Figure 5-12. Distribution of the causes of 151 hydraulic fracturing-related spills of chemicals
and fracturing fluid.
Data from U.S. EPA(2015n).
1 Spills in the EPA Spills Report were also categorized by the following sources: storage, equipment,
2 well or wellhead, hose or line, and unknown. Figure 5-13 presents the percent distribution for the
3 chemical or fracturing fluid spills associated with each source. Storage units (e.g., chemical totes,
4 fracturing fluid tanks) were the predominant source of spills, accounting for 36% (54 spills) of spill
5 sources. Spills from storage units were predominantly caused by human error (39%), followed by
6 failure of container integrity (30%). Spills from equipment were the next most common known
7 source (18%), followed by spills from hoses or lines (13%). Twenty-eight percent of spills had an
8 unknown source.
This document is a draft for review purposes only and does not constitute Agency policy.
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i Equipment
I Hose or line
iStorage
I Well or wellhead
•Unknown
Figure 5-13. Percent distribution of sources of 151 hydraulic fracturing-related spills of
chemicals or fracturing fluid.
Data from U.S. EPA(2015n).
1 The reported total volume of 125 of 151 chemical or hydraulic fracturing fluid spills was
2 approximately 184,000 gal (697,000 L). The volume was unknown for 26 of these spills. The spills
3 ranged in volume from 5 to more than 19,000 gal (19 to 72,000 L), with a median volume of 420 gal
4 (1,600 L). The largest source of spills was storage containers, which released approximately 83,000
5 gal (314,000 L) of spilled fluid. Spills from wells or wellheads are often associated with high spill
6 volumes. Nine instances of spills at the well or wellhead were associated with approximately
7 46,000 gal (174,000 L) of spilled fluid (see Figure 5-14). The high pressure associated with frac
8 head blowouts has led to large, high-volume spills (see Text Box 5-11).
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90,000
80,000
70,000
T3
= 60,000
'5,
in
2 50,000
53
'o 40,000
in
S3 30,000
co
20,000
10,000
0
Equipment Hose or line Storage Well or wellhead
Source of spill
Unknown
Figure 5-14. Total volume of fluids spilled for 151 hydraulic fracturing-related spills of
chemicals and fracturing fluid, by spill source.
Data from U.S. EPA(2015n).
1 Figure 5-15 presents the number of chemical or fracturing fluid spills that reached environmental
2 receptors, by receptor type. Environmental receptors (i.e., surface water, ground water, soil) were
3 identified for 101 of the 151 spills, or 67% of the spills in the EPA's analysis fU.S. EPA. 2015rQ. Soil
4 was by far the dominant environmental receptor, with 97 spills reaching soil. Thirteen spill reports
5 indicated that the spilled fluid had reached surface water. Nine spill reports identified both soil and
6 surface water as a receptor. No spill report identified ground water as a receptor. The data contain
7 few post-spill analyses, so ground water contamination may have occurred but have not been
8 identified. Additionally, several years may be required for a spilled fluid to leach into the ground
9 water and therefore impact on a ground water receptor may not be immediately apparent Storage
10 units were the predominant sources of spills reaching an environmental receptor.
This document is a draft for review purposes only and does not constitute Agency policy.
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120
100
80
60
40
20
Surface Water Ground Water
Environmental Receptor
• Yes • Unknown No
Figure 5-15. Number of hydraulic fracturing-related spills of chemicals or fracturing fluid that
reported whether an environmental receptor was reached.
"Unknown" refers to hydraulic fracturing related spill events for which environmental receptors were
specified as unknown or not identified (positively or negatively).
Data from U.S. EPA(2015n).
1 Six spills from storage containers reached a surface water receptor. Thirty-eight of the spills from
2 storage units reached a soil receptor. If a spill was confined to a lined well pad, for example, it might
3 not have reached the soil, but most incident reports did not include whether the well pad was lined
4 or unlined. Regarding spills of hydraulic fluids and chemicals from storage containers, 16 spills
5 were due to failure of container integrity, which includes holes and cracks in containers, and
6 overflowing containers as a result of human error or equipment malfunctions.
7 The EPA analysis demonstrates that spills of chemicals, additives, and fracturing fluids do occur at
8 well sites and reach both soil and surface water receptors.
5.7.2. Other Spill Reports
9 Surface spills related to hydraulic fracturing activities are not well documented in the scientific
10 literature, though some evidence of spills and impacts to environmental media exists (e.g., U.S. EPA.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 20151: Brantley etal.. 2014: Gross etal.. 2013: Papoulias and Velasco. 20131. For example,
2 Papoulias and Velasco [2013] demonstrated that fracturing fluid spilled into surface water likely
3 contributed to the distress and deaths of the threatened blackside dace fish in Kentucky. A variety
4 of chemicals entered the creek and significantly reduced the stream's pH and increased stream
5 conductivity. Using data from post-spill sampling reports in Colorado, Gross etal. [2013] identified
6 concentrations of benzene, toluene, ethylbenzene, and xylene in ground water samples, which the
7 authors attributed to numerous hydraulic fracturing-related spills. The COGCC [2014] published a
8 report analyzing all spills reported to the state of Colorado between 2010 and 2013, and found that
9 approximately 8% of them were related to hydraulic fracturing. Based on the EPA's analyses [U.S.
10 EPA, 2015n] and available scientific data, we estimate spill rates of chemicals and hydraulic
11 fracturing fluid range from 0.4 and 12.2 spills for every 100 wells. (See Text Box 5-14 for additional
12 information.]
Text Box 5-14. Spill Rates.
13 Several studies have estimated the frequency of hydraulic fracturing-related spills. Three studies [Rahm et al..
14 2015: Brantley et al.. 2014: Gradient. 2013] calculated a spill rate for the Marcellus Shale in Pennsylvania
15 using reports from the Pennsylvania Department of Environmental Protection (PA DEP] Oil and Gas
16 Compliance Report Database, and here we estimate an on-site spill rate for Colorado. The PA DEP database
17 provides a searchable format based on Notices of Violations from routine inspections or investigations of spill
18 reports or complaints. Each study had different criteria for inclusion, presented in Table 5-6, resulting in a
19 range of rates even when using the same data source. Spills of hydraulic fracturing fluids, flowback/produced
20 water are estimated to occur at a rate of 0.4 per 100 wells fractured. Spills related to hydraulic fracturing
21 activity are estimated to occur at a rate between 3.3 to 12.2 spills per 100 wells installed (PA DEP data] (see
22 Table 5-6].
23 In its study of spills related to hydraulic fracturing, the EPA determined that spill reports from the Colorado
24 Oil and Gas Conservation Commission (COGCC] Information System were the most detailed spill reports from
25 among the nine state data sources investigated and generally provided more of the information needed to
26 determine whether a spill was related to hydraulic fracturing (U.S. EPA. 2015n]. Here, we estimate the spill
27 rate in Colorado by dividing the number of hydraulic fracturing-related spills identified by the EPA (U.S. EPA.
28 2015n. Appendix B](Appendix B in U.S. EPA, 2015b] by the number of wells hydraulically fractured in
29 Colorado for specific time periods between January 2006 and April 2012. We used three data sources to
30 estimate the number of wells: (1] there were 172 reported spills in Colorado for the 15,000 wells fractured
31 from January 2006 to April 2012 (Drillmglnfo.2012]. (2] there were 50 reported spills in Colorado for the
32 3,559 wells fractured from January 2011 to April 2012 (U.S. EPA. 2015b]. and (3] there were 41 reported
33 spills in Colorado for the 3,000 wells fractured from September 2009 to October 2010 (U.S. EPA. 2013a].
34 From these data we estimate an average of 1.3 reported spills on or near the well pad for every 100
3 5 hydraulically fractured wells.
36
This document is a draft for review purposes only and does not constitute Agency policy.
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Table 5-6. Estimations of spill rates.
Spill rates from four different sources. Each source used different criteria to identify and include spills
in their analysis.
Spill rate3
0.4
3.3
12.2
1.3
Data source
PADEPb
Media
PADEPb
PADEPb
COGCCC
Time period
2008-2013
2009-2012
2007-July 2013
Jan 2006-
May 2012
Inclusion criteria
Volume spilled
> 400 gal;
Spill reported to reach
water body.
"Unconventional"
well;
Spills with unknown
volumes not included,
Includes any spill
during HF activities
"Unconventional" well
based on
environmental
violation rates.
Specifically related to
hydraulic fracturing on
or near well pad
Information source
Brantley et al. (2014)d
Gradient (2013)e
Rahm et al. (2015)e
U.S. EPA(2013a)d
aSpill rate is the number of reported spills per 100 wells.
PA DEP (http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx7/Oil Gas/
OG Compliance)
CCOGCC (https://cogcc.state.co. us/cogis/lncidentSearch.asp)
Spill rate is calculated as the number of spills per 100 wells fractured.
eSpill rate is calculated as the number of spills per 100 wells installed.
This document is a draft for review purposes only and does not constitute Agency policy.
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Text Box 5-14 (Spill Rates), continued:
1 The spill rates presented in Table 5-6 are based on spill reports found in two state data sources and are
2 limited by both the spills reported in the state data sources and the inclusion criteria defined by each of the
3 studies. Spills identified from state data sources are likely a subset of the total number of spills that occurred
4 within a state for a specified time period. Some spills may not be recorded in state data sources because they
5 do not meet the spill reporting requirements in place at the time of the spill. Additionally, the PA DEP Notices
6 of Violation may include spills not specifically related to hydraulic fracturing, such as spills of drilling fluids.
7 The inclusion criteria used by each of the studies affects which spills are used to calculate a spill rate. More
8 restrictive criteria, such as only counting spills that were greater than 400 gallons, results in a lower number
9 of spills being used for estimating spill rates, while less restrictive criteria, such as all spills from wells
10 marked unconventional in the PA DEP database, results in a greater number of spills being used for
11 estimating spill rates. Rahm etal. applied the least restrictive criteria of the four studies (i.e., spills from
12 unconventional wells) when identifying spills, while Brantley et al. applied more restrictive criteria (i.e., spills
13 of >400 gallons in which spilled fluids reached a surface water body). This may account for the different spill
14 rates calculated by these two studies.
15 Based on previous studies and the analysis here, hydraulic fracturing-related spills rates in Pennsylvania and
16 Colorado range from 0.4 and 12.2 per 100 wells. These numbers may not be representative of national spill
17 rates or rates in other regions. If this range is applied nationally however, assuming between 25,000 and
18 30,000 wells are fractured each year, we would expect between approximately 100 and 3,700 spills annually
19 from hydraulic fracturing.
5.8. Fate and Transport of Chemicals
2 0 This section provides an overview of fate and transport of the range of chemicals used in hydraulic
21 fracturing fluid, including the physicochemical properties of these chemicals, and an overview of
2 2 the potential for a spilled chemical to affect drinking water resources. A general overview of the
23 processes governing the fate and transport of a chemical spill is shown in Figure 5-16. A chemical
24 spill has the potential to migrate to and have an impact on drinking water resources. Once spilled,
25 there are different paths that chemicals can travel and different processes they may undergo.
26 Chemicals may react and transform into other chemicals, volatilize, travel to surface water, leach
27 into and partition to soils, and/or reach ground water. The potential path and the severity of the
28 impact of a spill depend on different factors, including the site conditions; environmental
29 conditions; climate; weather; and chemical properties, concentration, and volume of the release.
30 The point in the chemical mixing process where the spill occurs affects potential impact If the spill
31 occurs before chemicals are mixed into the base fluid, the chemicals will spill in their most
32 concentrated form. If the hydraulic fracturing fluid spills, then the chemicals will be more diluted,
33 and there may be effects on persistence and mobility due to interactions among chemicals present
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Schematic of the Fate and Transport Processes
Governing Potential Impacts of Spills to
Drinking Water Resources
Figure 5-16. Fate and transport schematic for a spilled hydraulic fracturing fluid.
Schematic shows the potential paths and governing processes that spilled chemicals, which may lead
to potential impacts to drinking water resources.
1 For inorganic chemicals, the properties and processes governing fate and transport depend on pH,
2 oxidation state, presence of iron oxides, soil organic matter, cation exchange capacity, and major ion
3 chemistry [U.S. EPA. 1996).* Transport of these chemicals into ground water depends on the nature
4 of ground water flow and flow through the unsaturated zone above the water table. Potential
5 transformations of inorganic chemicals differ from those of organic chemicals.2 Some inorganic
6 anions (i.e., nitrate, chloride, and bromide) move with their carrier liquid and are affected mostly by
7 physical transport mechanisms. For many inorganic chemicals, transport is driven by the physical
8 flow processes (advection and dispersion), sorption, and precipitation. The relative role of each of
9 these depends on both chemical and environmental characteristics.3'4
10 Determining the fate and transport of organic chemicals and mixtures is a complex problem,
11 because of the many processes and different environmental media (air, soil, water) that can have an
1 Cation exchange capacity is the total amount of cations (positively charged ions) that a soil can hold. For example, when
metal ions like Ca2+ and Na+ pass through the soil, they adhere and remain attached to the soil.
2 The unsaturated zone is also referred to as the vadose zone. Meaning "dry," the vadose zone is the soil zone above the
water table that is only partially filled by water, hence "unsaturated zone."
3 Advection is a mechanism for moving chemicals in flowing water, where a chemical moves along with the flow of the
water itself.
4 Sorption is the general term used to describe the partitioning of a chemical between soil and water and depends on the
nature of the solids and the properties of the chemical.
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1 impact Unlike inorganic chemicals, organic chemicals degrade, which may affect their movement
2 and potential impact. Schwarzenbach etal. [2002] formalized a general framework for organic
3 chemical transport, where transport and transformation depend on both the nature of the chemical
4 and the properties of the environment. The fate and transport of organic compounds in soils has
5 been presented in the literature (e.g., Bouchard etal., 2011: Rivettetal., 2011: Abriola and Finder,
6 1985a. b] and in textbooks [e.g.. Domenico and Schwartz. 1997: Schnoor. 1996: Freeze and Cherry,
7 19791.
5.8.1. Potential Paths
8 Chemicals, additives, and hydraulic fracturing fluids that are released into the environment travel
9 along different potential paths, as detailed in Figure 5-16. Liquids may flow overland to nearby
10 surface water or infiltrate the subsurface, where they may eventually reach the underlying ground
11 water or travel laterally to reach surface water. Movement can occur quickly or be delayed and
12 have a later or longer-term impact. Surface water and ground water gain or lose flow to each other,
13 and may transport chemicals in the process.
14 A dry chemical (e.g., gelling agents, biocides, friction reducers) released to the environment will
15 generally remain where it is spilled. Any spill that is not removed could act as a long-term source of
16 contamination. Wind could cause the chemical to disperse, or rain could dissolve a soluble chemical.
17 Dissolved chemicals may infiltrate into soil or flow overland. Insoluble chemicals and those sorbed
18 to soil particles could be mobilized by rain events via runoff and erosion.
5.8.1.1. Movement across the Land Surface
19 In low permeability soils, there may be little infiltration and greater overland flow. Higher
20 permeability soils will allow fluid to penetrate into the soil layer. In either case, some of the
21 chemicals in the fluid may sorb to the soil particles and the vegetation, and then these chemicals
22 may be mobilized during rainfall, runoff, or erosion. As rainwater percolates through the soil, it may
23 dissolve stored chemicals, which can then migrate toward ground water.
24 The type of release is also important. If the spill is a slow leak, then the liquid may pond and the
25 affected area will expand slowly. If a more rapid release occurs, like a blowout or tank failure, then
26 momentum may result in greater overland movement and less soil infiltration during the event
5.8.1.2. Movement through the Subsurface
27 The unsaturated and saturated zones are the two zones of soils below the ground surface.
28 Movement through the unsaturated zone is driven by the depth of ponding of the spilled fluid,
29 gravity, and capillary properties of the subsurface.1 In fractured rock or highly permeable soils,
3 0 fluids may move quickly through the subsurface. In low permeability soil, the movement of the fluid
31 is slower. As chemicals pass through the subsurface, some may sorb to soil or remain in the open
3 2 spaces between soil particles, effectively slowing their movement. Chemicals may again be
1 Capillarity occurs because of the forces of attraction of water molecules to themselves (cohesion) and to other solid
substances such as soils (adhesion).
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1 mobilized during future precipitation events, resulting in infiltration towards ground water or
2 movement through the unsaturated zone towards surface water.
3 Fluids that move through the subsurface into the saturated zone will move in the direction of the
4 flowing ground water. Generally, fluids travel further in systems with high ground water flow rates
5 and high recharge (e.g., sandy aquifers in humid climates) than in systems with low flow and low
6 recharge. Chemicals may sorb to suspended soil particles or complex with naturally occurring
7 chemicals (e.g., dissolved organic carbon) and be transported with the flowing water.1 These
8 mechanisms can mobilize sparingly soluble chemicals that would otherwise be immobile.
5.8.2. Physicochemical Properties
9 Three physicochemical properties are useful to describe the movement of chemicals in the
10 environment: (1) Kow, the octanol-water partition coefficient, (2) the aqueous solubility, and (3) the
11 Henry's law constant.2 These properties describe whether a chemical will sorb to soil and organic
12 matter or stay in water (Kow), how much of a chemical may dissolve in water (aqueous solubility),
13 and whether a chemical will tend to remain in the water or volatilize (Henry's law constant).3
14 The Kow measures the relative hydrophobicity (chemical prefers to be in oil, log Kow >0) and
15 hydrophilicity (chemical prefers to be in water, log Kow <0) of a chemical. Aqueous solubility is the
16 maximum amount of a chemical that will dissolve in water in the presence of a pure chemical;
17 solubility generally serves as an upper bound on possible concentrations. The Henry's law constant
18 is the ratio of the concentration of a chemical in air (or vapor pressure) to the concentration of that
19 chemical in water.
20 Estimates and measured values for physicochemical properties were obtained by using the
21 Estimation Program Interface Suite 4.1 (see Appendix C).4 Of the 1,076 chemicals the EPA listed as
22 used in hydraulic fracturing (see Appendix A), EPI Suite™ has estimated properties for 453 (42%).
23 EPI Suite™ does not have data available for the remaining 58% of the chemicals. The 453 chemicals
24 with physicochemical property data were chemicals with structures that are considered suitably
25 representative of the substance to compute properties within the constraints of EPI Suite™
26 software. Only unique defined organic desalted structures were submitted for property calculation.
27 Figure 5-17 presents histograms of all 453 of the chemicals, sorted by four physicochemical
28 parameters: measured log Kow (n = 247, 23%), estimated log ftow(n=45 3, 42%) estimated log of the
1 Complexation is a reaction between two chemicals that form a new complex, either through covalent bonding or ionic
forces. This often results in one chemical solubilizingthe other.
2 The octanol-water partition coefficient (Kow) represents the ratio of the solubility of a compound in octanol (a nonpolar
solvent) to its solubility in water (a polar solvent) in a mixture of the two. The higher the Kow, the more nonpolar the
compound.
3 We present the physicochemical parameter values using logio because of the wide range of values that these parameters
cover.
4 EPI Suite™, version 4.1, http://www.epa.gov/opptintr/exposure/pubs/episuite.htm [U.S. EPA. 2012b). The EPI
(Estimation Programs Interface) Suite™ is a Windows®-based suite of physicochemical property and environmental fate
estimation programs developed by the EPA Office of Pollution Prevention and Toxics and Syracuse Research Corporation.
EPI Suite™ provides estimates of physicochemical properties for organic chemicals and has a database of measured values
for physicochemical properties when available. EPI Suite™ cannot estimate parameters for inorganic chemicals.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 aqueous solubility (n = 453, 42%), and estimated log of Henry's law constant (at 25°C, n = 453,
2 42%).
, Most mobile
Least nobj|e
50
40
30
20
10
-10 -8 -6 -4 -2 0 2 4 6 8 10
Measured log KOB,|L/kg]
LOO
_. Most mobile
Least mobile .
80
£ 40
I
20
0 - i
-25 -20 -15 -10 -5 0 5 10 15 20 25
Estimated log X,,,,, [L/kg]
Least soluble
Most soluble
I Mi
Stays in water
Readily escapes to air
-20 -15 -10 -5 0 5 10 15 20
Estimated log Solubility [mg/L @ 25C]
-50 -40 -30 -20 -10 -0 10 20 30 40 50
Estimated log Henry's Law Constant [atm mj mole'1 @ 25C]
Figure 5-17. Histograms of physicochemical properties of chemicals used in the hydraulic
fracturing process.
Measured values of log Kow (upper left). Estimated physicochemical properties for log Kow (upper
right), log Solubility (lower left), and log Henry's law constant (lower right) for all chemicals.
Physicochemical properties (log Kow, solubility, and Henry's Law constant) estimated by EPI Suite™.
3 The EPA also used EPI Suite™ to determine the physicochemical properties for 19 chemicals
4 provided to the EPA as confidential business information (CBI) (See Text Box 5-3 for discussion on
5 CBI).1 The CBI chemical physicochemical properties are plotted as histograms in Figure 5-18. The
6 values of the physicochemical properties of known and CBI chemicals are similar, covering similar
7 ranges centered on similar values, suggesting that even though these chemicals are not publicly
8 known, their physicochemical properties are not appreciably different from the known chemicals.
9 This means that their fate and transport would not be appreciably different than the chemicals that
10 are publicly known.
1 Well operators may specify certain ingredients as confidential business information (CBI) and not disclose the chemicals
used to FracFocus. The CASRNs of a range of CBI chemicals were provided to USEPAby 9 service companies.
This document is a draft for review purposes only and does not constitute Agency policy.
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3.5
3
S'
ii 2.5
c
I 2
I 1.5
* 1
0.5
. Most mobile
Least mobile ,
Least mobile
I I
J
_ 3
T 2
I-
-505
Measured log K0[v[L/kg]
-.
7 '
_ 6
oi
7 5
c
T 4
A
E 3
2 2
I
Least Soluble
-20 -15 -10 -5 0 5 10 15 20
Estimated log Solubility [mg/L 2SC]
Most Soluble ^ Stays in water
J '! iL
°25 -20 -15 -10 -5 0 5 10 15 20
Estimated log Kolv[L/kg]
Readily escapes to air
-50 -40 -30 -20 -10 0 10 20 30 40 50
Estimated log Henry's Law Constant [atm m* mole -1 @ 25C]
Figure 5-18. Histograms of physicochemical properties of confidential chemicals used in the
hydraulic fracturing process.
Source: (U.S. EPA, 2013a)
Measured values of log Kow (upper left). Estimated physicochemical properties for log Kow (upper
right), log solubility (lower left), and log Henry's law constant (lower right) for all chemicals.
Physicochemical properties (log Kow, solubility, and Henry's Law constant) estimated by EPI Suite™.
5.8.3. Mobility of Chemicals
1 Figure 5-17 shows the distribution of the three properties. The log Kow distribution demonstrates
2 that the chemicals cover a wide range from the more mobile to the less mobile. The more
3 hydrophilic chemicals are more mobile (i.e., they move with water). The more hydrophobic
4 chemicals tend to associate with organic matter and soil particles and to be less mobile in the
5 environment, and they may serve as long-term sources of contamination. A large number of the
6 chemicals fall near log Kow = 0, which indicates that these chemicals are likely to associate roughly
7 equally with organic or aqueous phases. However, overall the log Kow values are skewed positively,
8 indicating less mobile chemicals, which may result in their being later-term or long-term sources of
9 impact to drinking water. The log S values span a wide range from fully miscible to sparingly
10 soluble. Many of the chemicals have high aqueous solubilities, with a large number being fully
11 miscible. Most of the chemicals have log Henry's law constants less than 0, indicating that most are
12 not volatile. Once these chemicals dissolve into water they will tend to stay there rather than
13 volatilize. Therefore, volatilization does not generally serve as a loss process for most hydraulic
14 fracturing chemicals.
15 Table 5-7 and Table 5-8 present the 20 most mobile and least mobile chemicals, known to be used
16 in hydraulic fracturing fluids, respectively, as ranked by log Kow. These were taken from the list of
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
1 515 chemicals with estimated values for physicochemical properties. These tables also include
2 values for aqueous solubility and Henry's law constant, as well as frequency of use, based on
3 FracFocus disclosures fU.S. EPA. 2015a).
4 Table 5-7 shows the chemicals that have the lowest log Kow and are, thus, the most mobile. These
5 chemicals are fully miscible (i.e., they will mix completely with water), which means they may move
6 through the environment at high concentrations, leading to greater severity of impact These
7 chemicals generally have low volatility, based on their negative log Henry's law constants (i.e., will
8 remain in water and will not be lost to the air). These chemicals will dissolve in water and move
9 rapidly through the environment (e.g., via infiltration into the subsurface or via overland flow to
10 surface waters). Chemicals exhibiting this combination of properties have greater potential to cause
11 immediate impacts to drinking water resources. Most of the chemicals in the table were
12 infrequently reported (<2% of wells) in FracFocus (U.S. EPA. 2015a). However, choline chloride
13 (14% of wells), used for clay control, and tetrakis(hydroxymethyl)phosphonium sulfate (11% of
14 wells), a biocide, were more commonly reported.
Table 5-7. Ranking of the 20 most mobile organic chemicals, as determined by the largest log
Kow, with CASRN, percent of wells where the chemical is reported from January 1,
2011 to February 28, 2013 (U.S. EPA, 2015b), and physicochemical properties (log
Kow, solubility, and Henry's Law constant) as estimated by EPI Suite™.
(U.S. EPA, 2015b)
For organic salts, parameters are estimated using the desalted form.
Rank
1
2
3
Chemical Name
1,2-Ethanediaminium, N,N'-bis[2-
[bis(2-hydroxyethyl)methylammo
nio]ethyl]-N,N'-bis(2-hydroxyeth
yl)-N,N'-dimethyl-, tetrachloride
Phosphonic acid,
[[(phosphonomethyl)imino]bis
[2,1-ethanediylnitrilobis
(methylene)]]tetrakis-
Phosphonicacid,
[[(phosphonomethyl)imino]bis
[2,1-ethanediylnitrilobis
(methylene)]]tetrakis-, sodium
salt
CASRN
138879-94-4
15827-60-8
22042-96-2
Percent of
wells
(U.S. EPA,
2015b)a
2%
0.2%
0.07%
Estimated
Log Kow
(unitless)b
-23.19
-9.72
-9.72
Estimated
Water
Solubility
(mg/L@
25°C)C
1.00 x 10s
1.00 x 10s
1.00 x 10s
Estimated
Henry's Law
Constant
(atm mVmole
@ 25°C)d
2.33 x 10"35
NA
NA
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Hydraulic Fracturing Drinking Water Assessment
Rank
4
5
6
7
8
9
10
11
12
13
14
15
16
Chemical Name
Phosphonic acid,
[[(phosphonomethyl)imino]bis
[2,1-ethanediylnitrilobis
(methylene)]]tetrakis-,
ammonium salt (l:x)
Phosphonic acid, (((2-[(2-
hydroxyethyl)(phosphonomethyl)
amino)ethyl)imino]bis(methylene
))bis-, compd. with 2-
aminoethanol
2-Hydroxy-N,N-bis(2-
hydroxyethyl)-N-
methylethanaminium chloride
N-(3-Chloroallyl)hexaminium
chloride
3,5,7-Triazatricyclo(3.3.1.1
(superscript 3,7))decane, l-(3-
chloro-2-propenyl)-, chloride, (Z)-
(2,3-dihydroxypropyl)
trimethylammonium chloride
Phosphonic acid,
[[(phosphonomethyl)imino]bis
[6,1-hexanediylnitrilobis
(methylene)]]tetrakis-
[Nitrilotris(methylene)]tris-
phosphonic acid pentasodium salt
Aminotrimethylene phosphonic
acid
Choline chloride
Choline bicarbonate
alpha-Lactose monohydrate
Lactose
CASRN
70714-66-8
129828-36-0
7006-59-9
4080-31-3
51229-78-8
34004-36-9
34690-00-1
2235-43-0
6419-19-8
67-48-1
78-73-9
5989-81-1
63-42-3
Percent of
wells
(U.S. EPA,
2015b)a
NA
NA
NA
0.02%
NA
NA
0.006%
0.5%
2%
14%
0.2%
NA
NA
Estimated
Log Kow
(unitless)b
-9.72
-6.73
-6.7
-5.92
-5.92
-5.8
-5.79
-5.45
-5.45
-5.16
-5.16
-5.12
-5.12
Estimated
Water
Solubility
(mg/L@
25°C)C
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
Estimated
Henry's Law
Constant
(atm ms/mole
@ 25°C)d
NA
5.29 x 10"42
4.78 x 10"19
1.76 x 10"8
1.76 x 10"8
9.84 x 10"18
NA
1.65 x 10"34
1.65 x 10"34
2.03 x 10"16
2.03 x 10"16
4.47 x 10"22
4.47 x 10"22
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Rank
17
18
19
20
Chemical Name
Tetrakis(hydroxymethyl)phospho
nium sulfate
Disodium
ethylenediaminediacetate
Nitrilotriacetamide
l,3,5-Triazine-l,3,5(2H,4H,6H)-
triethanol
CASRN
55566-30-8
38011-25-5
4862-18-4
4719-04-4
Percent of
wells
(U.S. EPA,
2015b)a
11%
0.6%
NA
0.2%
Estimated
Log Kow
(unitless)b
-5.03
-4.79
-4.75
-4.67
Estimated
Water
Solubility
(mg/L@
25°C)C
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
Estimated
Henry's Law
Constant
(atm mVmole
@ 25°C)d
9.17 x 10"13
l.lOxlO"16
1.61 x 10"18
1.08 x 10"11
a Some of the chemicals in these tables have NA (not available) listed as the number of wells, which means that these
chemicals have been used in hydraulic fracturing, but they were not reported to FracFocus program for the time period of the
study (January 1, 2011, to February 28, 2013) (U.S. EPA. 2015b). Analysis considered 34,675 disclosures and 676,376
ingredient records that met selected quality assurance criteria, including: completely parsed; unique combination of fracture
date and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid
concentrations. Disclosures that did not meet quality assurance criteria (3,855) or other, query-specific criteria were excluded
from analysis.
b Log Kow is estimated using the KOWWIN™ model, which uses an atom/fragment contribution method.
c Water solubility is estimated using the WSKOWWIN™ model, which estimates a chemical's solubility from Kow and any
applicable correction factors.
Henry's Law constant is estimated using the HENRYWIN™ model using the bond contribution method.
1 Table 5-8 shows the chemicals that have the highest log Kow and are, thus, the least mobile. The
2 estimated aqueous solubilities for some of these chemicals are extremely low, with highest
3 solubilities of <10 [ig/L. Therefore, the concentration of these chemicals dissolved in water will be
4 low. The estimated Henry's law constants are more variable for these low-mobility chemicals.
5 Chemicals with high log Kow values (>0) and high Henry's law constants will sorb strongly to organic
6 phases and solids and may volatilize. However, their strong preference for the organic or solid
7 phase may slow or reduce volatilization. The chemicals with low Henry's law constants will readily
8 sorb to organic phases and solids. Less mobile chemicals will move slowly through the soil and have
9 potentially delayed and longer-term impacts to drinking water resources. Seven of the chemicals in
10 Table 5-8 were reported to FracFocus [U.S. EPA. 2015b]. Five were reported infrequently (<1% of
11 wells). Tri-n-butyltetradecylphosphonium chloride (6% of wells), used as a biocide, and
12 OlO-alpha-alkenes (8% of wells), a mixture of alpha-olefins with carbon numbers greater than 10
13 used as a corrosion inhibitor, were more commonly reported. The least mobile organic chemical is
This document is a draft for review purposes only and does not constitute Agency policy.
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1 sorbitan, tri-(9Z)-9-octadecenoate, a mineral oil co-emulsifier (0.05% of wells), with an estimated
2 log Kow of 22.56.1
Table 5-8. Ranking of the 20 least mobile organic chemicals, as determined by the largest log
KOW, with CASRN, percent of wells where the chemical is reported from January 1,
2011 to February 28, 2013 (U.S. EPA, 2015b), and physicochemical properties (log
Kow, solubility, and Henry's Law constant) as estimated by EPI Suite™.
Source: (U.S. EPA, 2015b)
For organic salts, parameters are estimated using the desalted form.
Rank
1
2
3
4
5
6
7
8
9
10
11
12
Chemical Name
Sorbitan, tri-(9Z)-
9 octadecenoate
Fatty acids, C18-unsatd.,
dimers
Sorbitan sesquioleate
Tri-n-butyltetradecyl-
phosphonium chloride
Sodium bis(tridecyl)
sulfobutanedioate
1-Eicosene
D&C Red 28
C.I. Solvent Red 26
1-Octadecene
Alkenes, C>10 alpha-
Dioctyl phthalate
Benzene, C10-16-alkyl derivs.
CASRN
26266-58-0
61788-89-4
8007-43-0
81741-28-8
2673-22-5
3452-07-1
18472-87-2
4477-79-6
112-88-9
64743-02-8
117-84-0
68648-87-3
Percent of
wells
(U.S. EPA,
2015b)a
0.05%
NA
0.02%
6%
NA
NA
NA
NA
NA
8%
NA
0.5%
Estimated
Log Kow
(unitless)b
22.56
14.6
14.32
11.22
11.15
10.03
9.62
9.27
9.04
8.55
8.54
8.43
Estimated
Water
Solubility
(mg/L@
25°C)C
1.12 x 10"19
2.31 x 10'10
2.31 x 10"11
7.90 x 10"7
7.46 x 10"9
1.26 x 10"5
1.64 x 10"8
5.68 x 10"5
1.256 x 10"4
3.941 x 10"4
4.236 x 10"4
2.099 x 10"4
Estimated
Henry's Law
Constant
(atm m /
mole @
25°C)d
4.02 x 10"11
4.12xlO"08
7.55 x 10"12
2.61 x 10"1
8.51 x 10"11
1.89 x 101
6.37 x 10"21
5.48 x 10"13
1.07 x 101
8.09 x 10°
1.18xlO"5
1.78 x 10"1
1 Sorbitan, tri-(9Z)-9-octadecenoate, CASRN 26266-58-0, is soluble in hydrocarbons and insoluble in water, listed as an
effective coupling agent and co-emulsifier for mineral oil [Santa Cruz Biotechnology. 2015: ChemicalBook. 2010).
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Rank
13
14
15
16
17
18
19
20
Chemical Name
Di(2-ethylhexyl) phthalate
1-Octadecanamine, N,N-
dimethyl-
N,N-dimethyloctadecylamine
hydrochloride
Butyryl trihexyl citrate
1-Hexadecene
Benzo(g,h,i)perylene
Dodecylbenzene
Isopropanolamine
dodecylbenzene
CASRN
117-81-7
124-28-7
1613-17-8
82469-79-2
629-73-2
191-24-2
123-01-3
42504-46-1
Percent of
wells
(U.S. EPA,
2015b)a
NA
NA
NA
0.03%
NA
NA
NA
0.02%
Estimated
Log Kow
(unitless)b
8.39
8.39
8.39
8.21
8.06
7.98
7.94
7.94
Estimated
Water
Solubility
(mg/L@
25°C)C
1.132 x 10"3
8.882 x 10"3
8.882 x 10"3
5.56 x 10"5
1.232 x 10"3
7.321 x 10"4
1.015 x 10"3
1.015 x 10"3
Estimated
Henry's Law
Constant
(atm m3/
mole @
25°C)d
1.18xlO"5
4.51 x 10"3
4.51 x 10"3
3.65 x 10"9
6.10x10°
1.26 x 10"2
1.34 x 10"1
1.34 x 10"1
a Some of the chemicals in these tables have NA (not available) listed as the number of wells, which means that these
chemicals have been used in hydraulic fracturing, but they were not reported to FracFocus program for the time period of
the study (January 1, 2011, to February 28, 2013) (U.S. EPA, 2015b). Analysis considered 34,675 disclosures and 676,376
ingredient records that met selected quality assurance criteria, including: completely parsed; unique combination of fracture
date and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid
concentrations. Disclosures that did not meet quality assurance criteria (3,855) or other, query-specific criteria were
excluded from analysis.
b Log Kow is estimated using the KOWWIN™ model, which uses an atom/fragment contribution method.
c Water solubility is estimated using the WSKOWWIN™ model, which estimates a chemical's solubility from Kow and any
applicable correction factors.
Henry's Law constant is estimated using the HENRYWIN™ model using the bond contribution method.
1 Table 5-9 shows the EPI Suite™ estimated physicochemical property values of the 20 chemicals
2 most frequently reported to FracFocus nationwide, with estimated mean and median volumes
3 based on FracFocus data. Most have log Kow < 1, meaning that they are generally hydrophilic and
4 will associate with water. These chemicals also have very high solubilities, so they will be mobile in
5 the environment and go where the water goes. These chemicals have the potential for immediate
6 impacts to drinking water resources. Naphthalene has a measured log Kow = 3.3 with an estimated
7 solubility of 142.1 mg/L, which means it will be less mobile in the environment. Naphthalene will
8 sorb to particles and move slowly through the environment, and have the potential to act as long-
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1 term sources of contamination.1 All of these chemicals have low Henry's law constants, so they tend
2 not to volatilize.
1 Chemicals may have the potential to be long-term sources of contamination because they move slowly through the
environment. In this discussion, we are not accounting for biodegradation or other transformation processes, which may
reduce the persistence of certain chemicals in the environment. Under the right conditions, for example, naphthalene is
biodegradable, which may reduce or remove it from the environment, and thus may not be a long-term source of
contamination.
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Chapter 5 - Chemical Mixing
Table 5-9. The 20 chemicals reported most frequently nationwide for hydraulic fracturing based on reported FracFocus 1.0
disclosures (U.S. EPA, 2015b), with EPI Suite™ physicochemical parameters where available, and estimated mean and
median volumes of those chemicals, where density was available.
Source: (U.S. EPA, 2015b)
Excludes water, sodium chloride, and quartz. NA means that the physicochemical parameter is not provided by EPI Suite™. For organic salts,
parameters are estimated using the desalted form.
Rank
1
2
3
4
5
6
7
8
9
10
11
Chemical Name
Methanol
Distillates, petroleum,
hyd retreated light
Hydrochloric acid
Isopropanol
Ethylene glycol
Peroxydisulfuric acid,
diammonium salt
Sodium hydroxide
Guargum
Glutaraldehyde
Propargyl alcohol
Potassium hydroxide
CASRN
67-56-1
64742-47-8
7647-01-0
67-63-0
107-21-1
7727-54-0
1310-73-2
9000-30-0
111-30-8
107-19-7
1310-58-3
Number Of
Wells Using
Chemical
(% of wells)
24,753 (72%)
22,463 (65%)
22,380 (65%)
16,039 (47%)
15,800 (46%)
14,968 (44%)
13,265 (39%)
12,696 (37%)
11,562 (34%)
11,410 (33%)
10,049 (29%)
Log Kow (unitless)
Estimated
-0.63
NA
NA
0.28
-1.2
NA
NA
NA
-0.18
-0.42
NA
Measured
-0.77
NA
NA
0.05
-1.36
NA
NA
NA
NA
-0.38
NA
Water
Solubility
Estimate From
Log Kow
(mg/L @ 25°C)
1.00 x 106
NA
NA
4.024 x 105
1.00 x 106
NA
NA
NA
1.672 x 105
9.355 x 105
NA
Henry's Law Constant
(atm mVmole @ 25°C)
Estimated,
Bond
Method
4.27 x 10"6
NA
NA
7.52 x 10"6
1.31 x 10"7
NA
NA
NA
1.10 x 10"7
5.88 x 10"7
NA
Estimated,
Group
Method 25
3.62 x 10"6
NA
NA
1.14xlO"5
5.60 x 10"11
NA
NA
NA
2.39 x 10"s
NA
NA
Measured
4.55 x 10"6
NA
NA
S.lOxlO"6
6.00 x 10"s
NA
NA
NA
NA
1.15 x 10"6
NA
Estimated Volume,
per disclosure
(gal)
Mean
1,218
NA
28,320
2,095
614
NA
551
NA
1,313
183
NA
Median
110
NA
3,110
55
184
NA
38
NA
122
2
NA
June 2015
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Chapter 5 - Chemical Mixing
Rank
12
13
14
15
16
17
18
19
20
Chemical Name
Ethanol
Acetic acid
Citric acid
2-Butoxyethanol
Solvent naphtha,
petroleum, heavy
arom.
Naphthalene
2,2-Dibromo-3-
nitrilopropionamide
Phenolic resin
Choline chloride
CASRN
64-17-5
64-19-7
77-92-9
111-76-2
64742-94-5
91-20-3
10222-01-2
9003-35-4
67-48-1
M U /"**
Wells Using
Chemical
(% of wells)
9,861 (29%)
8,186 (24%)
8,142 (24%)
7,347 (21%)
7,108 (21%)
6,354 (19%)
5,656 (16%)
4,961 (14%)
4,741 (14%)
Log Kow (unitless)
Estimated
-0.14
0.09
-1.67
0.57
NA
3.17
1.01
NA
-5.16
Measured
-0.31
-0.17
-1.64
0.83
NA
3.3
0.82
NA
NA
Water
Solubility
Estimate From
Log Kow
(mg/L @ 25°C)
7.921 x 105
4.759 x 105
1.00 x 106
6.447 x 104
NA
1.421 x 102
2.841 x 103
NA
1.00 x 106
Henry's Law Constant
(atm mVmole @ 25°C)
Estimated,
Bond
Method
5.67 x 10"6
5.48 x 10"7
8.33 x 10"1S
9.79 x 10"s
NA
5.26 x 10"4
6.16xlO"14
NA
2.03 x 10"16
Estimated,
Group
Method 25
4.88 x 10"6
2.94 x 10"7
NA
2.08 x 10"s
NA
3.7 x 10"4
NA
NA
NA
Measured
5.00E-06
1.00 x 10"7
4.33 x 10"14
1.60 x 10"6
NA
4.4 x 10"4
1.91 x 10"s
NA
NA
Estimated Volume,
per disclosure
(gal)
Mean
831
646
163
385
NA
72
183
NA
2,131
Median
121
47
20
26
NA
12
5
NA
290
Note: Analysis considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria, including: completely parsed; unique combination of
fracture date and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet quality
assurance criteria (3,855) or other, query-specific criteria were excluded from analysis.
June 2015
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5.8.4. Transformation Processes
1 It is important to understand the processes governing transformation of chemicals in the
2 environment The transformation of a chemical reduces its concentration over time. Chemicals may
3 completely degrade before reaching a drinking water resource. Transformation processes may be
4 biotic or abiotic. The transformation process may transform a chemical into a less or more harmful
5 chemical.
6 Biodegradation is a biotic process where microorganisms transform a chemical from its original
7 form into another chemical. For example, the biodegradation pathway of methanol is
8 CH3OH^ CH20 -^ CHOOH -^ C02, or methanol -^ formaldehyde -^ formic acid -^ carbon dioxide.
9 This pathway shows how the original chemical transforms through a series of steps until it becomes
10 the final product, carbon dioxide. Some chemicals are readily biodegraded, while others break
11 down slowly over time. Biodegradation is a highly site-specific process, requiring nutrients, a
12 carbon source, water, and an energy source. A highly biodegradable chemical could be persistent if
13 the conditions for biodegradability are not met. Conversely, a highly biodegradable chemical could
14 biodegrade quickly under the right conditions, before it can impact a water resource. The
15 relationship between mobility and biodegradability is complex, and therefore a variety of factors
16 can influence a particular compound's movement through the environment
17 Abiotic processes, such as oxidation, reduction, photochemical reaction, and hydrolysis, can
18 transform or break apart chemicals. In hydrolysis, for example, a water molecule substitutes for a
19 group of atoms. The typical results are products that are more polar than the original, and thus
20 have different physicochemical properties than the original compounds [Schwarzenbach et al.,
21 2002).1
5.8.5. Fate and Transport of Chemical Mixtures
2 2 Chemicals at hydraulic fracturing sites are often present as mixtures, which may act differently in
23 the environment than individual chemicals do. Individual chemicals can affect the fate and
24 transport of other chemicals in a mixture primarily by changing their solubility and biodegradation
25 rates.
26 Mixtures of chemicals may be more mobile than individual chemicals due to cosolvency, which
27 increases solubility in the aqueous phase. Methanol and ethanol are examples of cosolvent alcohols
28 used frequently in hydraulic fracturing fluids [U.S. EPA. 2015aj. The presence of either greatly
29 increases BTEX solubility [Rasa etal.. 2013: Corseuil etal.. 2011: Heermann and Powers. 19981.2 By
30 increasing solubility, ethanol can affect the fate and transport of other compounds. For example,
i A polar molecule is a molecule with a slightly positive charge at one part of the molecule and a slightly negative charge
on another. The water molecule, HzO, is an example of a polar molecule, where the molecule is slightly positive around the
hydrogen atoms and negative around the oxygen atom.
2 BTEX is an acronym for benzene, toluene, ethylbenzene, and xylenes. These chemicals are a group of single ringed
aromatic hydrocarbons based on the benzene structure. These compounds are found in petroleum and are of specific
importance because of their potential health effects.
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1 BTEX has been observed to travel farther in the subsurface in the presence of ethanol [Rasaetal.,
2 2013: Corseuiletal..2011: Corseuiletal.. 2004: Powers etal.. 2001: Heermann and Powers. 1998].
3 The presence of surfactants lowers fluid surface tension and increases solubility of organic
4 compounds, and can mobilize less soluble/less mobile organic compounds. Two common
5 surfactants reported to FracFocus 1.0 from January 1, 2011 to February 2013 were 2-
6 butoxyethanol (CASRN 111-76-2, 21% of disclosures) and poly(oxy-l,2-ethanediyl)-nonylphenyl-
7 hydroxy (mixture) (CASRN 127087-87-0, 20% of disclosures). Additionally, surfactants can
8 mobilize bacteria in the subsurface, which can increase the impact of pathogens on drinking water
9 resources (Brown and Jaffe. 2001).
10 When chemicals are present as mixtures, one chemical may decrease or enhance the
11 biodegradability of another through inhibition or co-metabolism. The process of inhibition can
12 occur when multiple chemicals compete for the same enzyme, so only one chemical is degraded at a
13 time, which can ultimately slow biodegradation of each of the chemicals present. For example, the
14 biodegradation of ethanol and methanol may inhibit the biodegradation of BTEX or other organic
15 compounds present (Rasaetal.. 2013: Powers et al.. 2001). Co-metabolism may increase the
16 biodegradation rate of other compounds. For example, when methane or propane is present with
17 tetrachloroethylene, the enzyme produced by bacteria to degrade methane also degrades
18 tetrachloroethylene (e.g., Alvarez-Cohen and Speitel, 2001 and references therein). For the
19 purposes of chemicals used in hydraulic fracturing, the presence of other chemicals in additives and
20 hydraulic fracturing fluids could result in increased or decreased biodegradation if the chemicals
21 are spilled. A chemical that may have otherwise been biodegradable may be inhibited and act as a
22 long-term source.
5.8.6. Site and Environmental Conditions
2 3 Environmental conditions at and around the spill site affect the movement and transformation of
24 the chemical. We discuss the following: site conditions (e.g., proximity, land cover, and slope), soil
25 conditions (e.g., permeability and porosity), and weather and climate.
26 The proximity of a spill to a drinking water resource, either laterally in the case of a surface water
2 7 body or downward for an aquifer, affects the potential for impact. Land cover will affect how
28 readily a fluid moves over land. For example, more rugged land cover such as forest will impede
29 flow, and an asphalt road will facilitate flow. A spill that occurs on or near a sloped site may move
30 overland faster, making it more likely to reach a nearby surface water body. Flatter surfaces would
31 result in a greater chance for infiltration to the subsurface, which could increase the potential for a
32 ground water impact.
33 Soil characteristics that affect the transport and transformation of spill chemicals include soil
34 texture (e.g., clay, silt, sand), permeability, porosity, and organic content.1'1 Fluids will move more
1 Permeability of a soil describes how easily a fluid can move through the soil. Under a constant pressure, a fluid will move
faster in a high permeability soil than the same fluid in a low permeability soil.
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1 quickly through permeable soil (e.g., sand) than through less permeable soil (e.g., clay). A soil with a
2 high porosity provides more volume to hold water and spilled chemicals. Another important factor
3 for a site is the organic content, of which there are two competing types: soil organic carbon and
4 dissolved organic carbon. Each type of carbon acts as a strong substance for chemicals to adhere to.
5 Soil organic carbon present in a solid phase, such as dead and decaying leaves and roots, is not
6 mobile and slows the movement of chemicals through the soil. Dissolved organic carbon (DOC)
7 moves with the water and can act as a shuttling mechanism to move insoluble chemicals across the
8 surface and through the subsurface. Chemicals may also associate with particulates and colloids,
9 which may act as an important transport mechanism.
10 Weather and climate conditions also affect the fate and transport of a spilled chemical. After a
11 spilled chemical stops moving, rainfall may remobilize the chemical. The amount, frequency, and
12 intensity of precipitation will impact volume, distance, and speed of chemical movement.
13 Precipitation may carry chemicals downward or overland, and it can cause erosion, which may
14 move sorbed chemicals overland.
5.8.7. Peer-Reviewed Literature on the Fate and Transport of Hydraulic Fracturing Fluid Spills
15 There has been limited peer-reviewed research investigating the fate and transport of chemicals
16 spilled at hydraulic fracturing sites. Aminto and Olson (2012) modeled a hypothetical spill of
17 1,000 gal (3,800 L) of hydraulic fracturing fluid using equilibrium partitioning. The authors
18 evaluated how 12 chemicals typically used for hydraulic fracturing in the Marcellus Shale would
19 partition amongst different phases: air, water, soil, and biota.2 They presented a ranking of
20 concentrations for each phase. In water, they showed that sodium hydroxide (a pH buffer), 4,4-
21 dimethyl oxazolidine (a biocide), hydrochloric acid (a perforation clean-up additive), and 3,4,4-
22 trimethyl oxazolidine (a biocide) had the highest simulated water concentrations; however, these
23 concentrations depended on the chemicals included in the simulated mixture and the
24 concentrations of each. Their analysis also suggested that after a spill, a large fraction would enter
25 the air and leave the soil; however, some constituents would be left behind in the water, soil, and
26 biota compartments, which could effectively act as long-term contamination sources. Aminto and
27 Olson (2012) only studied this one scenario. Other scenarios could be constructed with different
28 chemicals in different concentrations. These scenarios may result in different outcomes with
29 greater impacts.
5.8.8. Potential and Documented Fate and Transport of Documented Spills
30 There is limited information on the fate and transport of hydraulic fracturing fluids and chemicals.
31 In this section, we highlight the potential and documented impacts for three documented spills (U.S.
32 EPA. 2015n). In each case, we provide the documented and potential paths (surface, subsurface, or
33 combination) and the associated fate and transport governing processes by which a spill has been
i Porosity of a soil describes the amount of empty space for a given volume of soil. The porosity describes how much air,
water, or hydraulic fluid a given volume of soil can hold.
2 The chemicals they investigated included: sodium hydroxide, ethylene glycol, 4,4-dimethyl oxazolidine, 3,4,4-trimethyl
oxazolodine, 2-amino-2-methyl-l-propanol, formamide, glutaraldehyde, benzalkonium chloride, ethanol, hydrochloric
acid, methanol, and propargyl alcohol.
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1 documented to or has the potential to have an impact on drinking water resources. The three cases
2 involve a tank overflow with a surface water impact, a human error blender spill with a soil impact,
3 and an equipment failure that had no impact These three spills were chosen to highlight cases
4 where there was a documented impact, a potential impact, and no impact.
5 In the first documented spill, shown in Figure 5-19, a tank overflowed twice, releasing a total of
6 7,350 gal (980 ft3 or 28 m3).1 The spilled fluid was documented as containing a friction reducer and
7 gel. The spill traveled across the land surface, crossed a road, and then continued to a nearby
8 stream. The spill affected wetlands and a stream, where fish were killed. The fish kill indicates that
9 the chemicals present were in high enough concentrations to have an adverse impact.
Tank overflow spill with documented impact to surface water:
2 spills, 7,350 gal fluid: water, friction reducer, gel
Documented Impact:
Fluid reached wetlands and creek
Fish stressed and killed
Figure 5-19. Fate and Transport Spill Example: Case 1.
Spills information from U.S. EPA(2015n).
10 For this first spill, the documented path was overland flow from the tank to the stream with a
11 documented, immediate impact. In addition to this documented path, there are potential paths for
12 potential impacts to drinking water resources. The spilled chemicals may have penetrated into the
13 soils or sorbed to soils and vegetation as the fluid moved across the ground towards the stream.
1 We provide the total volume of the spill in gallons as well as cubic length (cubic feet and cubic meters), because it may be
a little harder to visualize how far a volume of 7,300 gal might travel.
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1 Chemicals could be mobilized during later rainfall, runoff, or erosion events. Chemicals that
2 infiltrated the subsurface could serve as long-term sources, as well as travel laterally across the
3 unsaturated zone, or continue downwards to the ground water. Additionally, some chemicals could
4 be lost to transformation processes. The lack of reported soil or ground water sampling data
5 prevents the ability to know if these potential paths occurred or not.
6 The second documented spill [U.S. EPA, 2015n, line 144], shown in Figure 5-20, occurred when a
7 cap was left off the blender, and 504 gal (70 ft3 or 2 m3) of biocide and hydraulic fracturing fluid
8 were released; 294 gal (39 ft3 or 1.1 m3) were retained by a dike with a lined secondary
9 containment measure, demonstrating the partial effectiveness of this containment mechanism.
10 However, 210 gal (28 ft3 or 0.8 m3) did run off-site and were vacuumed up. There was no
11 documented impact to surface or ground water.
Cap left off of blender; biocide and water spill
504 gal spilled: 294 gal caught by dike, 210 gal ran off-site
Figure 5-20. Fate and Transport Spill Example: Case 2.
Spills information from U.S. EPA(2015n).
12 In this second case, the uncontained 210 gal could have infiltrated the subsurface, creating a
13 potential path to ground water. There is no documented information on the composition of the
14 spilled fluid. Highly mobile chemicals would have penetrated the soil more quickly than less mobile
15 chemicals, which would have sorbed to soil particles. As the chemicals penetrated into the soil,
16 some could have moved laterally in the unsaturated zone, or traveled downward to the water table
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1 and moved with the ground water. These chemicals could have served as a long-term source. These
2 chemicals could have transformed into other chemicals with different physicochemical properties,
3 and any volatile chemicals could have moved to the air as a loss process. As in the first case, there
4 was no reported sampling of soil or groundwater, so there is no way to demonstrate whether
5 chemicals did or did not follow this path.
6 In the third documented spill [U.S. EPA. 2015n. line 188], shown in Figure 5-21, 630 gal (84 ft3 or
7 2.4 m3) of crosslinker spilled onto the well pad when a hose wore off at the cuff. The spill was
8 contained in the berm and an on-site vacuum truck was used to clean up the spill. No impact to soil
9 or water was reported.
Hose worn at cuff of blender; crosslinker spill
630 gal spilled onto pad. Prevented infiltration
of fluid into soil.
Equipment failure:
Hose worn off
Onsite vac-truck
remediated spill
Figure 5-21. Fate and Transport Spill Example: Case 3.
Spills information from U.S. EPA(2015n).
10 For this third case, we do not have any information on whether the well pad was lined or not. If the
11 site had a liner, the spill could have been fully contained, not infiltrated the subsurface, and been
12 fully cleaned up. Without a liner or if the liner was not completely successful (e.g., had a tear), the
13 potential paths would have been similar to those above in the second case, where the chemicals
14 may sorb to the soils and penetrate into the subsurface. There was no reported sampling of soil or
15 ground water to determine whether or not chemicals migrated into the soil.
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5.9. Trends in Chemicals Use in Hydraulic Fracturing
1 This section provides an overview of ongoing changes in chemical use in hydraulic fracturing, with
2 an emphasis on efforts to reduce potential impacts from surface spills by using fewer and safer
3 chemicals.
4 Representatives from oil and gas companies, chemical companies, and non-profits are working on
5 strategies to reduce the number and volume of chemicals used and to identify safer chemicals
6 [Waldron, 2014]. Southwestern Energy Company, for example, is developing an internal chemical
7 ranking tool [SWN, 2014], and Baker Hughes is working on a hazard ranking system designed for
8 wide-scale external use [Baker Hughes, 2014a: Brannonetal., 2012: Daultonetal., 2012: Brannon
9 etal.. 2011]. Environmental groups, such as the Environmental Defense Fund, are also developing
10 hazard rating systems [Penttilaetal.. 2013]. Typical criteria used to rank chemicals include
11 mobility, persistence, biodegradation, bioaccumulation, toxicity, and hazard characteristics. In this
12 report, toxicity and a methodology to rank chemical hazards of hydraulic fracturing chemicals is
13 discussed in Chapter 9.
14 The EPA has not conducted a comprehensive review of efforts to develop safer hydraulic fracturing
15 chemicals. However, the following are some specific examples of efforts that companies cite as part
16 of their efforts toward safer chemical use:
17 • A renewable citrus-based replacement for conventional surfactants [Fisher, 2012]:
18 • A crosslinked gel system comprised of chemicals designated as safe food additives by the
19 U.S. Food and Drug Administration (Holtsclawetal.. 20111:
20 • A polymer-free gel additive fAl-Ghazal etal.. 20131:
21 • A dry, hydrocarbon-free powder to replace liquid gel concentrate [Weinstein et al., 2009]:
22 • Biodegradable polymers [Irwin, 2013]:
23 • The use of ultraviolet light to control bacteria [Rodveltetal., 2013]:
24 • New chelating agents that reduce the use of strong acids [LePage etal., 2013], and
25 • The recovery and reuse of flowback and produced water as hydraulic fracturing fluids,
26 which may reduce need to add additional chemicals [Horn etal.. 2013].
27 In addition to efforts to address environmental concerns, the oil and gas industry continues to
2 8 research and develop less expensive and more effective fracturing fluid additives. A review of the
29 EPA's new chemicals program found that from 2009 to April 2015, the Agency received pre-
30 manufacturing notices (PMN] for about 110 chemicals that have the potential for use as hydraulic
31 fracturing fluid additives. Examples include chemicals intended for use as clay control agents,
32 corrosion inhibitors, gel crosslinkers, emulsifiers, foaming agents, hydrate inhibitors, scale
33 inhibitors, and surfactants. At the time of PMN submission, these chemicals were not in commercial
34 use in the United States. As of April 2015, the EPA had received 30 notices of commencement,
35 indicating that some of those chemicals are now used commercially.
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1 The FracFocus 1.0 data extracted by the EPA cannot be used to identify temporal trends in additive
2 usage. A data set with a much longer duration of data collection would be needed to distinguish
3 actual temporal trends from the normal diversity of chemicals in use as a result of geologic and
4 geographic variability. However, the current FracFocus 1.0 database provides a point of comparison
5 for use in the future.
S.lO.Synthesis
6 Chemical mixing is the process by which a base fluid, chemicals, and proppant are mixed prior to
7 injection into the well. This chapter addressed the potential for on-site spills of chemicals used in
8 the hydraulic fracturing process to affect the quality of drinking water resources, which is governed
9 by three overarching factors: (1) fluid characteristics, (2) chemical management and spill
10 characteristics, and (3) chemical fate and transport.
5.10.1. Summary of Findings
11 Documented on-site chemical spills have occurred during the chemical mixing process and reached
12 soil and surface water receptors, with potential impacts to drinking water resources. The EPA
13 analysis of 497 spills reports found no documented impacts to ground water from those particular
14 chemical spills, though there was little information on post-spill testing and sampling [U.S. EPA,
15 2015n). The EPA's case study in Killdeer, ND strongly suggests that there was impact to ground
16 water, but it is unclear if the path was via the surface spill caused by the blowout [U.S. EPA. 2015)].
17 The EPA found 151 spills of chemicals or fracturing fluid on or near the well pad in a six-year time
18 period. The chemical spills were primarily caused by equipment failure (34%), closely followed by
19 human error (25%). The remaining spills were caused by a failure of container integrity, weather,
20 vandalism, well communication, or unknown causes. Reported spills cover a large range of volumes,
21 from five to 19,000 gal (19 to 72,000 L), with a median of 420 gal (1,700 L).
22 If a spilled fluid reaches a drinking water resource, the potential to affect the water quality is largely
23 governed by the fluid characteristics. A typical water-based fracturing fluid is composed of 90%-
24 94% water, 5%-9% proppant, and less than 2% chemical additives (Carter etal., 2013: Knappe and
25 Fireline. 2012). According to the EPA's analysis of disclosures to FracFocus 1.0, approximately 93%
26 of hydraulic fracturing fluids are inferred to use water as a base fluid (U.S. EPA, 2015a). Non-
27 aqueous constituents, such as nitrogen, carbon dioxide, and hydrocarbons, are also used as base
28 fluids or used in combination with water as base fluids.
29 The EPA has identified 1,076 unique chemicals used in hydraulic fracturing fluids. The chemicals
30 include acids, aromatic hydrocarbons, bases, hydrocarbon mixtures, polysaccharides, and
31 surfactants. Of the 1,076 chemicals, 453 have physicochemical properties in the EPI Suite™
32 database. These chemicals range from fully miscible to insoluble, and from highly hydrophobic to
33 highly hydrophilic. The majority of the chemicals are not volatile.
34 According to the EPA's analysis of FracFocus, a median of 14 chemicals are used per well, with a
35 range of four to 28 (5th and 95th percentiles). The volumes used range from tens to tens of
36 thousands of gallons (tens to tens of thousands of liters) per well; therefore, operators typically
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1 store chemicals on-site in large volumes (typically 200 to 400 gal (760-1,500 L) totes), often in
2 multiple containers. The ten most common chemicals (excluding quartz) are methanol,
3 hydrotreated light petroleum distillates, hydrochloric acid, isopropanol, ethylene glycol,
4 peroxydisulfuric acid diammonium salt, sodium hydroxide, guar gum, glutaraldehyde, and
5 propargyl alcohol. These chemicals are present in multiple additives. Methanol was reported in
6 72% of the FracFocus disclosures, and hydrotreated light petroleum distillates and hydrochloric
7 acid were both reported in over half the disclosures (U.S. EPA. 2015b).
5.10.2. Factors Affecting the Frequency or Severity of Impacts
8 The potential for spills from the chemical mixing process to affect drinking water resources
9 depends on three factors: fluid characteristics, chemical management and spill characteristics, and
10 chemical fate and transport. Specific factors affecting the frequency and severity of impacts include
11 size and type of spill, volume of chemicals spilled, type of chemicals and their properties,
12 combinations of chemicals spilled, environmental conditions, proximity to drinking water
13 resources, employee training and experience, quality and maintenance of equipment, and spill
14 containment and mitigation.
15 The size and type of a fracturing operation, including the number of wellheads, the depth of the
16 well, the length of the horizontal leg, and the number of stages and phases, affect the likelihood and
17 potential impacts of spills. Larger operations may require larger volumes of chemicals, more
18 storage containers, more equipment, and additional transfers between different pieces of
19 equipment. Larger storage containers increase the maximum volume of a spill or leak from a
20 storage container, and additional transfers between equipment increase the possibility of human
21 error.
22 The type of chemical spilled governs how it will move and transform in the environment More
23 mobile chemicals move faster through the environment, causing a quicker impact More mobile
24 chemicals are also generally more soluble and may reach the drinking water resource at higher
25 concentrations. Less mobile chemicals will move more slowly, and may have delayed and longer-
26 term impacts, at lower concentrations. The severity of impact is also governed by how the chemical
27 adversely impacts water quality. Water quality impacts may range from aesthetic effects (e.g., taste,
28 smell) to adverse health effects.
29 The environmental conditions at and around the spill site affect the fate and transport of a given
30 chemical. These conditions include soil properties, climate, weather, and terrain. Permeable soils
31 may allow for rapid transport of the spilled fluid through the soil and into a nearby drinking water
32 resource. Precipitation can re-mobilize trapped chemicals and move them over land or through the
33 subsurface.
34 The proximity of a spill to drinking water resources affects the frequency and severity of impact
35 The closer a spill is to a drinking water a resource, the higher potential to reach it Also, as a fluid
36 moves toward a drinking water resource, it may decrease in concentration, which will affect the
37 severity of an impact. More concentrated chemicals have the potential to have a bigger impact on
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1 water quality. The characteristics of the drinking water resource will also influence the magnitude
2 of the impact of a spill.
3 The most successful way to prevent impacts to drinking water resources is to prevent spills from
4 occurring in the first place and to quickly and effectively contain spills. Effective spill containment
5 and mitigation measures can prevent or reduce the frequency and severity of impacts. Spill
6 containment measures include well pad containment liners, diversion ditches, berms, dikes,
7 overflow prevention devices, drip pans, and secondary containers. These may prevent a spill from
8 reaching soil and water receptors. Spill mitigation, including removing contaminated soils,
9 vacuuming up spilled fluids, and using sorbent materials may limit the severity of a spill.
10 Implementation of these measures varies from site-to-site and may not always be effective.
5.10.3. Uncertainties
11 The lack of information regarding the composition of chemical additives and fracturing fluids,
12 containment and mitigation measures in use, and the fate and transport of spilled fluids greatly
13 limits our ability to assess potential impacts to drinking water resources.
14 There is no standard design for hydraulic fracturing fluids. Detailed information on the chemicals
15 used is limited, and volumes of chemicals stored on-site are generally not publicly available. These
16 limitations in data preclude the ability to know what volumes of chemicals may be spilled.
17 FracFocus, which currently holds the most comprehensive information on water and chemicals
18 used in hydraulic fracturing fluids, identifies well-specific chemicals and the concentration of those
19 chemicals as a maximum percentage of the mass of fracturing fluid. Accuracy and completeness of
20 original FracFocus disclosure information was not verified. In applying the EPA-standardized
21 chemical list to the ingredient records in the FracFocus database, standardized chemical names
22 were assigned to only 65% of the ingredient records from the more than 36,000 unique, fully
23 parsed disclosures. The remaining ingredient records could not be assigned a standardized
24 chemical name and were excluded from analyses [U.S. EPA. 2015a].
25 Operators may specify certain ingredients as confidential business information (CBI) and not
26 disclose the chemical used. More than 70% of disclosures to FracFocus contained at least one CBI
2 7 chemical. Of disclosures with at least one CBI chemical, the average number of CBI chemicals was
28 five. Approximately 11% of all ingredients were reported to FracFocus as CBI [U.S. EPA. 2015a). No
29 data are available in FracFocus for any chemical listed as CBI. Therefore, FracFocus CBI chemicals
30 are not included in analyses of volume, physical properties, or any other analysis in this
31 assessment, although we were able to do limited physicochemical analysis of 19 CBI chemicals.
32 Of the 1,076 hydraulic fracturing fluid chemicals identified by the EPA, 623 did not have estimated
33 physicochemical properties reported in the EPI Suite™ database. Knowing the chemical properties
34 of a spilled fluid is essential to predicting how and where it will travel in the environment Although
35 we can make some generalizations about the physicochemical properties of these chemicals and
36 how spilled chemicals may move in the environment, the distribution of properties could change if
37 we obtained data for all known fracturing fluid chemicals (as well as for those listed as CBI).
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1 In order to determine the potential impact of a spill, the physicochemical properties, the site-
2 specific environmental conditions, and proximity to drinking water resources must be known. This
3 information is generally lacking.
4 There is a lack of baseline surface water and ground water quality data. This lack of data limits our
5 ability to assess the relative change to water quality from a spill or attribute the presence of a
6 contaminant to a specific source.
7 In addition to limited information on chemical usage, we cannot complete a thorough assessment of
8 the potential impact of chemical spills due to limited information on actual spills. Data sources used
9 in the EPA's spills analysis do not cover all states with hydraulic fracturing activity. The available
10 data provide limited information on the types and volumes of chemicals spilled, spill causes,
11 containment and mitigation measures, and sources of spills. In addition, there is little available data
12 on impacts of spills, due to a lack of baseline data and incomplete documentation of follow-up
13 actions and testing.
14 In general, then, we are limited in our ability to fully assess potential impacts to drinking water
15 resources from chemical spills, based on available current information. To improve our
16 understanding we need: more information on the chemical composition of additives and fracturing
17 fluid; the physicochemical properties of chemicals used; baseline monitoring and field studies of
18 spilled chemicals; drinking water resources quality conditions before and after hydraulic fracturing
19 is performed; detailed site-specific environmental conditions; more information on the
2 0 containment and mitigation measures and their effectiveness; and the types and volumes of spills.
5.10.4. Conclusions
21 The chemical mixing stage of the hydraulic fracturing process has the potential to cause impacts to
2 2 drinking water resources by way of surface spills of chemicals and fracturing fluids. There are
2 3 documented chemical spills at fracturing sites, but a lack of available data limits our ability to
24 determine impacts. Potential impacts to drinking water resources are governed by the fluid
2 5 characteristics, chemical management and spill characteristics, and the fate and transport of spilled
26 chemicals through the environment
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Text Box 5-16. Research Questions Revisited.
1 What is currently known about the frequency, severity, and causes of spills of hydraulic fracturing fluids
2 and additives?
3 • The frequency of on-site spills from hydraulic fracturing operations could be obtained for two states.
4 Frequency estimates from data and literature ranged from 0.4 to 1.3 spills for every 100 wells
5 hydraulically fractured in Pennsylvania and Colorado, respectively, and between 3.3 and 12.2 spills for
6 every 100 wells installed in Pennsylvania (Rahmetal., 2015: U.S. EPA, 2015n: Brantley etal., 2014:
7 Gradient. 20131.i These estimates include spills of hydraulic fracturing chemicals and fluids, and
8 flowback and produced water reported in state databases. It is unknown whether these spill estimates
9 are representative of national occurrences. Estimates of the frequency of on-site spills from hydraulic
10 fracturing operations were unavailable for other areas. If the estimates are representative, the number of
11 spills nationally could range from 100 to 3,700 spills annually, assuming 25,000 to 30,000 new wells are
12 fractured p er y ear.
13 • In an analysis of spills, EPA characterized volumes and causes of hydraulic fracturing-related spills
14 identified from selected state and industry data sources. The spills occurred between January 2006 and
15 April 2012 in 11 states and included 151 cases in which fracturing fluid or additives spilled on or near a
16 well pad [U.S. EPA. 2015n). These cases were likely a subset of all chemical and fracturing fluid spills
17 during the study's time period. The reported volume of chemicals or fracturing fluid spilled ranged from
18 5 gal to more than 19,000 gal (19 to 72,000 L), with a median volume of 420 gal (1,600 L) per spill. Spill
19 causes included equipment failure, human error, failure of container integrity, and other causes (e.g.,
20 weather and vandalism). The most common cause was equipment failure. Specific causes of equipment
21 failure included blowout preventer failure, corrosion, and failed valves. More than 30% of the chemical or
22 fracturing fluid spills characterized by the EPA came from fluid storage units (e.g., tanks, totes, and
23 trailers) (U.S. EPA. 2015n).
1 Spill frequency estimates are for a given number of wells over a given period of time. These are not annual estimates nor
are they for over a lifetime of the wells.
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1 What are the identities and volumes of chemicals used in hydraulic fracturing fluids, and how might this
2 composition vary at a given site and across the country?
3 • In this assessment, we compiled a list of 1,076 chemicals used to formulate hydraulic fracturing fluids.
4 These chemicals include acids, alcohols, aromatic hydrocarbons, bases, hydrocarbon mixtures,
5 polysaccharides, and surfactants. This is a cumulative list over multiple wells and years. Operators used
6 an median of 14 unique chemicals per well according to the EPA's analysis of disclosures to FracFocus
7 [U.S. EPA. 2015a).
8 • Our analysis showed that chemical use varies and that no single chemical is used at all well sites across
9 the country, although several chemicals are widely used. Methanol, hydrotreated light petroleum
10 distillates, and hydrochloric acid were reported in 65% or more of FracFocus disclosures analyzed by the
11 EPA [U.S. EPA, 2015al. The composition of hydraulic fracturing fluids varies by state, by well, and within
12 the same service company and geologic formation. This variability likely results from several factors,
13 including the geology of the formation, the availability and cost of different chemicals, and operator
14 preference [U.S. EPA.2015a).
15 • Estimates from the EPA's database developed from disclosures made to FracFocus suggest median
16 volumes of individual chemicals injected per well ranged from a few gallons to thousands of gallons, with
17 a median of 650 gal (2,500 L) per chemical per well [U.S. EPA, 2015bl. If 14 unique chemicals are used
18 per well, then an estimated 9,100 gal (34,000 L) of chemicals may be injected per well (U.S. EPA. 2015aj.
19 What are the chemical and physical properties of hydraulic fracturing chemical additives?
20 • Measured or estimated physicochemical properties were obtained for 453 of the 1,076 chemicals
21 reported in hydraulic fracturing fluids. The wide variety of chemicals results in a wide range of
22 physicochemical properties.
23 • Many hydraulic fracturing chemicals fully dissolve in water, but the aqueous solubilities range from fully
24 miscible to sparingly soluble.
25 • The octanol-water partition coefficient ranges from the highly hydrophilic to the highly hydrophobic.
2 6 Many chemicals used in hydraulic fracturing fluid fall in the middle of this range, suggesting that they will
2 7 divide equally between water and solid phase, so that they may move slower through the environment
28 than those that associate more with water. More chemicals will associate strongly with soils and organic
29 materials, suggesting the potential of these chemicals to be long-term contaminants if they are spilled.
30 • There are few hydraulic fracturing chemicals that are volatile. Most hydraulic fracturing chemicals will
31 tend to remain in water as opposed to volatilizing to the air.
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1 • The chemicals for which we know physicochemical properties are not necessarily the chemicals most
2 frequently reported as used in hydraulic fracturing activities. Of the 453 chemicals for which
3 physicochemical properties were available, 18 of the top 20 most mobile chemicals were included in 2%
4 or less of disclosures fU.S. EPA. 2015b). However, two more common, but highly mobile chemicals,
5 choline chloride and tetrakis (hydroxymethyl) phosphonium sulfate were reported in 14% and 11% of
6 disclosures, respectively. These two chemicals are thus relatively more common, and, if spilled, their
7 properties of high mobility means they would move quickly through the environment with the flow of
8 water.
9 If spills occur, how might hydraulic fracturing chemical additives contaminate drinking water
10 resources?
11 • When chemicals are spilled, there are several paths by which a chemical could contaminate drinking
12 water resources. The chemical could flow overland to nearby surface water, penetrate into the soil that
13 could travel laterally and impact surface waters, or infiltrate and contaminate the underlying ground
14 water.
15 • Of the 151 spills characterized by the EPA, fluids reached surface water in 13 (9%) and soil in 97 (64%)
16 of those cases. None of the spills reportedly reached ground water [U.S. EPA, 2015n), but it could take
17 several years for spilled fluids to infiltrate soil and leach into ground water. Thus, it may not be
18 immediately known whether a spill reaches ground water or not
19 • The timing of a potential impact varies, but it could occur quickly, be delayed, have a continual impact
20 over time, or occur much later. Which path the spill takes depends on different conditions, such as
21 distance to a water receptor, spill volume, soil characteristics, and the physicochemical properties of the
22 chemical.
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Tudor. EH: Nevison. GW: Allen. S: Pike. B. (2009). Case study of a novel hydraulic fracturing method that
maximizes effective hydraulic fracture length. In 2009 SPE annual technical conference & exhibition.
Richardson, TX: Society of Petroleum Engineers. http://dx.doi.org/10.2118/124480-MS
U.S. EPA (U.S. Environmental Protection Agency). (1996). Soil screening guidance: technical background
document, part 2 [EPA Report] (2nd ed.). (EPA/540/R-95/128). Washington, DC: U.S. Environmental
Protection Agency, Office of Solid Waste and Emergency Response.
http://www.epa.gov/superfund/health/conmedia/soil/pdfs/part 2.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2012b). Estimation Programs Interface Suite for Microsoft
Windows (EPI Suite) [Computer Program]. Washington DC: US Environmental Protection Agency.
Retrieved from http://www.epa.gov/oppt/exposure/pubs/episuitedl.htm
U.S. EPA (U.S. Environmental Protection Agency). (2013a). Data received from oil and gas exploration and
production companies, including hydraulic fracturing service companies 2011 to 2013. Non-confidential
business information source documents are located in Federal Docket ID: EPA-HQ-ORD2010-0674.
Available at http://www.regulations.gov.
U.S. EPA (U.S. Environmental Protection Agency). (2015a). Analysis of hydraulic fracturing fluid data from the
FracFocus chemical disclosure registry 1.0 [EPA Report]. (EPA/601/R-14/003). Washington, D.C.: Office
of Research and Development, U.S. Environmental Protection Agency.
http://www2.epa.gov/hfstudy/analysis-hydraulic-fracturing-fluid-data-fracfocus-chemical-disclosure-
registry-1-pdf
U.S. EPA (U.S. Environmental Protection Agency). (2015b). Analysis of hydraulic fracturing fluid data from the
FracFocus chemical disclosure registry 1.0: Project database [EPA Report]. (EPA/601/R-14/003).
Washington, D.C.: U.S. Environmental Protection Agency, Office of Research and Development.
http://www2.epa.gov/hfstudy/epa-project-database-developed-fracfocus-l-disclosures
U.S. EPA (U.S. Environmental Protection Agency). (2015J). Retrospective case study in Killdeer, North Dakota:
study of the potential impacts of hydraulic fracturing on drinking water resources [EPA Report]. (EPA
600/R-14/103). Washington, D.C.
U.S. EPA (U.S. Environmental Protection Agency). (2015n). Review of state and industry spill data:
characterization of hydraulic fracturing-related spills [EPA Report]. (EPA/601/R-14/001). Washington,
D.C.: Office of Research and Development, U.S. Environmental Protection Agency.
Upstream Pumping. (2015). Upstream pumping: Wellhead technology and services. Available online at
http://upstreampumping.com/
UWS (Universal Well Services). (2008). Environmental response plan for field operations. (PATT-EPA-
0001060). Meadville, PA: Universal Well Services, Inc.
Vidic. RD: Brantley. SL: Vandenbossche. IM: Yoxtheimer. D: Abad. ID. (2013). Impact of shale gas development
on regional water quality [Review]. Science 340:1235009. http://dx.doi.org/10.1126/science.1235009
Waldron. P. (2014). In search of greener fracking for natural gas. Available online at
http://www.insidescience.org/content/search-greener-fracking-natural-gas/1791
Weinstein. I: Phillippi. M: Walters. HG. (2009). Dry-polymer blending eliminates need for hydrocarbon carrier
fluids. In 2009 SPE/EPA/DOE E&P Environmental & Safety Conference. Richardson, TX: Society of
Petroleum Engineers. http://dx.doi.org/10.2118/121002-MS
Wertz. I. (2014). Fracking site operator faces contempt complaint after acid spill. Available online at
http://stateimpact.npr.org/oklahoma/2014/08/14/fracking-site-operator-faces-contempt-complaint-
after-acid-spill/
Yeager. RR: Bailey. DE. (2013). Diesel-based gel concentrate improves Rocky Mountain region fracture
treatments. Richardson, TX: Society of Petroleum Engineers. http://dx.doi.org/10.2118/17535-MS
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 6
Well Injection
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6. Well Injection
6.1. Introduction
1 To conduct hydraulic fracturing, fluids (primarily water, mixed with the types of chemicals and
2 proppant described in Chapter 5) are injected into a well under high pressure.: These fluids flow
3 under pressure through the well (sometimes thousands of feet below the surface), then exit the
4 well and move into the formation, where they create fractures in the rock. This process is also
5 known as a fracture treatment or a type of stimulation.2 The fractures, which typically extend
6 hundreds of feet laterally from the well, are designed to remain within the production zone to
7 access as much oil or gas as possible, while using no more water or chemicals than necessary to
8 complete the operation.3
9 Production wells are sited and designed primarily to optimize production of oil or gas, which
10 requires isolating water-bearing formations and those containing the hydrocarbons to be exploited
11 from each other. This isolation can also protect drinking water resources. Appropriately sited,
12 designed, constructed, and operated wells and hydraulic fracturing treatments can reduce the
13 potential for impacts to drinking water resources. However, problems with the well's components
14 or improperly sited, designed, or executed hydraulic fracturing operations (or combinations of
15 these) could lead to adverse effects on drinking water resources.
16 The well and the geologic environment in which it is located are a closely linked system, often
17 designed with multiple barriers (i.e., isolation afforded by the well's casing and cement and the
18 presence of multiple layers of subsurface rock) to prevent fluid movement between oil/gas zones
19 and drinking water resources. Therefore, in this chapter we discuss (1) the well (including its
20 construction and operation) and (2) features in the subsurface geologic formations that could
21 provide or have provided pathways for migration of fluids to drinking water resources. If present
22 and in combination with the existence of a fluid and a physical force that moves the fluid, these
23 pathways can lead to impacts on drinking water resources throughout the life of the well, including
24 during and after hydraulic fracturing.4
25 Fluids can move via pathways adjacent to or through the production well that are created in
26 response to the stresses exerted during hydraulic fracturing operations (see Section 6.2). While
27 wells are designed and constructed to isolate fluids and maximize the production of oil and gas,
i A fluid is a substance that flows when exposed to an external pressure; fluids include both liquids and gases.
2 In the oil and gas industry, "stimulation" has two meanings—it refers to (1) injecting fluids to clear the well or pore
spaces near the well of drilling mud or other materials that create blockage and inhibit optimal production (i.e., matrix
treatment) and (2) injecting fluid to fracture the rock to optimize the production of oil or gas. This chapter focuses on the
latter.
3 The "production zone" (sometimes referred to as the target zone) refers to the portion of a subsurface rock zone that
contains oil or gas to be extracted (sometimes using hydraulic fracturing). "Producing formation" refers to the larger
geologic unit in which the production zone occurs.
4 The primary physical force that moves fluids within the subsurface is a difference in pressure. Fluids move from areas of
higher pressure to areas of lower pressure when a pathway exists. Density-driven buoyancy may also serve as a driving
force. See Section 6.3.
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1 inadequate construction or degradation of the casing or cement can allow fluid movement that can
2 change the quality of drinking water resources. Potential issues associated with wells may be
3 related to the following:
4 • Casing (e.g., faulty, inadequate, or degraded casing or other well components, as
5 influenced by the numbers of casings; the depths to which these casings are set;
6 compatibility with the geochemistry of intersected formations; the age of the well;
7 whether re-fracturing is performed; and other operational factors) and
8 • Cement (e.g., poor, inadequate, or degraded cement, as influenced by a lack of cement in
9 key intervals; poor-quality cement; improper or inadequate placement of cement; or
10 degradation of cement over time).
11 Fluid movement can also occur via induced fractures and/or other features within subsurface
12 formations (see Section 6.3). While the hydraulic fracturing operation may be designed so that the
13 fractures will remain within the production zone, it is possible that, in the execution of the
14 hydraulic fracturing treatment, fractures can extend beyond their designed extent. Four scenarios
15 associated with induced fractures may contribute to fluid migration or communication between
16 zones:
17 • Flow of injected and/or displaced fluids through pore spaces in the rock formations out of
18 the production zone due to pressure differences and buoyancy effects.
19 • Fractures extending out of oil/gas formations into drinking water resources or zones that
20 are in communication with drinking water resources or fracturing into zones containing
21 drinking water resources.
22 • Fractures intersecting artificial structures, including abandoned or active (producing)
23 offset wells near the well that is being stimulated (i.e., well communication) or abandoned
24 or active mines.1
25 • Fractures intersecting geologic features that can act as conduits, such as existing
26 permeable faults and fractures.
27 In this chapter, we describe the conditions that can contribute to or cause the development of the
28 pathways listed above, the evidence for the existence of these pathways, and potential impacts or
29 impacts on drinking water resources associated with these pathways.
30 The interplay between the well and the subsurface features is complex, and sometimes it is not
31 possible to identify what specific element is contributing to or is the primary cause of an impact to
32 drinking water resources. For example, concerns have been raised regarding stray gas detected in
33 ground water in natural gas production areas (for additional information about stray gas, see
34 Sections 6.2.2 and 6.3.2.4).2 Stray gas migration is a technically complex phenomenon, because
1 An abandoned well refers to a well that is no longer being used or cannot be used because of its poor condition.
2 Stray gas refers to the phenomenon of natural gas (primarily methane) migrating into shallow drinking water resources
or to the surface.
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1 there are many potential naturally occurring or artificially created routes for migration of gas into
2 aquifers (including along production wells and via naturally existing or induced fractures), and it is
3 challenging to determine the source of the natural gas and whether the mobilization is related to oil
4 or gas production activities.
5 Furthermore, identifying cases where contamination of drinking water resources occurs due to oil
6 and gas production activities—including hydraulic fracturing operations—requires extensive
7 amounts of site and operational data, collected before and after hydraulic fracturing operations.
8 Where such data does exist and provides evidence of contamination, we present it in the following
9 sections. We do not attempt to predict which of these pathways is most likely to occur or to lead to
10 a drinking water impact, or the magnitude of an impact that might occur as a result of migration via
11 any single pathway, unless the information is available and documented based on collected data.
6.2. Fluid Migration Pathways Within and Along the Production Well
12 In this section, we discuss pathways for fluid movement along or through the production well used
13 in the hydraulic fracturing operation. While these pathways can form at any time within any well,
14 the repeated high pressure stresses exerted during hydraulic fracturing operations may make
15 maintaining integrity of the well more difficult [Council of Canadian Academies. 2014]. In Section
16 6.2.1, we presentthe purpose of the various well components and typical well construction
17 configurations. Section 6.2.2 describes the pathways for fluid movement that can potentially
18 develop within the production well and wellbore and the conditions that lead to pathway
19 development, either as a result of the original design of the well, degradation over time or use, or
20 hydraulic fracturing operations.
21 While we discuss casing and cement separately, it is important to note that these are related—
22 inadequacies in one of these components can lead to stresses on the other. For example, flaws in
23 cement may expose the casing to corrosive fluids. Furthermore, casing and cement work together in
24 the subsurface to form a barrier to fluid movement, and it may not be possible to distinguish
25 whether integrity problems are related to the casing, the cement, or both. For additional
26 information on well design and construction, see Appendix D.
6.2.1. Overview of Well Construction
27 Production wells are constructed to convey hydrocarbon resources from the reservoirs in which
28 they are found to the surface and also to isolate fluid-bearing zones (containing oil, gas, or fresh
29 water) from each other. Multiple barriers are often present, and they act together to prevent both
30 horizontal movement (in or out of the well) and vertical movement (along the wellbore from deep
31 formations to drinking water resources). Proper design and construction of the casing, cement, and
3 2 other well components in the context of the location of drinking water resources and maintaining
33 mechanical integrity throughout the life of a well are necessary to prevent migration of fracturing
34 fluids, formation fluids, and hydrocarbons into drinking water resources.
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1 A well is a multiple-component system that typically includes casing, cement, and a completion
2 assembly, and it may be drilled vertically, horizontally, or in a deviated orientation.1 These
3 components work together to prevent unintended fluid movement into, out of, or along the well.
4 Due to the presence of multiple barriers within the well and the geologic system in which it is
5 placed, the existence of one pathway for fluid movement does not necessarily mean that an impact
6 to a drinking water resource has occurred or will occur.
7 Casing primarily acts as a barrier to lateral movement of fluids, and cement primarily acts as a
8 barrier to unintended vertical movement of fluids. Together, casing and cement are important in
9 preventing fluid movement into drinking water resources, and are the focus of this section. Figure
10 6-1 illustrates the configurations of casing and cement that may occur in oil and gas production
11 wells, including the types of casing strings that may be present, the potential locations of cement,
12 and other features. The figure depicts an idealized representation of the components of a
13 production well; it is important to note that there is a wide variety in the design of hydraulically
14 fractured oil and gas wells in the United States [U.S. EPA. 2015o], and the descriptions in the figure
15 or in this chapter do not represent every possible well design.
6.2.1.1. Casing
16 Casing is steel pipe that is placed into the drilled wellbore to maintain the stability of the wellbore,
17 to transport the hydrocarbons from the subsurface to the surface, and to prevent intrusion of other
18 fluids into the well and wellbore [Hyne, 2012: Renpu, 2011]. A long continuous section of casing is
19 referred to as a casing string, which is composed of individual lengths of casing (known as casing
20 joints) that are threaded together using casing collars. In different sections of the well, multiple
21 concentric casing strings (of different diameters) can be used, depending on the construction of the
22 well.
23 The presence of multiple layers of casing strings can isolate and protect geologic zones containing
24 drinking water. In addition to conductor casing, which prevents the hole from collapsing during
2 5 drilling, one to three other types of casing may be also present in a well. The types of casing include
2 6 (from largest to smallest diameter) surface casing, intermediate casing, and production casing
27 fGWPC. 2014: Hyne. 2012: Renpu. 20111 One or more of any of these types of casing may be
28 present in a well. Surface casing often extends from the wellhead down to the base (bottom) of the
29 drinking water resource to be protected. Wells also may be constructed with liners, which are
30 anchored or suspended from inside the bottom of the previous casing string, rather than extending
31 all the way to the surface, and production tubing, which is used to transport the hydrocarbons to
32 the surface.
1 For the purposes of this assessment, a well's "orientation" refers to the direction in which the well is drilled, and
"deviation" is used to indicate an orientation that is neither strictly vertical nor strictly horizontal. However, in industry
usage, "deviation" is also used as a generic term to indicate well orientation.
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• 12 =
12;
Wells used in hydraulic fracturing operations are constructed with
multiple layers of casing and cement to isolate fluid-bearing zones from
each other. While there is no "typical well," some of the more common
elements are presented in this figure. For additional information on the
design and construction of wells, see Appendix D.
Wells are constructed with multiple layers of casing that maintain
wellbore stability, transport hydrocarbons to the surface, and prevent
intrusion of fluids into the well and wellbore (1).
Surface casing (2) extends from the wellhead (3) down to or below the
base (bottom) of the ground water resource (4) to be protected. The
surface casing is cemented from its base to the surface to isolate the
ground water resource and prevent fluid movement. (Wells may also
have a conductor casing (not shown) to prevent unconsolidated material
from collapsing into the wellbore.) The cement shoe (5) controls the
placement of cement and prevents it from flowing back into the casing
after it has been placed.
When used, intermediate casing (6) can reduce pressure on weak
formations or allow better control of over-pressured formations, and it
extends from the surface through the formation(s) of concern.
The production casing (7) extends to the end of the wellbore in the
production zone (8)—which, in many cases, is thousands of feet below
the surface—and is cemented in place. In some wells, a production liner is
used in place of production casing. The production liner is hung from the
next largest casing string by a hanger (9) that is attached to the casing and
typically is cemented in place from the surface. Tubing (10), when used,
conveys hydrocarbons to the surface; it is installed after hydraulic
fracturing operations and is not cemented in place. If the well has an
open hole completion (not shown), the production casing extends just
into the production zone and the entire length of the wellbore through
the production zone is uncased.
At the bottom of the production casing, a packer (11), a mechanical
sealing device, may beset at the lower end of the tubing to create and
seal off the annulus (12), the space between the tubing and casing (or
between two casing strings), and to keep fluid from migrating along the
wellbore. Perforations (13) may be made through the casing and cement,
using small explosive charges; fracturing is conducted through the
perforations. Fracturing fluids are pumped into the well through the
tubing, if present, or through the production casing (if the well has an
open hole completion).
Cement (14) isolates fluid-containing formations from each other,
protects the casing from exposure to formation fluids, and adds strength
to the casing.
Figure 6-1. Overview of well construction.
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1 Among the wells represented by the Well File Review (see Text Box 6-1), between one and three
2 casing strings were present (the Well File Review did not evaluate conductor casings). A
3 combination of surface and production casings was most often reported, followed by a combination
4 of surface, intermediate, and production strings. All of the production wells used in hydraulic
5 fracturing operations in the Well File Review had surface casing, while approximately 39% of the
6 wells (an estimated 9,100 wells) had intermediate casing, and 94% (an estimated 21,900 wells) had
7 production casing (U.S. EPA. 2015o).
Text Box 6-1. The Well File Review.
8 The EPA conducted a survey of onshore oil and gas production wells that were hydraulically fractured by nine
9 oil and gas service companies in the continental United States between approximately September 2009 and
10 September 2010. The Review of Well Operator Files for Hydraulically Fractured Oil and Gas Production Wells:
11 Well Design and Construction [U.S. EPA, 2015o), referred to as the Well File Review, presents the results of the
12 survey and describes, for these wells: well design and construction characteristics, the relationship of well
13 design and construction characteristics to drinking water resources, and the number and relative location of
14 well construction barriers (i.e., casing and cement) that can block pathways for potential subsurface fluid
15 movement.
16 The results of the survey are based on information provided by well operators for a statistically
17 representative sample of 323 hydraulically fractured oil and gas production wells. The EPA did not attempt to
18 independently and systematically verify data supplied by well operators. Consequently, results from analyses
19 based on these data are of the same quality as the supplied data.
20 Results of the survey are presented as rounded estimates of the frequency of occurrence of hydraulically
21 fractured production well design or construction characteristics with 95% confidence intervals. The results
22 are statistically representative of an estimated 23,200 (95% confidence interval: 21,400-25,000) onshore oil
23 and gas production wells hydraulically fractured in 2009 and 2010 by the nine service companies.
24 Hydraulic fracturing operations impose a variety of stresses on the well components. The casing
25 should be designed with sufficient strength to withstand the stresses it will encounter during the
26 installation, cementing, fracturing, production, and postproduction phases of the life of the well.
27 These stresses, illustrated in Figure 6-2, include burst pressure (the interior pipe pressure that will
28 cause the casing to burst), collapse pressure (the pressure applied to the outside of the casing that
29 will cause it to collapse), tensile stress (the stress related to stretching exerted by the weight of the
30 casing or tubing being raised or lowered in the hole), compression and bending (the stresses that
31 result from pushing along the axis of the casing or bending the casing), and cyclical stress (the
32 stress caused by frequent or rapid changes in temperature or pressure). Casing strength can be
33 increased by using high-strength alloys or by increasing the thickness of the casing. In addition, the
34 casing must be resistant to corrosion from contact with the formations and any fluids that might be
35 transported through the casing, including hydraulic fracturing fluids, brines, and oil or gas.
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Tensile
Compressive
Collapse
b
M
Burst
Note: Figure not to scale
Stresses Exerted on Well Casings
Figure 6-2. The various stresses to which the casing will be exposed.
In addition to the stresses illustrated, the casing will be subjected to bending and cyclical stresses.
Source: U.S. EPA(2012c).
6.2.1.2. Cement
1 Cement is one of the most important components of a well for providing zonal isolation and
2 reducing impacts on drinking water. Cement isolates fluid-containing formations from each other,
3 protects the casing from exposure to formation fluids, and provides additional strength to the
4 casing. The strength of the cement and its compatibility with the formations and fluids encountered
5 are important for maintaining well integrity through the life of the well.
6 The cement does not always need to be continuous along the entire length of the well in order to
7 protect drinking water resources; rather, protection of drinking water resources depends on a good
8 cement seal across the appropriate subsurface zones, including all fresh water- and hydrocarbon-
9 bearing zones. One study in the Gulf of Mexico found that there was no breakdown in isolation
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1 between geologic zones with pressure differentials as high as 14,000 psi as long as there was at
2 least 50 ft (15 m) of high-quality cement between the zones [King and King. 2013].
3 Most wells have cement behind the surface casing, which is a key barrier to contamination of
4 drinking water resources. The surface casings in nearly all of the wells used in hydraulic fracturing
5 operations represented in the Well File Review (93% of the wells, or an estimated 21,500 wells)
6 were fully cemented.1 None of the wells studied in the Well File Review had completely uncemented
7 surface casings.
8 The length and location of cement behind intermediate and production casings can vary based on
9 the presence and locations of over-pressured formations, formations containing fluids, or
10 geologically weak formations (i.e., those that are prone to structural failure when exposed to
11 changes in subsurface stresses). State regulations and economics also play a role; 2 5 out of 2 7 oil
12 and gas producing states surveyed by the Ground Water Protection Council require some minimum
13 amount of cementing on the production casing above the producing zone (GWPC. 2014). In general,
14 the intermediate casings of the wells studied in the Well File Review were fully cemented; while
15 among production casings, about half we re partially cemented, about a third were fully cemented,
16 and the remainder were either uncemented or their cementing status was undetermined. Among
17 the approximately 9,100 wells represented in the Well File Review that are estimated to have
18 intermediate casing, the intermediate casing was fully cemented in an estimated approximately
19 7,300 wells (80%) and partially cemented in an estimated 1,700 wells (19%). Production casings
20 were partially cemented in 47% of the wells, or approximately 10,900 wells (U.S. EPA. 2015o).
21 The Well File Review also estimated the number of wells with a continuous cement sheath along the
22 outside of the well. An estimated 6,800 of the wells represented in the study (29%) had cement
23 from the bottom of the well to the ground surface, and approximately 15,300 wells (66%) had one
24 or more uncemented intervals between the bottom of the well and the ground surface. In the
25 remaining wells, the location of the top of the cement was uncertain, so no determination could be
26 made regarding whether the well had a continuous cement sheath along the outside of the well
27 fU.S. EPA. 2015oj.
28 A variety of methods are available for placing the cement, evaluating the adequacy of the cementing
29 process and the resulting cement job, and repairing any identified deficiencies. Cement is most
3 0 commonly emplaced by pumping the cement down the inside of the casing to the bottom of the
31 wellbore and then up the space between the outside of the casing and the formation (or the next
32 largest casing string). This method is referred to as the primary cement job and can be performed
33 as a continuous event in a single stage (i.e., "continuous cementing") or in multiple stages (i.e.,
34 "staged cementing"). Staged cementing may be used when, for example, the estimated weight and
i The Well File Review defined fully cemented casings as casings that had a continuous cement sheath from the bottom of
the casing to at least the next larger and overlying casing (or the ground surface, if surface casing). Partially cemented
casings were defined as casings that had some portion of the casing that was cemented from the bottom of the casing to at
least the next larger and overlying casing (or ground surface), but were not fully cemented. Casings with no cement
anywhere along the casing, from the bottom of the casing to at least the next larger and overlying casing (or ground
surface), were defined as uncemented.
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1 pressure associated with standard cement placement could damage weak zones in the formation
2 [Crook. 20081.
3 Deficiencies in the cementing process can result from poor centering or lost cement.: Poor
4 centering of the casing within the wellbore can cause uneven cement placement around the
5 wellbore, leading to the formation of thin weak spots that are prone to creation of uncemented
6 channels around the casing and loss of integrity [Kirksey, 2013]. If any deficiencies or defects in the
7 primary cement job are identified, remedial cementing may be performed.
8 In over 90% of wells studied in the Well File Review, the casing strings were cemented using
9 primary cement methods. Secondary or remedial cementing was used on an estimated
10 4,500 casings (8%) most often on surface and production casings and less often on intermediate
11 casings. The remedial cementing techniques employed in these wells included cement squeezes,
12 cement baskets, and pumping cement down the annulus [U.S. EPA. 2015o]. See Appendix D for
13 more information on remedial cementing techniques.
14 A variety of logs are available to evaluate the quality of cement behind the well casing. Among wells
15 in the Well File Review, the most common type of cement evaluation log run was a standard
16 acoustic cement bond log [U.S. EPA. 2015o]. Standard acoustic cement bond logs are used to
17 evaluate both the extent of the cement placed along the casing and the cement bond between the
18 cement, casing, and wellbore.2 Cement bond indices calculated from standard acoustic cement bond
19 logs on the wells in the Well File Review showed a median bond index of 0.7 just above the
20 hydraulic fracturing zone; this value decreased to 0.4 over a measured distance of 5,000 ft (1,524
21 m) above the hydraulic fracturing zone [U.S. EPA. 2015o]. While standard acoustic cement bond
22 logs can give an average estimate of bonding, they cannot alone indicate zonal isolation, because
23 they may not be properly run or calibrated [Boydetal., 2006: Smolen, 2006]. One study of 28 wells
24 found that cement bond logs failed to predict communication between formations 11% of the time
25 [Boydetal., 2006]. In addition, they cannot discriminate between full circumferential cement
26 coverage by weaker cement and lack of circumferential coverage by stronger cement [King and
27 King. 2013: Smolen. 2006]. A few studies have compared cement bond indices to zonal isolation,
28 with varying results. For example, Brown etal. [1970] showed that among 16 South American wells
29 with varying casing size and cement bond indices, a cemented 5.5 in (14 cm] diameter casing with a
30 bond index of 0.8 along as little as five feet can act as an effective seal. The authors also suggest that
31 an effective seal in wells having calculated bond indices differing from 0.8 are expected to have an
32 inverse relationship between bond index and requisite length of cemented interval, with longer
33 lengths needed along casing having a lower bond index. Another study recommends that wells
34 undergoing hydraulic fracturing should have a given cement bond over an interval that is three
35 times the length that would otherwise be considered adequate for zonal isolation (Fitzgerald etal.,
i Lost cement refers to a failure of the cement or the spacer fluid used to wash the drilling fluid out of the wellbore to be
circulated back to the surface, indicating that the cement has escaped into the formation.
2 Cement bond logs are used to calculate a bond index, which varies between 0 and 1, with 1 representing the strongest
bond and 0 representing the weakest bond.
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1 1985]. Conversely, King and King [2013] concluded that field tests from wells studied by Flournoy
2 andFeaster [1963] had effective isolation when the cement bond index ranged from 0.31 to 0.75.
6.2.1.3. Well Orientation
3 A well can be drilled and constructed with any of several different orientations: vertical, horizontal,
4 and deviated. The well's orientation can be important, because it affects the difficulty of drilling,
5 constructing, and cementing the well. In particular, as described below, constructing and cementing
6 horizontal wells present unique challenges [Sabins, 1990]. In a vertical well, the wellbore is vertical
7 throughout its entire length, from the wellhead at the surface to the production zone. Deviated
8 wells are drilled vertically but are designed to deviate from the vertical direction at some point
9 such that the bottom of the well is at a significant lateral distance away from the point in the
10 subsurface directly under the wellhead. In a horizontal well, the well is drilled vertically to a point
11 known as the kickoff point, where the well turns toward the horizontal, extending into and parallel
12 with the approximately horizontal targeted producing formation (see Figure 6-1].
13 The use of horizontal wells, particularly in unconventional reservoirs, is increasing [Drillinglnfo,
14 2014b: Valko. 2009]. Among wells evaluated in the Well File Review (i.e., over the period of
15 September 2009 to September 2010], about 66% were vertical, 11% were horizontal, and about
16 23% were deviated wells (U.S. EPA, 2015O].1 This is generally consistent with information available
17 in industry databases—of the approximately 16,000 oil and gas wells used in hydraulic fracturing
18 operations in 2009 (one of the years for which the data for the Well File Review were collected],
19 39% were vertical, 33% were horizontal, and 28% were either deviated or the orientation was
20 unknown (Drillinglnfo. 2014b]. Note that among natural gas wells used in hydraulic fracturing
21 operations, 49.5% of wells in the Drillinglnfo database were horizontal. The use of horizontal wells
22 in hydraulic fracturing operations has also been steadily increasing; in 2012, 63.7% of all wells used
23 in hydraulic fracturing operations were horizontal, compared to just 4% in 2003 (Drillinglnfo,
24 2014b]. See Figure 2-16 for a map presenting the locations of horizontal wells in the United States.
6.2.1.4. Well Completion
2 5 Another important aspect of well construction is how the well is completed into the production
2 6 zone, because the well's completion is part of the system of barriers and must be intact to provide a
27 fully functioning system.2 A variety of completion configurations are available. The most common
28 configuration is for casing to extend to the end of the wellbore and be cemented in place (U.S. EPA,
29 2015o: George etal.. 2011: Renpu. 2011]. Before hydraulic fracturing begins, perforations are made
30 through the casing and cement into the production zone. It is through the perforated casing and
31 cement that hydraulic fracturing is conducted. In some cases, a smaller temporary casing, known as
32 a frac string, is inserted inside the production casing to protect it from the high pressures imposed
33 during hydraulic fracturing operations. Another method of completion is an open hole completion,
1 The Well File Review considered any non-horizontal well in which the well bottom was located more than 500 ft (152
m) laterally from the wellhead as being deviated.
2 Completion is a term used to describe the assembly of equipment at the bottom of the well that is needed to enable
production from an oil or gas well. It can also refer to the activities and methods (including hydraulic fracturing) used to
prepare a well for production following drilling.
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1 where the production casing extends into the production zone and the entire length of the drilled
2 horizontal wellbore through the production zone is left uncased. With open hole completions, the
3 entire production zone can either be fractured all at once in a single stage, or in stages using a
4 casing string set on formation packers, which separate the annulus into stages.1 A special casing
5 with retractable sleeves is used to fracture each stage separately. Among wells represented in the
6 Well File Review, an estimated 6% of wells (1,500 wells) had open hole completions, 6% of wells
7 (1,500 wells) used formation packers, and the rest were cased and cemented (U.S. EPA. 2015o).
8 In some cases, wells may be recompleted after the initial construction, with re-fracturing if
9 production has decreased (Vincent. 2011). Recompletion also may include additional perforations
10 in the well at a different interval to produce from a new formation, lengthening the wellbore, or
11 drilling new laterals from an existing wellbore.
6.2.2. Evidence of the Existence of Fluid Movement Pathways or of Fluid Movement
12 The following sections describe the pathways for fluid movement that can develop within the
13 production well and wellbore. We also describe the conditions that lead to the development of fluid
14 movement pathways and, where available, evidence that a pathway has allowed fluid movement to
15 occur within the casing or cement, and—in the case of sustained casing pressure (see Section
16 6.2.3)—a combination of factors within the casing and cement. (See Figure 6-3 for an illustration of
17 potential fluid movement pathways related to casing and cement) We describe available
18 information regarding the rate at which these pathways have been identified in hydraulic fracturing
19 wells or, where such information does not exist, present the results of research on oil and gas
20 production wells in general or on injection wells.2 Insufficient publicly accessible information exists
21 to determine whether wells intended for hydraulic fracturing are constructed differently from
22 production wells where no fracturing is conducted. However, given the applicability of well
23 construction technology to address the subsurface conditions encountered in hydraulic fracturing
24 operations and production or injection operations in general, this information is considered
25 relevant to the research questions (see Section 6.4).
26 While new wells can be specifically designed to withstand the stresses associated with hydraulic
27 fracturing operations, older wells, which are sometimes used in hydraulic fracturing operations,
28 may not have been designed to the same specifications. Where older wells were not designed
29 specifically to withstand the stresses associated with hydraulic fracturing, their reuse for this
30 purpose could be a concern. Frac strings, which are specialized pieces of casing inserted inside the
31 production casing, may be used to protect older casing during fracturing. However, the effect of
32 fracturing on the cement on the production casing in older wells is unknown. One study on re-
33 fracturing of wells noted that the mechanical integrity of the well was a key factor in determining
34 the success or failure of the fracturing (Vincent, 2011). An estimated 6% of wells (1,400 wells)
1 A formation packer is a specialized casing part that has the same inner diameter as the casing but whose outer diameter
expands to make contact with the formation and seal the annulus between the casing and formation, preventing
migration of fluids.
2 An injection well is a well into which fluids are being injected (40 CFR 144.3).
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1 represented in the Well File Review were more than 10 years old before they were fractured
2 between 2009 and 2010 [U.S. EPA. 2015oj.
Figure 6-3. Potential pathways for fluid movement in a cemented wellbore.
These pathways include: (1) casing/tubing leak into a permeable formation, (2) migration along an
uncemented annulus, (3) migration along microannuli between the casing and cement, (4) migration
through poor cement, or (5) migration along microannuli between the cement and formation. Note:
the figure is not to scale and is intended to provide a conceptual illustration of pathways that may
develop within the well.
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1 Note that there are also potential issues related to where older wells are sited. For example, some
2 wells may be in areas with naturally occurring subsurface faults or fractures that could not be
3 detected or fully characterized with the technologies available at the time of construction. See
4 Section 6.3.2.
6.2.2.1. Pathways Related to Well Casing
5 High pressures associated with hydraulic fracturing operations can damage the casing and lead to
6 fluid movement that can change the quality of drinking water resources. The casing string through
7 which fracturing fluids are injected is subject to higher pressures during fracturing operations than
8 during other phases in the life of a production well. To withstand the stresses created by the high
9 pressure of hydraulic fracturing, the well and its components must have adequate strength and
10 elasticity. If the casing is compromised or is otherwise not strong enough to withstand these
11 stresses (see Figure 6-2), a casing failure may result. If undetected or not repaired, casing failures
12 will serve as pathways for fracturing fluids to leak out of the casing.1 Below we present indicators
13 that pathways along the casing are present or allowing fluid movement
14 Fracturing fluids or fluids naturally present in the subsurface could flow into other zones in the
15 subsurface if inadequate or no cement is present and the pressure in the casing is greater than the
16 formation pressure. As we describe below, pathways for fluid movement associated with well
17 casing may be related to the original design or construction of the well, degradation of the casing
18 over time, or problems that can arise through extended use as the casing succumbs to stresses.
19 Casing failure may also occur if the wellbore passes through a structurally weak geologic zone that
20 fails and deforms the well casing. Such failures are common when drilling through zones containing
21 salt [Renpu. 2011). This type of well damage may also be possible if hydraulic fracturing causes
22 stress failure along a fault Investigation of a well following a seismic event in England that was
23 attributed to hydraulic fracturing found that the casing had been deformed by the stress from the
24 formation [De Pater and Baisch, 2011]. While it is not known if the casing deformation occurred
25 before or after the seismic event, such damage is possible if mechanically weak formations are
26 present The changes in the pressure field in the portions of the formation near the wellbore during
27 hydraulic fracturing can also cause mechanically weak formations to fail, potentially damaging the
28 well. Palmer etal. [2005] demonstrated through modeling that hydraulic fracturing within coal that
29 had a low unconfined compressive strength could cause shear failure of the coalbeds surrounding
30 the wellbore.
31 Corrosion in uncemented zones is the most common cause of casing failure. This can occur if
32 uncemented sections of the casing are exposed to corrosive substances such as brine or hydrogen
33 sulfide [Renpu. 2011]. Corrosion commonly occurs at the collars that connect sections of casing or
1 Internal mechanical integrity tests (MITs), such as casing inspection logs or caliper logs, annulus pressure monitoring,
and pressure testing, can provide early warning of a problem, such as a leak, within the casing. It is important to note that
if a well fails an MIT, this does not mean there is a failure of the well or that drinking water resources are impacted. An
MIT failure is a warning that something needs to be addressed, and a loss of integrity is an event that may result in fluid
movement from the well if remediation is not performed.
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1 at other places where other equipment is attached to the casing. Corrosion at collars may
2 exacerbate problems with loose or poorly designed connections, which are another common cause
3 of casing leaks fKing and King. 2013: Brufatto etal.. 20031 Watson and Bachu f20091 found that
4 66% of all casing corrosion occurred in uncemented well sections, as shown in Pathway 1 of Figure
5 6-3.
6 Aging and use of the well contribute to casing degradation. Casing corrosion and degradation can
7 occur over time and with extended use. Also, exposure to corrosive chemicals such as hydrogen
8 sulfide, carbonic acid, and brines can accelerate corrosion. Therefore, the potential for fluid
9 migration related to compromised casing tends to be higher in older wells. Ajani and Kelkar [2012]
10 studied wells in Oklahoma and found a correlation between well age and integrity, specifically in
11 wells spaced between 1,000 and 2,000 ft (305 and 610 m) from a well being fractured, the
12 likelihood of impact to the well rose from approximately 20% to 60% as the well's age increased
13 from 200 days to over 600 days. Age was also found to be a factor in well integrity problems in a
14 study of wells in the Gulf of Mexico [Brufatto etal., 2003]. The studies mentioned did not look for
15 evidence of such fluid movement pathways, however. Because of this potential for degradation of
16 well components in older wells and the related potential for fluid movement, reentering older wells
17 for re-fracturing may contribute to the development of fluid movement pathways within those
18 wells.
19 As noted above, the casing and cement work together to strengthen the well and provide zonal
2 0 isolation. Uncemented casing does not necessarily lead to fluid migration. However, migration can
21 occur if the casing in an uncemented zone fails during hydraulic fracturing operations or if the
2 2 uncemented section is in contact with fluid-containing zones (including the zone being fractured).
23 Sections of well casing that are uncemented may allow fluid migration into the annulus between the
24 casing and formation. Fluid is free to migrate between formations in contact with the uncemented
2 5 well section in any uncemented annulus without significant hole sloughing or wellbore swelling. If
26 the uncemented section extends through a drinking water resource, fluid migration into the
27 drinking water resource may occur.
28 Other well integrity problems have been found to vary with the well environment, particularly
29 environments with high pressures and temperatures. Wells in high pressure/high temperature
30 environments, wells with thermal cycling, and wells in corrosive environments can have life
31 expectancies of less than 10 years (King and King. 2013].
32 The depth of the surface casing relative to the base of the drinking water resource to be protected is
33 an important factor in protecting the drinking water resource. In a limited risk modeling study of
34 selected injection wells in the Williston Basin, Michie and Koch (1991] found the risk of aquifer
35 contamination from leaks from the inside of the well to the drinking water resource was 7 in
36 1,000,000 injection wells if the surface casing was set deep enough to cover the drinking water
37 resource, andthatthe risk increased to 6 in 1,000 wells if the surface casing was notset deeper
38 than the bottom of the drinking water resource. An example where surface casing did not extend
39 below drinking water resources comes from an investigation of 14 drinking water wells with
40 alleged water quality problems in the Wind River and Fort Union formations in Wyoming
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1 [WYOGCC, 2014]. The state found that the surface casing of oil and gas wells was shallower than the
2 depth of 3 of the 14 drinking water wells. Some of the oil and gas wells with shallow surface casing
3 had elevated gas pressures in their annuli [WYOGCC. 2014).
4 During hydraulic fracturing operations near Killdeer, in Dunn County, North Dakota, the
5 production, surface, and conductor casing of the Franchuk 44-20 SWH well ruptured, causing fluids
6 to spill to the surface (Jacob, 2011]. The rupture occurred during the 5th of 23 stages of hydraulic
7 fracturing when the pressure spiked to over 8,390 psi (58 MPa). The casing failed, and ruptures
8 were found in two locations along the production casing—one just below the surface and one at
9 about 55 ft (17 m) below ground surface. The surface casing ruptured in three places down to a
10 depth of 188 ft (57 m), and the conductor casing ruptured in one place. Despite a shutdown of the
11 pumps, the pressure was still sufficient to cause fluid to travel through the ruptured casings and to
12 bubble up at the surface. Ultimately, nearly 168,000 gallons (636 m3) of fluids and approximately
13 2,860 tons (2,595 metric tons) of contaminated soil were removed from the site (Jacob, 2011].
14 Sampling of two monitoring wells in the drinking water aquifer identified brine contamination that
15 was consistent with mixing of local ground water with brine from Madison Group formations,
16 which the well had penetrated (U.S. EPA, 2015)]. Tert-butyl alcohol (TEA] was also found in the two
17 wells with brine contamination. The TEA was consistent with degradation of tert-butyl
18 hydroperoxide, a component of the fracturing fluid used in the Franchuk well. The rupture
19 (blowout] was the only source consistent with findings of high brine and TEA concentrations in the
20 two wells.1 For additional information about impacts at the Killdeer site, see Text Box 5-12 in
21 Section 5.5 and Section 6.3.2.2.
22 Inadequate casing or cement can respond poorly when blowout preventers activate. When blowout
23 preventers are activated, they immediately stop the flow in the well, which can create a sudden
24 pressure increase in the well. If the casing or cement are not strong enough to withstand the
25 increased pressure when this occurs, well components can be damaged (The Royal Society and the
26 Royal Academy of Engineering. 2012] and the potential for fluid release and migration in the
27 subsurface increases. Blowouts can also occur during the production phase, and cause spills on the
28 surface that can affect drinking water resources; see Section 7.7.3.2.
29 While well construction and hydraulic fracturing techniques continue to change, the pressure- and
30 temperature-related stresses associated with hydraulic fracturing remain as factors that can affect
31 the integrity of the well casing. Several studies have evaluated the components of a well that can
32 affect well performance and integrity. Ingraffea et al. (2014] conducted a study of well integrity in
33 Pennsylvania production wells to assess overall trends in well integrity. This study identified a
34 significant increase in well integrity problems from 2009 to 2011 rising to 5% to 6% of all wells,
35 followed by a decrease beginning in 2012 to about 2% of all wells, a reduction of approximately 100
i A well blowout is the uncontrolled flow of fluids out of a well. A blowout preventer (BOP) is casinghead equipment that
prevents the uncontrolled flow of oil, gas, and mud from the well by closing around the drill pipe or sealing the hole [Oil
and Gas Mineral Services. 2010). BOPs are typically a temporary component of the well, in place only during drilling and
perhaps through hydraulic fracturing operations.
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1 violations among 3,000 wells. The rise in well integrity problems between 2009 and 2011 coincided
2 with an increase in the number of wells in unconventional reservoirs.
3 Emerging isotopic techniques can be used to identify the extent to which stray gas occurring in
4 drinking water resources is linked to casing failure (see Text Box 6-2 for more information on stray
5 gas). Darrahetal. [2014] used hydrocarbon and noble gas isotope data to investigate the source of
6 gas in eight identified "contamination clusters." Seven of these clusters were stripped of
7 atmospheric gases (Ar36 and Ne20) and were enriched in crustal gases, indicating the gas migrated
8 quickly from depth without equilibrating with intervening formations. The rapid transport was
9 interpreted to mean that the migration did not occur along natural fractures or pathways, which
10 would have allowed equilibration to take place. Possible explanations for the rapid migration
11 include transport up the well and through a leaky casing (Pathway 1 in Figure 6-3) or along
12 uncemented or poorly cemented intervals from shallower depths (Pathways 2 through 5 in Figure
13 6-3). In four Marcellus Shale clusters, gas found in drinking water wells had isotopic signatures and
14 ratios of ethane to methane that were consistent with those in the producing formation. The
15 authors conclude that this suggests that gas migrated along poorly constructed wells from the
16 producing formation, likely with improper, faulty, or failing production casings. In three clusters,
17 the isotopic signatures and ethane to methane ratios were consistent with formations overlying the
18 Marcellus. The authors suggest that this migration occurred from the shallower gas formations
19 along uncemented or improperly cemented wellbores. In another Marcellus cluster in the study,
20 deep gas migration was linked to a subsurface well, likely from a failed well packer.
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Text Box 6-2. Stray Gas Migration.
Stray gas refers to the phenomenon of natural gas (primarily methane) migrating into shallow drinking water
resources, into water wells, or to the surface (e.g., cellars, streams, or springs). Stray gas in the wellhead of a
production well is an indicator of an active wellbore pathway. Methane is not a regulated drinking water
contaminant, but it can initiate chemical and biological reactions that release or mobilize other contaminants,
and gas can accumulate to explosive levels when allowed to exsolve (degas) from ground water in closed
environments. Stray gas may originate from conventional and unconventional natural gas reservoirs, as well
as from coal mines, landfills, leaking gas wells, leaking gas pipelines, and buried organic matter (Baldassare.
20111.
Detectable levels of dissolved hydrocarbons (generally methane and/or ethane) exist in most oxygen-poor
aquifers, even in the absence of human activity (Gorody. 2012). Pre-drilling studies show that low levels of
methane are frequently found in water wells in northern Pennsylvania and New York (Kappel. 2013: Kappel
and Nystrom, 2012): one USGS study detected methane in 80% of sampled wells in Pike County, Pennsylvania
(Senior. 2014). The origin of methane in ground water can be either thermogenic (produced by high
temperatures and pressures in deeper formations, such as the gas found in the Marcellus Shale) or biogenic
(produced in shallower formations by bacterial activity in anaerobic conditions). Occurrence of thermogenic
methane in shallower formations depends upon the existence of a hydrocarbon source and pathways by
which the gas can migrate. Interactions between hydrocarbon production and natural systems must also be
considered. For example, Brantley et al. (2014) describe how northern Pennsylvania's glacial history may
help explain why stray gas is more common there than in the southern part of the state.
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1 Stray gas migration can be a technically complex phenomenon, in part because there are many potential
2 routes for migration. The lack of detailed monitoring data, including a lack of baseline measurements prior to
3 hydrocarbon production, often further complicates stray gas research. Examining the concentrations and
4 isotopic compositions of methane and higher molecular weight hydrocarbons such as ethane and propane
5 can aid in determining the source of stray gas [Tilley and Muehlenbachs. 2012: Baldassare. 2011: Rowe and
6 Muehlenbachs. 1999]. Isotopic composition and methane-to-ethane ratios can help determine whether the
7 gas is thermogenic or biogenic in origin and whether it is derived from shale or other formations [Gorody.
8 2012: Muehlenbachs et al.. 2012: Barker and Fritz. 1981]. Isotopic analysis can also be used to identify the
9 strata where the gas originated and provide evidence for migration mechanisms [Darrah et al.. 2014].
10 However, determining the source of methane does not necessarily establish the migration pathway. Well
11 casing and cementing issues may be an important source of stray gas problems [lackson et al.. 2013b]:
12 however, other potential subsurface pathways are also discussed in the literature. Multiple researchers (e.g.,
13 lackson etal., 2013b: Molofsky etal., 2013: Revesz etal., 2012: Osborn etal., 2011] have described biogenic
14 and/or thermogenic methane in ground water supplies in Marcellus gas production areas, although the
15 pathways of migration are generally not apparent. The Osborn etal. [2011] study found that thermogenic
16 methane concentrations in well water increased with proximity to Marcellus Shale production sites, while
17 Molofsky et al. [2013] found the presence of gas to be more closely correlated with topography and elevation.
18 Similarly, Siegel et al. [In Press] found no correlation between methane in ground water and proximity to
19 production wells.
2 0 The EPA conducted case studies that included investigating stray gas in northeastern Pennsylvania and the
21 Raton Basin of Colorado. In northeastern Pennsylvania, many drinking water wells within the study area
22 were found to have elevated methane concentrations. For some of the wells, the EPA concluded that the
23 methane (both thermogenic and biogenic] was naturally occurring background gas not attributable to gas
24 exploration activities. In others, it appeared that non-background methane had entered the water wells
25 following well drilling and hydraulic fracturing. In most cases, the methane in the wells likely originated from
26 intermediate formations between the production zone and the surface; however, in some cases, the methane
27 appears to have originated from deeper layers such as those where the Marcellus Shale is found [U.S. EPA.
28 2015o]. The Raton Basin case study examined the Little Creek Field, where potentially explosive quantities of
29 methane were vented into a number of drinking water wells in 2007. The methane was found to be primarily
30 thermogenic in origin, modified by biologic oxidation [U.S. EPA. 20151]. Secondary biogeochemical changes
31 related to the migration and reaction of methane within the shallow drinking water aquifer were reflected in
3 2 the characteristics of the Little Creek Field ground water [U.S. EPA. 20151].
3 3 While the sources of methane in the two studies could be determined with varying degrees of certainty,
34 attempts to definitively identify the pathways of migration have been inconclusive. In northeastern
35 Pennsylvania, while the sources could not be definitively determined, the Marcellus Shale could not be
36 excluded as a potential source in some wells based on isotopic signatures, methane-to-ethane ratios, and
37 isotope reversal properties [U.S. EPA. 2014J]. The Pennsylvania
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1 Department of Environmental Protection (PA DEP) cited at least two operators for failure to prevent gas
2 migration at a number of wells within the study area. Evidence cited by the state included isotopic
3 comparison of gas samples from drinking water wells, water bodies, and gas wells; inadequate cement jobs;
4 and sustained casing pressure (although, under Pennsylvania law, oil or gas operators can be cited if they
5 cannot disprove the contamination was caused by their well using pre-drilling samples). A separate study
6 (Ingraffea et al.. 2014] showed that wells in this area had higher incidences of well integrity problems relative
7 to wells in other parts of Pennsylvania. In the Raton Basin, the source of methane was identified as the
8 Vermejo coalbeds. Based on modeling of the Raton Basin study area, the migration could be explained either
9 by migration along natural rock features in the area or by migration caused by fracturing around the wellbore
10 (U.S. EPA, 201511. Because the gas production wells were shut in shortly after the incident began, the wells
11 could not be inspected to determine whether an integrity failure in the wellbore was a likely cause of the
12 migration.1
13 These two case studies illustrate the considerations involved with understanding stray gas migration and the
14 difficulty in determining sources and migration pathways. In order to more conclusively determine sources
15 and migration pathways, studies in which data are collected on well integrity and ground water methane
16 concentrations both before and after hydraulic fracturing operations, in addition to the kinds of data
17 summarized above, would be needed.
6.2.2.2. Pathways Related to Cement
18 Fluid movement may result from inadequate well design or construction (e.g., cement loss or other
19 problems that arise in cementing of unconventional wells) or degradation of the cement over time
20 (e.g., corrosion or the formation of microannuli), which may, if undetected and not repaired, cause
21 the cement to succumb to the stresses exerted during hydraulic fracturing.2'3 The well cement must
22 be able to withstand the subsurface conditions and the stresses encountered during hydraulic
23 fracturing operations. In this section, we present indicators that pathways within the cement are
24 present or allowing fluid movement
25 Uncemented zones can allow fluids or brines to move into drinking water resources. An improper
26 cement job can fail to maintain zonal isolation in several ways. The first is by poor cement
27 placement If a fluid-containing zone is left uncemented, the open annulus between the formation
28 and casing can act as a pathway for migration of that fluid. Fluids can enter the wellbore along any
29 uncemented section of the wellbore if a sufficient pressure gradient is present Once the fluids have
30 entered the wellbore, they can travel along the entire uncemented length of the wellbore, unless the
31 wellbore sloughs in around the casing.
32 Because of its low density, gas will migrate up the wellbore if an uncemented wellbore is exposed to
33 a gas-containing formation. Gas may then be able to enter other formations (including drinking
1 Shutting in a well refers to sealing off a well by either closing the valves at the wellhead, a downhole safety valve, or a
blowout preventer.
2 External MITs, such as temperature logs, noise logs, oxygen activation logs, and radioactive tracer logs, can indicate
improper cementing or degradation of the cement.
3 Microannuli are very small channels that form in the cement and that may serve as pathways for fluid migration to
drinking water resources.
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1 water resources) if the wellbore is uncemented and the pressure in the annulus is sufficient to force
2 fluid into the surrounding formation [Watson and Bachu. 2009]. The rate at which the gas can move
3 will depend on the difference in pressure between the annulus and the formation [Wojtanowicz.
4 2008]. Harrison [1985] also demonstrated that such uncemented annuli could result in the
5 migration of gas into overlying formations open to the annulus.
6 In several cases, poor or failed cement has been linked to stray gas migration (see Text Box 6-2]. A
7 Canadian study found that uncemented portions of casing were the most significant contributors to
8 gas migration [Watson and Bachu. 2009]. The same study also found that 57% of all casing leaks
9 occurred in uncemented segments. In the study by Darrah et al. [2014] [see Section 6.2.2.1] using
10 isotopic data, four clusters of gas contamination were linked to cement issues. In three clusters in
11 the Marcellus and one in the Barnett, gas found in drinking water wells had isotopic signatures
12 consistent with intermediate formations overlying the producing zone. This suggests that gas
13 migrated from the intermediate units along the well annulus, along uncemented portions of the
14 wellbore or through channels or microannuli. In a study in Utah, Heilweil etal. [2013] used a
15 stream-based methane monitoring method to identify a case of potential gas migration near a well
16 with defective casing or cement
17 Cementing of the surface casing is the primary aspect of well construction that protects drinking
18 water resources. Most states require the surface casing to be set and cemented from the level of the
19 lowermost drinking water resource to the surface [GWPC. 2014]. Most wells—including those used
20 in hydraulic fracturing operations—have such cementing in place. Among the wells represented in
21 the Well File Review, surface casing, which was found to be fully cemented in 93% of wells,
22 extended below the base (i.e., the bottom, deepest, or lowermost part] of the protected ground
23 water resource reported by well operators in an estimated 55% of wells (12,600 wells].1 In an
24 additional 28% of wells (6,400 wells], the operator-reported protected ground water resources
25 were fully covered by the next cemented casing string. A portion of the annular space between
26 casing and the operator-reported protected ground water resources was uncemented in at least 3%
27 of wells (600 wells] (U.S. EPA. 2015o].2 Improper placement of cement can lead to cement integrity
28 problems. For example, an improper cement job can be the result of loss of cement during
29 placement into a formation with high porosity or fractures, causing a lack of adequate cement
30 across a water- or brine-bearing zone. Additionally, failure to use cement that is compatible with
31 the anticipated subsurface conditions, failure to remove drilling fluids from the wellbore, and
32 improper centralization of the casing in the wellbore can all lead to the formation of channels (i.e.,
33 small connected voids] in the cement during the cementing process [McDaniel et al., 2 014: Sabins,
34 1990]. If the channels are small and isolated, they may not lead to fluid migration. However, if they
1 In the in the Well File Review, protected ground water resources were reported by well operators. For most wells
represented in the Well File Review, protected ground water resources were identified by the well operators from state
or federal authorization documents. Other data sources used by well operators included aquifer maps, data from offset
production wells, open hole log interpretations done by operators, operator experience, online databases, and references
to a general requirement by the oil and gas agency.
2 The well files representing an estimated 8% of wells in the Well File Review did not have sufficient data to determine
whether the operator-reported protected ground water resource was uncemented or cemented. In these cases, there was
ambiguity either in the depth of the base or the top of the operator-reported protected ground water resource.
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1 are long and connected, extending across multiple formations or connecting to other existing
2 channels or fractures, they can present a pathway for fluid migration. Figure 6-3 shows a variety of
3 pathways for fluid migration that are possible from failed cement jobs.
4 One example of how cement problems associated with hydraulic fracturing contributed to a
5 contamination incident occurred in Bainbridge, Ohio. This incident was particularly well studied by
6 the Ohio Department of Natural Resources [ODNR, 2008] and by an expert panel [Bair etal., 2010].
7 The level of detail available for this case is not typically found in studies of such events but was
8 collected because of the severity of the impacts and the resulting legal action. The English #1 well
9 was drilled to a depth of 3,900 ft (1,189 m] below ground surface (bgs] with the producing
10 formation located between 3,600 and 3,900 ft (1,097 and 1,189 m] bgs. Overlying the producing
11 formation were several uneconomic formations that contained over-pressured gas (i.e., gas at
12 pressures higher than the hydrostatic pressure exerted by the fluids within the well].1 The original
13 cement design required the cement to be placed 700-800 ft (213-244 m] above the producing
14 formation to seal off these areas. During cementing, however, the spacer fluid failed to return to the
15 surface, indicating lost cement, and the cement did not reach the intended height.2 Despite the lack
16 of sufficient cement, the operator proceeded with hydraulic fracturing.
17 During the fracturing operation, about 840 gallons (3.2 m3] of fluid flowed up the annulus and out
18 of the well. When the fluid began flowing out of the annulus, the operator immediately ceased
19 operations. About a month later, there was an explosion in a nearby house where methane had
2 0 entered from an abandoned and unplugged drinking water well that was connected to the cellar
21 (Bair etal.. 2010]. In addition to the explosion, the over-pressured gas entering the aquifer resulted
22 in the contamination of 26 private drinking water wells with methane.
2 3 Contamination at Bainbridge was the result of inadequate cement The ODNR determined that
24 failure to cement the over-pressured gas formations, proceeding with the fracturing operation
2 5 without verifying there was adequate cement, and the extended period during which the well was
26 shut in all contributed to the contamination of the aquifer with stray gas (ODNR. 2008]. Cement
27 logs found the cement top was at 3,640 ft (1,109 m] bgs, leaving the uneconomic gas-producing
28 formations and a portion of the production zone uncemented. Hydraulic fracturing fluids flowing
29 out of the annulus provided an indication that the fracturing had created a path from the producing
30 formation to the well annulus. This pathway may have allowed gas from the producing formation
31 along with gas from the uncemented formation to enter the annulus. Because the well was shut in,
32 the pressure in the annulus could not be relieved, and the gas eventually traveled through natural
33 fractures surrounding the wellbore into local drinking water aquifers. (During the time the well
34 was shut in, natural gas seeped into the well annulus and pressure built up from an initial pressure
35 of 90 psi (0.6 MPa] to 360 psi (2.5 MPa]]. From the aquifer, the gas moved into drinking water wells
36 and from one of those wells into a cellar, resulting in the explosive accumulation of gas.
1 Hydrostatic pressure is the pressure exerted by a column of fluid at a given depth. Here, it refers to the pressure exerted
by a column of drilling mud or cement on the formation at a particular depth.
2 Spacer fluid is a fluid pumped before the cement to clean drilling mud out of the wellbore.
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1 While limited literature is available on construction flaws in wells that have been used in hydraulic
2 fracturing operations, several studies have examined construction flaws in oil and gas wells in
3 general. One study that examined reported drinking water contamination incidents in Texas
4 identified 10 incidents related to drilling and construction activities among 250,000 oil and gas
5 wells [Kell. 2011]. The study noted that many of the contamination incidents were associated with
6 wells that were constructed before Texas revised its regulations on cementing in 1969 (it is not
7 clear how old the wells were at the time the contamination occurred). Because this study relied on
8 reported incidents, it is possible that other wells exhibited integrity issues but did not result in
9 contamination of a drinking water well or were not reported. Therefore, this should be considered
10 a low-end estimate of the number of well integrity issues that could be tied directly to drilling and
11 construction activities. It is important to note that the 10 contamination incidents identified were
12 not associated with wells that were hydraulically fractured [Kell. 2011).
13 Several investigators have studied violations information from the PA DEP online violation
14 database to evaluate the rates of and possible factors contributing to well integrity problems,
15 including those related to cement. The results of these studies are summarized in Table 6-1. While
16 all of the studies shown in the table used the same database, their results vary, not only because of
17 the different time frames, but also because they used different definitions of what violations
18 constituted an integrity problem or failure. For example, Considine etal. [2012] considered all
19 events resulting in environmental damage—including effects such as erosion—and found a
2 0 relatively high violation rate. Davies etal. [2014] and Ingraffea et al. [2014] investigated violations
21 related to well integrity, while Vidicetal. [2013] looked only at well integrity violations that
22 resulted in fluid migration out of the wellbore; these more specific studies found relatively lower
23 violation rates. Olawoyin et al. [2013] performed a statistical analysis that weighted violations
24 based on risk and found that the most risky violations included those involving pits, erosion, waste
25 disposal, and blowout preventers.
Table 6-1. Results of studies of PA DEP violations data that examined well failure rates.
Study
Violations investigated
Data timeframe
Key findings3
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Study
Considine et al.
(2012)
Davies et al.
(2014)
Ingraffea et al.
(2014)
Vidicetal.
(2013)
Olawovin et al.
(2013)
Violations investigated
Violations resulting in
environmental damage
(3,533 wells studied)
Failure of one of the
barriers preventing fluid
migration (8,030 wells
studied)
Violations and inspection
records indicating
structural integrity loss
(3,391 wells studied)
Failure of cement/casing
that allowed fluid to leak
out (6,466 wells studied)
All violations (2,001 wells
studied)
Data timeframe
2008-2011
2005-2013
2000-2012
2008-2013
2008-2010
Key findings3
Of 845 environmental damage incidents (which
resulted in 1,144 violations), approximately 10%
were related to casing or cement problems. The
overall violation rate dropped from 52.9% of all
wells in 2008 to 20.8% of all wells in 2011.
Approximately 5% of wells received this type of
violation. The incident rate increased to 6.3%
when failures noted on forms, but not resulting
in violations, were included.
Wells in unconventional reservoirs experienced
a rate of structural integrity loss of 6.2%, while
the rate for conventional wells was 1%.
Approximately 3.4% of wells received this type
of violation.
Analysis of 2,601 violations from 65 operators
based on weighted risks found that potentially
risky violations increased 342% over the study
period, while total violations increased 110%.
a Note: While all of these studies used the same database, their results vary because they studied different time frames and
used different definitions of what violations constituted an integrity problem or failure.
1 Because a significant portion of Pennsylvania's recent oil and gas activity is in the Marcellus Shale,
2 many of the wells in these studies were most likely used for hydraulic fracturing. For example,
3 Ingraffea et al. [2014] found that approximately 16% of the oil and gas wells drilled in the state
4 between 2000 and 2012 were completed in unconventional reservoirs, and nearly all of these wells
5 were used for hydraulic fracturing. Wells drilled in unconventional reservoirs experienced higher
6 rates of structural integrity loss than conventional wells drilled during the same time period
7 [Ingraffea etal., 2014]. The authors did not compare rates of structural integrity loss in
8 conventional wells that were and were not used for hydraulic fracturing; they assumed that
9 unconventional wells were hydraulically fractured and conventional wells were not
10 Violation rates resulting in environmental pollution among all wells dropped from 52.9% in 2008
11 to 20.8% in 2011 [Considine etal.. 2012]. and the drop may be due to a number of factors.
12 Violations related to failure of cement or other well components represented a minority of all well
13 violations. Of 845 events that caused environmental contamination, including but not limited to
14 contamination of drinking water resources, Considine etal. [2012] found that about 10% (85
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1 events) were related to casing and cement problems. The rest of the incidents were related to site
2 restoration and spills (the violations noted are confined to those incidents that caused
3 environmental damage i.e., the analysis excluded construction flaws that did not have adverse
4 environmental effects).
5 Another source of information on contamination caused by wells is positive determination letters
6 (PDLs) issued by the PA DEP. PDLs are issued in response to a complaint when the state determines
7 that contamination did occur in proximity to oil and gas activities. The PDLs take into account the
8 impact, timing, well integrity, and formation permeability; however, liability is presumed for wells
9 within a given distance if the oil and gas operator cannot refute that they caused the contamination,
10 based on pre-drilling sampling [Brantley etal.. 2014).' Brantley et al. [2014) examined these PDLs,
11 and concluded that approximately 2 0 unconventional gas wells impacted water supplies between
12 2008 and 2012; this equates to 0.1% to 1% of the 6,061 wells spudded between 2008 and 2012 (it
13 is unclear exactly how many PDLs are linked to an individual well). While these oil and gas wells
14 were linked to contamination of wells and springs, the mechanisms for the impacts (including
15 whether fluids may have been spilled at the surface or if there was a pathway through the well or
16 through the subsurface rock formation to the drinking water resource) were not described by
17 Brantley et al. (2014). We did not perform a full and independent review of the PDLs for this
18 assessment
19 While the studies discussed above present possible explanations for higher violation incidences in
2 0 hydraulically fractured wells, it should be noted that other explanations that are not specific to
21 hydraulic fracturing are also possible. These could include different inspection protocols and
2 2 different formation types.
23 Cementing in horizontal wells, which are commonly hydraulically fractured, presents challenges
24 that can contribute to higher rates of integrity issues. The observation by Ingraffea et al. (2014) that
25 wells drilled in unconventional reservoirs experience higher rates of structural integrity loss than
26 conventional wells is supported by conclusions of Sabins (1990), who noted that horizontal wells
27 have more cementing problems because they are more difficult to center properly and can be
28 subject to settling of solids on the bottom of the wellbore. Cementing in horizontal wells presents
29 challenges that can contribute to higher rates of integrity issues.
30 Thermal and cyclic stresses caused by intermittent operation also may stress cement (King and
31 King. 2013: Ali etal.. 2009). Increased pressures and cyclic stresses associated with hydraulic
32 fracturing operations can contribute to cement integrity losses and, if undetected, small integrity
33 problems can lead to larger ones. Temperature differences between the (typically warmer)
34 subsurface environment and the (typically cooler) injected fluids, followed by contact with the
35 (typically warmer) flowback water, can lead to contraction of the well materials (both casing and
36 cement), which introduces additional stresses. Similar temperature changes may occur when
1 Under Pennsylvania's Oil and Gas Act, operators of oil or gas wells are presumed liable if water supplies within 1,000 ft
(305 m) were impacted within 6 months of drilling, unless the claim is rebutted by the operator; this was expanded to
2,500 ft (762 m) and 12 months in 2012.
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1 multiple fracturing stages are performed. Because the casing and cement have different mechanical
2 properties, they may respond differently to these stress cycles and debond.
3 Several studies illustrate the effects of cyclic stresses. Dusseault et al. [2000] indicate that wells that
4 have undergone several cycles of thermal or pressure changes will almost always show some
5 debonding between cement and casing. Microannuli formed by this debonding can be conduits for
6 gas migration, in particular because the lighter density of gas provides a larger driving force for
7 migration through the microannuli than for heavier liquids.: One laboratory study indicated that
8 microannuli on the order of 0.01 in (0.3 mm) could increase effective cement permeability from
9 1 nD (1 x 10-21 m2) in good quality cement up to 1 mD (1 x IQ-IS m2) [Bachu and Bennion. 2009].
10 This six-order magnitude increase in permeability shows that even small microannuli can
11 significantly increase the potential for flow through the cement Typically, these microannuli form
12 at the interface between the casing and cement or between the cement and formation. Debonding
13 and formation of microannuli can occur through intermittent operation, pressure tests, and
14 workover operations [Dusseault etal., 2000].2 While a small area of debonding may not lead to fluid
15 migration, the microannuli in the cement that result from the debonding can serve as initiation
16 points for fracture propagation if re-pressurized gas enters the microannulus [Dusseault etal.,
17 20001
18 The Council of Canadian Academies [2014] found that the repetitive pressure surges that occur
19 during the fracturing process would make maintaining an intact cement seal more of a challenge in
20 wells that are hydraulically fractured. Wang and Dahi Taleghani [2014] performed a modeling
21 study that showed that hydraulic fracturing pressures could initiate annular cracks in cement.
22 Another study of well data indicated that cement failure rates are higher in intermediate casings
23 compared to other casings [McDaniel etal., 2014]. The failures occurred after drilling and
24 completion of wells, and the authors surmised that the cement failures were most likely due to
25 cyclical pressure stresses caused by drilling. Theoretically, such cyclical pressure events could also
26 be experienced during multiple stage hydraulic fracturing. Mechanical stresses associated with well
27 operation or workovers and pressure tests also may lead to small cracks in the cement, which may
28 provide migration pathways for fluid.
29 Corrosion can lead to cement failure. Cement can fail to maintain integrity as a result of degradation
30 of the cement after the cement is set Cement degradation can result from attack by corrosive brines
31 or chemicals such as sulfates, sulfides, and carbon dioxide that exist in formation fluids [Renpu,
32 2011]. These chemicals can alter the chemical structure of the cement, resulting in increased
33 permeability or reduced strength and leading to loss of cement integrity over time. Additives or
34 specialty cements that can decrease cement susceptibility to specific chemical components are
35 available.
1 Microannuli can also form due to an inadequate cement job, e.g., poor mud removal or improper cement placement rate.
2 A workover refers to any maintenance activity performed on a well that involves ceasing operations and removing the
wellhead. Depending on the purpose of the workover and the tools used, workovers may induce pressure changes in the
well.
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6.2.2.3. Sustained Casing Pressure
1 An example of how the issues related to casing and cement discussed in the preceding sections can
2 work together and be difficult to differentiate can be seen in the case of sustained casing pressure.:
3 Sustained casing pressure is an indicator that pathways within the well related to the well's casing,
4 cement, or both allowed fluid movement to occur. Sustained casing pressure can result from casing
5 leaks, uncemented intervals, microannuli, or some combination of the three, which can be an
6 indication that a well has lost integrity. Sustained casing pressure can be observed when an annulus
7 (either the annulus between the tubing and production casing or between any two casings) is
8 exposed to a source of nearly continuous elevated pressure. Goodwin and Crook [1992] found that
9 sudden increases in sustained casing pressure occurred in wells that were exposed to high
10 temperatures and pressures. Subsequent logging of these wells showed that the high temperatures
11 and pressures led to shearing of the cement/casing interface and a total loss of the cement bond.
12 Sustained casing pressure occurs more frequently in older wells and horizontal or deviated wells.
13 One study found that sustained casing pressure becomes worse as a well ages. Sustained casing
14 pressure was found in less than 10% of wells that were less than a year old, but was present in up
15 to 50% of 15-year-old wells [Brufatto etal.. 2003). While these wells may not have been
16 hydraulically fractured, the study demonstrates that older wells can exhibit more integrity
17 problems. Watson and Bachu [2009] found that a higher portion of deviated wells had sustained
18 casing pressure compared to vertical wells. Increased pressures, cyclic stresses [Syed and Cutler,
19 2010]. and difficulty in cementing horizontal wells [Sabins. 1990] also may lead to increased
20 instances of sustained casing pressure in wells where hydraulic fracturing occurs [Muehlenbachs et
21 al.. 2012: Rowe and Muehlenbachs. 1999].
22 Sustained casing pressure can be a concern for several reasons. If the pressures are allowed to build
23 up to above the burst pressure of the exterior casing or the collapse pressure of the interior casing,
24 the casing may fail. Increased pressure can also cause gas or liquids to enter lower-pressured
25 formations that are exposed to the annulus either through leaks or uncemented sections.
26 Laboratory experiments by Harrison [1985] demonstrated that over-pressurized gas in the annulus
27 could cause rapid movement of gas into drinking water resources if a permeable pathway exists
28 between the annulus and the ground water. Over-pressurization of the annulus can be avoided by
29 venting the annulus to the atmosphere.
30 In a few cases, sustained casing pressure in wells that have been hydraulically fractured may have
31 been linked to drinking water contamination, although it is challenging to definitively determine
32 the actual cause. In one study in northeastern Pennsylvania, hydrocarbon and isotope
33 concentrations were used to investigate stray gas migration into domestic drinking water [U.S. EPA,
i Sustained casing pressure is pressure in any well annulus that is measurable at the wellhead and rebuilds after it is bled
down, not caused solely by temperature fluctuations or imposed by the operator fSkierven etal.. 2011). If the pressure is
relieved by venting natural gas from the annulus to the atmosphere, it will build up again once the annulus is closed (i.e.,
the pressure is sustained). The return of pressure indicates that there is a small leak in a casing or through uncemented or
poorly cemented intervals that exposes the annulus to a pressured source of gas that is actively being used. It is possible
to have pressure in more than one of the annuli.
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1 20141]. While the composition of the gas in the water wells was consistent with that of the gas
2 found in nearby gas wells with high casing pressures, other possible sources of the gas could not be
3 ruled out. Several gas wells in the study area were cited by the PA DEP for having elevated casing
4 annulus pressures. In another example in Alberta, Canada, 14% of wells drilled since 1971 have
5 shown serious sustained casing flow, defined as more than 10,594 ft3 (300 m3)/day atpressures
6 higher than 0.48 psi/ft (11 kPa/m) times the surface casing depth (Tackson and Dussealt, 2014].
7 Another study in the same area found gas in nearby drinking water wells had a composition that
8 was consistent with biogenic methane mixing with methane from nearby coalbed methane and
9 deeper natural gas fields (Tilley and Muehlenbachs, 2012].
10 Adequate well design, detection (i.e., through annulus pressure monitoring], and repair of sustained
11 casing pressure reduce the potential for fluid movement. Watson and Bachu (2009] found that
12 regulations that required monitoring and repair of sustained casing vent flow or sustained casing
13 pressure had a positive effect on lowering leak rates. The authors also found that wells initially
14 designed for injection experienced sustained casing pressure less often than those that were
15 retrofitted (Watson and Bachu. 2009].
16 Another study in Mamm Creek, Colorado, obtained similar results. The Mamm Creek field is in an
17 area where lost cement and shallow, gas-containing formations are common. A number of wells in
18 the area have experienced sustained casing pressure, and methane has been found in several
19 drinking water wells along with seeps into local creeks and ponds. In one well, four pressured gas
2 0 zones were encountered during well drilling and there was a lost cement incident, which resulted
21 in the cement top being more than 4,000 ft (1,219 m] lower than originally intended. Due to high
22 measured bradenhead pressure (661 psi, or 4.6 MPa], cement remediation efforts were
23 implemented (Crescent. 2011: COGCC. 2004]. The operator of this well was later cited by the
24 Colorado Oil and Gas Conservation Commission (COGCC] for causing natural gas and benzene to
25 seep into a nearby creek. The proposed route of contamination was contaminants flowing up the
26 well annulus and then along a fault. The proposed contamination route appeared to be validated
27 because, once remedial cementing was performed on the well, methane and benzene levels in the
28 creek began to drop (Science Based Solutions LLC, 2014]. In response to the incident, the state
29 instituted requirements to identify and cement above the top of the highest gas-containing
30 formation and to monitor casing pressures after cementing.
31 Not every well that shows positive pressure in the annulus poses a potential problem. Sustained
32 pressure is only a problem when it exceeds the ability of the wellbore to contain it or when it
33 indicates downhole communication problems (TIPRO, 2012]. A variety of management options are
34 available for managing such pressure including venting, remedial cementing, and use of kill fluids in
35 the annulus (TIPRO. 2012].l
1 A kill fluid is a weighted fluid with a density that is sufficient to overcome the formation pressure and prevent fluids
from flowing up the wellbore.
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6.3. Fluid Migration Associated with Induced Fractures within Subsurface
Formations
1 In this section, we discuss potential pathways for fluid movement associated with induced fractures
2 and subsurface geologic formations (outside of the well system described in Section 6.2). We
3 examine the potential for fluid migration into drinking water resources by evaluating the
4 development of migration pathways within subsurface formations, the flow of injected and
5 formation fluids, and important factors that affect these processes.:
6 Fluid movement requires both a physical conduit (e.g., the permeable matrix pore volume or a
7 fracture in the rock) and a driving force.2 In subsurface rock formations, fluid movement is driven
8 by the existence of a hydraulic gradient depending on elevation and pressure, which is also
9 influenced by fluid density, composition, and temperature (Finder and Celia. 2006). Pressure
10 differentials in the reservoir and density-driven fluid buoyancy are the key forces governing fluid
11 migration during and after hydraulic fracturing operations. Pressure differentials depend upon the
12 initial conditions within these formations and are directly influenced by pressures that are created
13 by injection or production regimes. Buoyancy depends on density differences among and between
14 gases and liquids, and it causes fluid migration when and where these density differences exist
15 along with a pathway (Finder and Gray, 2008).
16 As hydraulic fracturing takes place, injected fluids leaving the well create fractures within the
17 production zone and enter the formation through the newly created fractures. Unintended fluid
18 migration may result from this fracturing process. Migration pathways to drinking water resources
19 could develop as a result of changes in the subsurface flow or pressure regime associated with
20 hydraulic fracturing; via fractures that extend beyond the intended formation or that intersect
21 existing natural faults or fractures; or via fractures that intersect offset wells or other artificial
22 structures (Jackson etal.. 2013c). These subsurface pathways may facilitate the migration of fluids
23 by themselves or in conjunction with the well-based pathways described in Section 6.2. Fluids
24 potentially available for migration include both fluids that are injected into the well (including
25 leakoff) and formation fluids (including brine or natural gas).3
1 A subsurface formation (also referred to as a "formation" throughout this section) is a mappable body of rock of
distinctive rock type(s), including the rock's pore volume (i.e., the void space within a formation that fluid flow can occur,
as opposed to the bulk volume which includes both pore and solid phase volume), with a unique stratigraphic position.
2 Permeability (i.e., intrinsic or absolute permeability) of formations describes the ability of water to move through the
formation matrix, and it depends on the rock's grain size and the connectedness of the void spaces between the grains.
Where multiple phases of fluids exist in the pore space, the flow of fluids also depends on relative permeabilities.
3 Leakoff is the fraction of the injected fluid that infiltrates into the formation and is not recovered during production
(Economides et al.. 2007).
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1 The potential for subsurface fluid migration into drinking water resources can be evaluated during
2 two different time periods [Kim and Moridis. 2015]:
3 1. Following the initiation of fractures within the reservoir prior to any production, when the
4 injected fluid, pressurizing the formation, flows through the fractures and the fractures
5 grow into the reservoir. Fluid leaks off into the formation, allowing the fractures to close
6 except where they are held open by the proppant [Adachi et al., 2007].
7 2. During the production period, after fracturing is completed and pressure in the fractures is
8 reduced, and hydrocarbons (along with produced water] flow from the reservoir into the
9 well.
10 Note that these two time periods vary in duration. As described in Chapter 2, the first period of
11 fracture creation and propagation (i.e., the hydraulic fracturing itself] is a relatively short-term
12 process, typically lasting 2 to 10 days, depending on the number of stages in the fracture treatment
13 design. On the other hand, operation of the well for production covers a substantially longer period
14 (depending on many factors such as the amount of hydrocarbons in place and economic
15 considerations], and can be as long as 40 or 60 years in onshore tight gas reservoirs (Ross and King,
16 2007].
17 The following discussion of potential subsurface fluid migration into drinking water resources
18 focuses primarily on the physical movement of fluids and the factors that affect this movement.
19 Section 6.3.1 describes the basic principles of subsurface fracture creation, geometry, and
2 0 propagation, to provide context for the discussion of potential fluid migration pathways in Section
21 6.3.2. Geochemical and biogeochemical reactions among injected fluids, formation fluids, subsurface
22 microbes, and rock formations are another important component of subsurface fluid migration and
23 transport. See Chapter 7 for a discussion of the processes that affect pore fluid biogeochemistry and
24 influence the chemical and microbial composition of flowback and produced water.
6.3.1. Overview of Subsurface Fracture Growth
25 Fracture initiation and growth is a highly complex process due to the heterogeneous nature of the
26 subsurface environment It depends on the geomechanical characteristics of rock formations, fluid
27 properties, pore pressures, and subsurface stress fields. As shown in Figure 6-4, fracture formation
28 is controlled by the three in situ principal compressive stresses: the vertical stress (Si/], the
29 maximum horizontal stress (Sn), and the minimum horizontal stress (S/,]. During hydraulic
30 fracturing, pressurized fluid injection creates high pore pressures around the well. When the
31 pressure exceeds the local least principal stress and the tensile strength of the rock, failure results
32 and fractures form fZoback. 2010: FiaeretaL 20081
33 Fractures propagate (increase in length] in the direction of the maximum principal stress, which is
34 perpendicular to the direction of the least principal stress. Deep in the subsurface, the maximum
35 principal stress is generally in the vertical direction because the overburden (the weight of
36 overlying rock] is the largest single stress. Therefore, in deep formations, the local least principal
37 stress is the minimum horizontal stress (S/,], and the principal fracture orientation is expected to be
38 vertical. This is the scenario illustrated in Figure 6-4. At shallower depths, where the rock is
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1 subjected to less pressure from the overburden, more fracture propagation is expected to be in the
2 horizontal direction. Using tiltmeter data from over 10,000 fractures in various North American
3 reservoirs, Fisher and Warpinski [2012] found that fractures at approximately 4,000 ft (1,220 m)
4 below the surface or deeper are primarily vertical (see below for more information on tiltmeters).
5 Between approximately 4,000 and 2,000 ft (1,220 and 610 m), fracture complexity increases, and
6 fractures at approximately 2,000 ft (610 m) or shallower are primarily horizontal (Fisher and
7 Warpinski. 2012].1 Horizontal fracturing can also occur in deeper settings in some less-common
8 reservoir environments where the principal stresses have been altered by salt intrusions or similar
9 types of geologic activity (Tones and Britt, 2009].
Figure 6-4. Hydraulic fracture planes (represented as ovals), with respect to the principal
subsurface compressive stresses: Sv (the vertical stress), SH (the maximum
horizontal stress), and S/, (the minimum horizontal stress).
At depths greater than approximately 2,000 ft (610 m), the principal fracture orientation is expected
to be vertical, as fractures propagate in the direction of SH.
1 Fracture complexity is the ratio of horizontal-to-vertical fracture volume distribution, as defined by Fisher and
Warpinski (2012). Fracture complexity is higher in fractures with a larger horizontal component.
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1 In addition to the principal subsurface stresses, other geomechanical and reservoir characteristics
2 and operational factors affect fracture creation, geometry, and propagation.1 These include initial
3 reservoir pressure and saturation, injected fluid pressure or injection rate, geomechanical rock
4 characteristics, reservoir heterogeneity, tensile strength, fluid type within fractures, and reservoir
5 permeabilities [Kim and Moridis. 2015]. Fracture creation is a complex process that involves
6 interactions between multiple properties. For example, as described by Daneshy [2009], fracture
7 height depends on a combination of parameters and processes including the material properties of
8 geologic formations, pore pressures, stress differences in adjacent formations, shear failure
9 (slippage] at the fracture tip, and the reorientation of the fracture as it crosses an interface between
10 formations. Injection rates, the initial water saturation of the formation, and the type of fluid
11 injected also have effects on fracture creation and propagation [Kim and Moridis, 2015, 2013].
12 Numerical modeling techniques have been developed to describe fracture creation and propagation
13 and to provide a better understanding of this complex process [Kim and Moridis, 2013]. Modeling
14 hydraulic fracturing in shale or tight gas reservoirs requires integrating the physics of both flow
15 and geomechanics to account for fluid flow, fracture propagation, and dynamic changes in pore
16 volume and permeability. Some important flow and geomechanical parameters included in these
17 types of advanced models are: permeability, porosity, Young's modulus, Poisson's ratio, and tensile
18 strength, as well as heterogeneities associated with these parameters.2 Some investigations using
19 these models have indicated that the vertical propagation of fractures (due to tensile failure] may
20 be limited by shear failure, which increases the permeability of the formation and leads to greater
21 leakoff. These findings demonstrate that elevated pore pressure can cause shear failure, thus
22 further affecting matrix permeability, flow regimes, and leakoff (Daneshy. 2009]. Computational
23 investigations have also indicated that slower injection rates can increase the amount of leakoff
24 (Kim and Moridis. 2013].
25 In addition to their use in research settings, analytical and numerical modeling approaches are used
26 by oil and gas companies to design hydraulic fracturing treatments and predict the extent of
27 fractured areas (Adachietal.. 2007]. Specifically, modeling techniques are used to assess the
28 treatment's sensitivity to critical parameters such as injection rate, treatment volumes, fluid
29 viscosity, and leakoff. The industry models range from simpler (typically two-dimensional]
30 theoretical models to computationally more complicated and accurate three-dimensional models.
31 In addition to computational approaches, monitoring of hydraulic fracturing operations can provide
32 insights into fracture development Monitoring techniques involve both operational monitoring
33 methods and "external" methods that are not directly related to the production operation.
34 Operational monitoring refers to the monitoring of parameters including pressure, flow rate, fluid
35 density, and additive concentrations using surface equipment and/or downhole sensors (Eberhard,
36 2011]. This monitoring is conducted to ensure that the operation is proceeding as planned and to
i Fracture geometry refers to characteristics of the fracture such as height and aperture (width).
2 Young's modulus, a ratio of stress to strain, is a measure of the rigidity of a material. Poisson's ratio is a ratio of
transverse-to-axial (or latitudinal-to-longitudinal) strain, and it characterizes how a material is deformed under pressure.
See Zoback(2010) for more information on the geomechanical properties of reservoir rocks.
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1 determine if operational parameters need to be adjusted. Interpretation of pressure data can be
2 used to better understand fracture behavior [e.g.. Kim and Wang. 2014]. Anomalies in operational
3 monitoring data can also indicate whether an unexpected event has occurred, such as
4 communication with another well (see Section 6.3.2.3).
5 The volume of fluid injected is typically monitored to provide information on the volume and extent
6 of fractures created [Fiewelling etal., 2013]. However, numerical investigations have found that
7 reservoir gas flows into the fractures immediately after they open from hydraulic fracturing, and
8 injection pressurizes both gas and water within the fracture to induce further fracture propagation
9 [Kim and Moridis, 2015]. Therefore, the fracture volume can be larger than the injected fluid
10 volume. As a result, simple estimation of fracture volume based on the amount of injected fluid may
11 underestimate the growth of the vertical fractures, and additional information is needed to
12 accurately predict the extent of fracture growth.
13 External monitoring technologies can also be used to collect data on fracture characteristics and
14 extent during hydraulic fracturing and/or production. These monitoring methods can be divided
15 into near-wellbore and far-field techniques. Near-wellbore techniques include the use of tracers,
16 temperature logs, video logs, or caliper logs [Holditch. 2007]. However, near-wellbore techniques
17 and logs only provide information for, at most, a distance of two to three wellbore diameters from
18 the well and are, therefore, not suited for tracking fractures for their entire length [Holditch, 2007].
19 Far-field methods, such as microseismic monitoring or tiltmeters, are used if the intent is to
20 estimate fracture growth and height across the entire fractured reservoir area. Microseismic
21 monitoring involves placing one or more geophones in a position to detect the very small amounts
22 of seismic energy generated during subsurface fracturing [Warpinski, 2009].' Monitoring these
23 microseismic events gives an idea of the location and size of the fracture network, as well as the
24 orientation and complexity of fracturing [Fisher and Warpinski. 2012]. Tiltmeters, which measure
25 extremely small deformations in the earth, can be used to determine the direction and volume of
26 the fractures and, within certain distances from the well, to estimate their dimensions [Lecampion
27 etal.. 2005].
6.3.2. Migration of Fluids through Pathways Related to Fractures/Formations
28 As noted above, subsurface migration of fluids requires a pathway, induced or natural, with enough
29 permeability to allow fluids to flow, as well as a hydraulic gradient physically driving the fluid
30 movement. The following subsections describe and evaluate potential pathways for the migration
31 of fracturing fluids, hydrocarbons, or other formation fluids from producing formations to drinking
32 water resources. They also present cases where the existence of these pathways has been
33 documented. As described above, potential subsurface migration pathways for fluid flow out of the
34 production formation are categorized as follows: (1] flow of fluids into the production zone via
35 induced fractures and out of the production zone via flow through the formation, (2] fracture
36 overgrowth outof the production zone, (3] migration via fractures intersecting offsetwells and
1 Typical microseismic events associated with hydraulic fracturing have a magnitude on the order of -2.5 (negative two
and half) [Warpinski. 2009).
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1 other artificial structures, and (4) migration via fractures intersecting other geologic features.
2 Although these four potential pathways are discussed separately here, they may act in combination
3 with each other or in combination with pathways along the well (as discussed in Section 6.2) to
4 affect drinking water resources.
5 In many cases (depending on fracture depth, height, and direction), the distance between the
6 producing formation and the drinking water resource is one of the most important factors affecting
7 the possibility of fluid migration between these formations (Reagan et al.. 2 015: Tacksonetal..
8 2013c). This distance varies substantially among shale gas plays, coalbed methane plays, and other
9 areas where hydraulic fracturing takes place in the United States (see Table 6-2). Many hydraulic
10 fracturing operations target deep shale zones such as the Marcellus or Haynesville/Bossier, where
11 the vertical distance between the top of the shale formation and the base of drinking water
12 resources may be 1 mile (1.6 km) or greater. This is reflected in the Well File Review, which found
13 that the largest proportion of wells used for hydraulic fracturing—an estimated 6,200 wells
14 (27%)—had 5,000 to 5,999 ft (1,524 to 1,828 m) of measured distance along the wellbore between
15 the induced fractures and the reported base of protected ground water resources (U.S. EPA,
16 2015O).1 However, as shown in Table 6-2, operations in the Antrim and the New Albany plays take
17 place at relatively shallower depths, with distances of 100 to 1,900 ft (30 to 579 m) between the
18 producing formation and the base of drinking water resources. The Well File Review indicated that
19 20% of wells used for hydraulic fracturing (an estimated 4,600 wells) were located in areas with
20 less than 2,000 ft (610 m) between the fractures and the base of protected ground water resources
21 (U.S. EPA, 2015o). In coalbed methane plays, which are typically shallower than shale gas plays,
22 these separation distances can be even smaller. For example, in the Raton Basin of southern
23 Colorado and northern New Mexico, approximately 10% of coalbed methane wells have less than
24 675 ft (206 m) of separation between the gas wells' perforated intervals and the depth of local
25 water wells. In certain areas of the basin, this distance is less than 100 ft (30 m) (Watts. 2006).
2 6 Some hydraulic fracturing operations are conducted within formations that contain drinking water
27 resources (see Table 6-2). One example of hydraulic fracturing taking place within a geologic
28 formation that is also used as a drinking water source is in the Wind River Basin in Wyoming
29 fWYOGCC. 2014: Wright etal.. 20121 Vertical gas wells in this area target the lower Eocene Wind
30 River Formation and the underlying Paleocene Fort Union Formation, which consist of interbedded
31 layers of sandstones, siltstones, and mudstones. The Wind River Formation also serves as the
32 principal source of domestic, municipal, and agricultural water in this rural area. Hydraulic
33 fracturing in rock formations that meet a state or federal definition of an underground source of
34 drinking water is also known to take place in coalbed methane operations in the Raton Basin (U.S.
35 EPA. 20151). in the Powder River Basin of Montana and Wyoming (as described in Chapter 7), and
36 in several other coalbed methane plays. In one field in Alberta, Canada, there is evidence that
37 fracturing in the same formation as a drinking water resource (in combination with well integrity
1 In the Well File Review, measured depth represents length along the wellbore, which may be a straight vertical distance
below ground or may follow a more complicated path, if the wellbore is not straight and vertical.
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1 problems; see Section 6.2.2.2) led to gas migration into water wells [Tilley and Muehlenbachs,
2 2012]. However, no information is available on other specific incidents of this type.
Table 6-2. Comparing the approximate depth and thickness of selected U.S. shale gas plays
and coalbed methane basins.
Shale data are reported in GWPC and ALL Consulting (2009) and NETL(2013); coalbed methane data
are reported in ALL Consulting (2004) and U.S. EPA (2004). See Figures 2-2 and 2-4 in Chapter 2 for
information on the locations of these basins, plays, and formations.
Basin/play/formation3
Approx. depth
(ft [m] below surface)
Approx. net thickness
(ft [m])
Distance between top of
production zone and base of
treatable water (ft [m])
Shale plays
Antrim
Barnett
Eagle Ford
Fayetteville
Haynesville- Bossier
Marcellus
New Albany
Woodford
600 to 2,200
[183 to 671]
6,500 to 8,500
[1,981 to 2,591]
4,000 to 12,000
[1,219 to 3,658]
1,000 to 7,000
[305 to 2, 134]
10,500 to 13,500
[3,200 to 4, 115]
4,000 to 8,500
[1,219 to 2,591]
500 to 2,000
[152 to 610]
6,000 to 11,000
[1,829 to 3,353]
70 to 120
[21 to 37]
100 to 600
[30 to 183]
250
[76]
20 to 200
[6 to 61]
200 to 300
[61 to 91]
50 to 200
[15 to 61]
50 to 100
[15 to 30]
120 to 220
[37 to 67]
300 to 1,900
[91 to 579]
5,300 to 7,300
[1,615 to 2,225]
2,800 to 10,800
[853 to 3,292]
500 to 6,500
[152 to 1,981]
10, 100 to 13, 100
[3,078 to 3,993]
2, 125 to 7,650
[648 to 2,332]
100 to 1,600
[30 to 488]
5,600 to 10,600
[1,707 to 3,231]
Coalbed methane basins
Black Warrior
(Upper Pottsville)
Powder River
(Fort Union)
Raton (Vermejo
and Raton)
San Juan (Fruitland)
0 to 3,500
[0 to 1,067]
450 to >6,500
[137 to 1,981]
< 500 to > 4, 100
[< 152 to > 1,250]
550 to 4,000
[168 to 1,219]
< 1 to > 70
[21]
75
[23]
10 to >140
[3 to >43]
20 to 80
[6 to 24]
As little as zero
As little as zerob
As little as zerob
As little as zero
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Basin/play/formation3
Approx. depth
(ft [m] below surface)
Approx. net thickness
(ft [m])
Distance between top of
production zone and base of
treatable water (ft [m])
a For coalbed methane, values are given for the specific coal units noted in parentheses.
b Formation fluids in producing formations meet the definition of drinking water in at least some areas of the basin.
1 The overall frequency of occurrence of hydraulic fracturing in aquifers that meet the definition of
2 drinking water resources across the United States is unknown. Some information, however, that
3 provides insights on the occurrence and geographic distribution of this practice is available.
4 According to the Well File Review, an estimated 0.4% of the 23,200 wells represented in that study
5 had perforations used for hydraulic fracturing that were placed shallower than the base of the
6 protected ground water resources reported by well operators [U.S. EPA, 2015O].1 An analysis of
7 produced water composition data maintained by the U.S. Geological Survey (USGS) provides insight
8 into the geographic distribution of this practice. The USGS produced water database contains
9 results from analyses of samples of produced water collected from more than 8,500 oil and gas
10 production wells in unconventional formations (coalbed methane, shale gas, tight gas, and tight oil)
11 within the continental United States.2 Just over 5,000 of these samples, which were obtained from
12 wells located in 37 states, reported total dissolved solids (TDS) concentrations. Because the
13 database does not track whether samples were from wells that were hydraulically fractured, we
14 selected samples from wells that were more likely to have been hydraulically fractured by
15 restricting samples to those collected in 1950 or later and to those that were collected from wells
16 producing from tight gas, tight oil, shale gas, or coalbed methane formations. This yielded 1,650
17 samples from wells located in Alabama, Colorado, North Dakota, Utah, and Wyoming.3'4 The TDS
18 concentrations among these samples ranged from approximately 90 mg/L to 300,000 mg/L.
19 Samples from approximately 1,200 wells in Alabama, Colorado, Utah, and Wyoming reported TDS
20 concentrations at or below 10,000 mg/L. This analysis, in conjunction with the result from the Well
21 File Review, suggests that, while the overall frequency of occurrence may be low, the activity may
22 be concentrated in some areas of the country.
1 The 95% confidence interval reported in the Well File Review indicates that this phenomenon could have occurred in as
few as 0.1% of the wells or in as many as 3% of the wells.
2 We used the USGS Produced Water Geochemical Database Version 2.1 (USGS database v 2.1) for this analysis
[http://energy.cr.usgs.gov/prov/prodwat/). The database is comprised of produced water samples compiled by the USGS
from 25 individual databases, publications, or reports.
3 See Chapter 2, Text Box 2-1, which describes how commercial hydraulic fracturing began in the late 1940s.
4 For this analysis, we assumed that produced water samples collected in 1950 or later from shale gas, tight oil, and tight
gas wells were from wells that had been hydraulically fractured. To estimate which coal bed methane wells had been
hydraulically fractured, we matched API numbers from coal bed methane wells in the USGS database v 2.1 to the same API
numbers in the commercial database Drillinglnfo, in which hydraulically fractured wells had been identified by EPA using
the assumptions described in Section 2.3.1. Wells with seemingly inaccurate (i.e., less than 12 digit) API numbers were
also excluded. Only coalbed methane wells from the USGS database v 2.1 that matched API numbers in the Drillinglnfo
database were retained for this analysis.
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6.3.2.1. Flow of Fluids Out of the Production Zone
1 One potential pathway for fluid migration out of the production formation into drinking water
2 resources is flow of injected fluids (or displacement of formation fluids due to injection) through
3 the formation matrix during or after a hydraulic fracturing treatment. In deep, low-permeability
4 shale and tight gas settings and where induced fractures are contained within the production zone,
5 flow through the production formation has generally been considered an unlikely pathway for
6 migration into drinking water resources [Jackson etal.. 2013c]. However, there is limited
7 information available on the fate of injected fluids that are not recovered during production (i.e.,
8 leakoff) or displaced formation fluids for cases where hydraulic fracturing takes place within or
9 close to drinking water resources.
10 Leakoff into shale gas formations may be as high as 90% or more of the injected volume (see
11 Section 7.2 and Table 7-2). The actual amount of leakoff depends on the amount of injected fluid,
12 the hydraulic properties of the reservoir (e.g., permeability), the capillary pressure near the
13 fracture faces, and the period of time the well is shut in following hydraulic fracturing before the
14 start of production (Kim etal.. 2014: Byrnes. 2011). '-2 However, despite the potentially large
15 volume of fluid that may be lost into the formation, the flow of this fluid is generally controlled or
16 limited by processes such as imbibition by capillary forces and adsorption onto clay minerals
17 (Duttaetal.. 2014: Dehghanpour etal.. 2013: Dehghanpour etal.. 2012: Roychaudhuri etal.. 2011).3
18 It has been suggested that these processes can sequester the fluids in the producing formations
19 permanently or for geologic time scales (Engelder, 2012: Byrnes, 2011).
20 A limited number of studies in the literature have evaluated a combination of certain conditions
21 that can facilitate migration of fluids despite these processes.. Myers (2012b) suggests that
22 migration of injected and/or formation fluids into the overburden may be possible in cases where
23 there is a significant vertical hydraulic gradient, sufficient permeability, density-driven buoyancy,
24 and the displacement of formation brines by large volumes of injected fluid. Flewelling and Sharma
25 (2014) note that, for migration to occur, an upward hydraulic gradient would be necessary,
26 particularly for brine that is denser than the ground water in the overlying formations; in the case
27 of natural gas, though, buoyancy would provide an upward flux A limited number of studies in the
28 literature have evaluated a combination of certain conditions that can facilitate migration of fluids
29 despite these processeSi Myers (2012b) suggests that migration of injected and/or formation fluids
30 into the overburden may be possible in cases where there is a significant vertical hydraulic
31 gradient, sufficient permeability, density-driven buoyancy, and the displacement of formation
1 Relative permeability is a dimensionless property allowing for the comparison of the different abilities of fluids to flow
in multiphase settings. If a single fluid is present, its relative permeability is equal to 1, but the presence of multiple fluids
generally inhibits flow and decreases the relative permeability (Schlumberger. 2014).
2 Shutting in the well after fracturing allows fluids to move farther into the formation, resulting in a higher gas relative
permeability near the fracture surface and improved gas production [Bertoncello etal.. 2014).
3 Imbibition is the displacement of a nonwetting fluid (i.e., gas) by a wetting fluid (typically water). The terms wetting or
nonwetting refer to the preferential attraction of a fluid to the surface. In typical reservoirs, water preferentially wets the
surface, and gas is nonwetting. Capillary forces arise from the differential attraction between immiscible fluids and solid
surfaces; these are the forces responsible for capillary rise in small-diameter tubes and porous materials. These
definitions are adapted from Pake (1978).
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1 brines by large volumes of injected fluid. Flewelling and Sharma [2014] note that for migration to
2 occur, an upward hydraulic gradient would be necessary, particularly for brine that is denser than
3 the ground water in the overlying formations; in the case of natural gas, though, buoyancy would
4 provide an upward flux [Vengosh etal., 2014]. Some natural conditions could create this upward
5 hydraulic gradient in the absence of any effects from hydraulic fracturing [Flewelling and Sharma,
6 2014]. However, these natural mechanisms have been found to cause very low flow rates over very
7 long distances, yielding extremely small vertical fluxes in sedimentary basins—corresponding to
8 some estimated travel times of 100,000 to 100,000,000 years across a 328 ft (100 m] thick layer
9 with about 0.01 nD (1 x 10~23 m2] permeability [Flewelling and Sharma, 2014]. Furthermore,
10 fracturing fluid would likely be sequestered in the immediate vicinity of the fracture network due to
11 capillary tension [Engelder, 2012].
12 Over-pressurization of producing formations due to the injection of large amounts of fluid during
13 hydraulic fracturing may support the upward hydraulic gradient for fluid migration [Myers,
14 2012b]. Myers' modeling results suggest that significant pressure buildup that occurs at the
15 location of fluid injection may not return to pre-hydraulic fracturing levels for up to a year.
16 However, these findings have been disputed in the literature due to certain suggested limitations of
17 the original study (e.g., extensive simplification of the model, lack of accurate characterization of
18 regional flow, misrepresentation of saturation conditions in shale formations], and they have been
19 found to be physically implausible given the hydrogeologic characteristics of actual sedimentary
20 basins fCohen etal.. 2013: Fie welling etal.. 2013: VidicetaL 2013: Saiers and Earth. 20121 Some
21 researchers have also suggested that pressure perturbations due to hydraulic fracturing operations
22 are localized to the immediate vicinity of the fractures, due to the very low permeabilities of shale
23 formations [Flewelling and Sharma, 2014]. However, there are emerging studies indicating that
24 pressure impacts of hydraulic fracturing operations may extend farther than the immediate vicinity
25 and may create risk of induced seismicity [Skoumaletal.. 2015]. Following hydraulic fracturing
26 operations, a large-scale depressurization would be expected over the longer term due to
27 hydrocarbon production, which may counteract any short-term localized pressure effects of
28 hydraulic fracturing during production and cause fluids to flow primarily toward the fracture
29 network [Flewelling and Sharma, 2014].
30 In responses to these critiques, Myers [2013. 2012a] states that they do not prove his original
31 hypothesis or findings wrong, but instead highlight the need for complex three-dimensional
32 modeling and detailed data collection for improving the understanding of the process and risks to
33 drinking water resources. Myers [2013, 2012a] argues that, given the large volume of hydraulic
34 fracturing operations in formations such as the Marcellus, these formations would have to hold
35 very large volumes of water that would be imbibed into the shale. Furthermore, he notes that
36 migration of these fluids into overlying formations may be facilitated by existing fractures or out-of-
37 zone fracturing (as discussed in the following sections].
6.3.2.2. Fracture Overgrowth out of the Production Zone
3 8 Fractures that extend out of the intended production zone into another formation or an unintended
39 zone within the same formation could provide a potential fluid migration pathway into drinking
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1 water resources [Tacksonetal., 2013c]. This migration could occur either through the fractures
2 themselves or in connection with other permeable subsurface features or formations (see Figure
3 6-5). Such "out-of-zone fracturing" is undesirable from a production standpoint and may occur as a
4 result of inadequate reservoir characterization or fracture treatment design [Eisner etal., 2006].
5 Some researchers have noted that fractures growing out of the targeted production zone could
6 potentially contact other formations, such as higher conductivity sandstones or conventional
7 hydrocarbon reservoirs, which may create an additional pathway for potential migration into a
8 drinking water resource [Reagan etal.. 2015). In addition, fractures growing out of the production
9 zone could potentially intercept natural, preexisting fractures (discussed in Section 6.3.2.4) or
10 active or abandoned wells near the well where hydraulic fracturing is performed (discussed in
11 Section 6.3.2.3).
44-4^1 Naturally Occurring Fractures /^jjj^urf
Figure 6-5. Conceptualized depiction of potential pathways for fluid movement out of the
production zone: (a) induced fracture overgrowth into over- or underlying
formations; (b) induced fractures intersecting natural fractures; and (c) induced
fractures intersecting a transmissive fault.
Thickness and depth of production formation are important site specific factors for each operation.
12 The fracture's geometry (see Section 6.3.1) affects its potential to extend beyond the intended zone
13 and serve as a pathway to drinking water resources. Vertical heights of fractures created during
This document is a draft for review purposes only and does not constitute Agency policy.
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1 hydraulic fracturing operations have been measured in several U.S. shale plays, including the
2 Barnett, Woodford, Marcellus, and Eagle Ford, using microseismic and microdeformation field
3 monitoring techniques [Fisher and Warpinski. 2012). These data indicate typical fracture heights
4 extending from tens to hundreds of feet. Davies etal. [2012] analyzed this data set and found that
5 the maximum fracture height was 1,929 ft (588 m) and that 1% of the fractures had a height greater
6 than 1,148 ft (350 m). This may raise some questions about fractures being contained within the
7 producing formation, as some Marcellus fractures were found to extend for at least 1,500 ft
8 (477 m), while the maximum thickness of the formation is generally 350 ft (107 m) or less (MCOR.
9 2012]. However, the majority of fractures were found to have heights less than 328 ft (100 m],
10 suggesting limited possibilities for fracture overgrowth exceeding the separation between shale
11 reservoirs and shallow aquifers (Davies etal., 2012]. This is consistent with modeling results found
12 by Kim and Moridis (2015] and others, as described below. Where the producing formation is not
13 continuous horizontally, the lateral extent of fractures may also become important. For example, in
14 the Fisher and Warpinski (2012] data set, fractures were found to extend to horizontal lengths
15 greater than 1,000 ft (305m].
16 Results of National Energy Technology Laboratory (NETL] research in Greene County,
17 Pennsylvania, are generally consistent with those reported in the Fisher and Warpinski (2012] data
18 set Microseismic monitoring was used at six horizontal Marcellus Shale wells to identify the
19 maximum upward extent of brittle deformation caused by hydraulic fracturing (Hammacketal.,
20 2014]. At three of the six wells, fractures extending between 1,000 and 1,900 ft (305 and 579 m]
21 above the Marcellus Shale were identified. Overall, approximately 40% of the microseismic events
22 occurred above the Tully Limestone, the formation overlying the Marcellus Shale that is sometimes
23 referred to as an upper barrier to hydraulic fracture growth. However, all microseismic events were
24 at least 5,000 ft (1,524 m] below drinking water aquifers, as the Marcellus Shale is one of the
25 deepest target formations (see Table 6-2], and no impacts to drinking water resources or another
26 local gas-producing interval were identified. See Text Box 6-3 for more information on the Greene
27 County site.
28 Similarly, in Dunn County, North Dakota, there is evidence of out-of-zone fracturing in the Bakken
29 Shale (U.S. EPA. 201511. Atthe Killdeer site (see Section 6.2.2.1 and Chapter 5, Text Box 5-12],
30 fracturing fluids and produced water were released during a rupture of the casing at the Franchuk
31 44-20 SWH well. Water quality characteristics at two monitoring wells located immediately
32 downgradient of the Franchuk well reflected a mixing of local Killdeer Aquifer water with deep
33 formation brine. Ion and isotope ratios used for brine fingerprinting suggest that Madison Group
34 formations (which directly overlie the Bakken in the Williston Basin] were the source of the brine
35 observed in the Killdeer Aquifer, and the authors concluded that this provides evidence for out-of-
36 zone fracturing. Industry experience also indicates that out-of-zone fracturing may be fairly
37 common in the Bakken and that produced water from many Bakken wells has Madison Group
38 chemical signatures (Arkadakskiy and Rostron. 2013b. 2012b: Peterman etal.. 2012].
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Text Box 6-3. Monitoring at the Greene County, Pennsylvania, Hydraulic Fracturing Test Site.
1 Monitoring performed at the Marcellus Shale test site in Greene County, Pennsylvania, evaluated fracture
2 height growth and zonal isolation during and after hydraulic fracturing operations [Hammack et al.. 2014].
3 The site has six horizontally drilled and two vertical wells that were completed into the Marcellus Shale.
4 Pre-fracturing studies of the site included a 3D seismic survey to identify faults, pressure measurements, and
5 baseline sampling for isotopes; drilling logs were also run. Hydraulic fracturing occurred April 24 to May 6,
6 2012, and June 4 to 11, 2012. Monitoring at the site included the following:
7 • Microseismic monitoring was conducted during four of the six hydraulic fracturing jobs on the site,
8 using geophones placed in the two vertical Marcellus Shale wells. These data were used to monitor
9 fracture height growth above the six horizontal Marcellus Shale wells during hydraulic fracturing.
10 • Pressure and production data were collected from a set of vertical gas wells completed in Upper
11 Devonian/Lower Mississippian zones 3,800 to 6,100 ft (1,158 to 1,859 m] above the Marcellus. Data were
12 collected during and after the hydraulic fracturing jobs and used to identify any communication between
13 the fractured areas and the Upper Devonian/Lower Mississippian rocks.
14 • Chemical and isotopic analyses were conducted on gas and water produced from the Upper
15 Devonian/Lower Mississippian wells. Samples were analyzed for stable isotope signatures of hydrogen,
16 carbon, and strontium and for the presence of perfluorocarbon tracers used in 10 stages of one of the
17 hydraulic fracturing jobs to identify possible gas or fluid migration to overlying zones fSharmaetal.,
18 2014a: Sharma et al.. 2014b].
19 As of September 2014, no evidence was found of gas or brine migration from the Marcellus Shale [Hammack
20 etal..2Q14]. although longer-term monitoring will be necessary to confirm that no impacts to overlying zones
21 have occurred [Zhang et al., 2014al.
22 Extreme vertical fracture growth is generally considered to be limited by layered geological
23 environments and other physical constraints [Fisher and Warpinski. 2012: Daneshy. 2009]. For
24 example, differences in in situ stresses in layers above and below the production zone can restrict
25 fracture height growth in sedimentary basins [Fisher and Warpinski. 2012). High-permeability
26 layers near hydrocarbon-producing zones can reduce fracture growth by acting as a "thief zone"
27 into which fluids can migrate, or by inducing a large compressive stress that acts on the fracture [de
28 Pater and Dong. 2009. as cited in Fisher and Warpinski. 2012]. Although these thief zones may
29 prevent fractures from reaching shallower formations or growing to extreme vertical lengths, it is
30 important to note that they do allow fluids to migrate out of the production zone into these
31 receiving formations, which could potentially contain drinking water resources. A volumetric
32 argument has also been used to discuss limits of vertical fracture growth; that is, the volumes of
33 fluid needed to sustain fracture growth beyond a certain height would be unrealistic [Fisher and
34 Warpinski. 2012]. However, as described in Section 6.3.1, fracture volume can be greater than the
35 volume of injected fluid due to the effects of pressurized water combined with the effects of gas
36 during injection [Kim and Moridis, 2015]. Nevertheless, some numerical investigations suggest
37 that, unless unrealistically high pressures and injection rates are applied to an extremely weak and
38 homogeneous formation that extends up to the near surface, hydraulic fracturing generally induces
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1 stable and finite fracture growth in a Marcellus-type environment and the fractures are unlikely to
2 extend into drinking water resources [Kim and Moridis. 2015].
3 Modeling studies have identified other factors that affect the containment of fractures within the
4 producing formation. As discussed above, additional numerical analysis of fracture propagation
5 during hydraulic fracturing has demonstrated that contrasts in the geomechanical properties of
6 rock formations can affect fracture height containment [Gu and Siebrits, 2008] and that geological
7 layers present within shale gas reservoirs can limit vertical fracture propagation [Kim and Moridis.
8 2015]. Modeling and monitoring studies generally agree that physical constraints on fracture
9 propagation will prevent induced fractures from extending from deep zones directly into drinking
10 water resources [Kim and Moridis, 2015: Flewellingetal., 2013: Fisher and Warpinski, 2012].
11 Using a numerical simulation, Reagan etal. [2015] investigated potential short-term migration of
12 gas and water between a shale or tight gas formation and a shallower ground water unit. Migration
13 was assessed immediately after hydraulic fracturing and for up to a 2-year time period during the
14 production stage. The potential migration pathway was assumed to be a permeable fracture or fault
15 connecting the producing formation to the shallower ground water unit Such a pathway may be
16 either entirely hydraulically induced (due to fracture overgrowth in a case where the separation
17 distance is limited, as discussed below], or may be a smaller induced fracture connecting to a
18 natural, permeable fault or fracture (as discussed in Section 6.3.2.4]. For the purposes of this study,
19 the pathway was assumed to be pre-existing, and Reagan etal. (2015] did not model the fracturing
20 process itself.
21 The subsurface system evaluated in the modeling investigation included a horizontal well used for
22 hydraulic fracturing and gas production, the connecting fracture or fault between the producing
23 formation and the aquifer, and a shallow vertical water well in the aquifer (see Figure 6-5]. The
24 parameters and scenarios used in the study are shown in Table 6-3; two vertical separation
25 distances between the producing formation and the aquifer were investigated, along with a range of
26 production zone permeabilities and other variables used to describe four production scenarios. The
27 horizontal well was assigned a constant bottomhole pressure of half the initial pressure of the
28 target reservoir, not accounting for any over-pressurization from hydraulic fracturing. Over-
29 pressurization during hydraulic fracturing may create an additional driving force for upward
30 migration. Results of this investigation, which represents a typical production period, indicate a
31 generally downward water flow within the connecting fracture (from the aquifer through the
32 connecting fracture into the hydraulically induced fractures in the production zone] and some
33 upward migration of gas (Reagan etal., 2015]. In certain cases, gas breakthrough (i.e., the
34 appearance of gas at the base of the drinking water aquifer] was also observed. The key parameter
35 affecting migration of gas into the aquifer was the production regime, particularly whether gas
36 production, driving the fluid migration toward the production well, was occurring in the reservoir.
37 Simulations including a producing gas well showed only a few instances of breakthrough, while
38 simulations without gas production tended to result in breakthrough; these breakthrough times
39 ranged from minutes to 20 days. However, in all cases, the gas escape was limited in duration and
40 scope, because the amount of gas available for immediate migration toward the shallow aquifer was
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1 limited to that initially stored in the hydraulically induced fractures after the stimulation process
2 and prior to production. These simulations indicate that the target reservoir may not be able to
3 replenish the gas available for migration in hydraulically induced fractures prior to production.
Table 6-3. Modeling parameters and scenarios investigated by Reagan etal. (2015).
This table illustrates the range of parameters included in the Reagan et al. (2015) modeling study. See
Figure 6-5, Figure 6-6, and Figure 6-7 for conceptualized illustrations of these scenarios.
Model parameter or variable
Values investigated in model scenarios
All scenarios
Lateral distance from connecting feature to water well
Vertical separation distance between producing
formation and drinking water aquifer
Producing formation permeability range
Drinking water aquifer permeability
Initial conditions
Production well bottom hole pressure
Production regime
328 ft (100m)
656 ft (200 m);
2,625 ft (800 m)
lnD(lxlO"21m2);
100nD(lxlO"19m2);
lu.D(lxlO"18m2)
0.1D(lxlO"13m2);
lD(lxlO"12m2)
Hydrostatic
Half of the initial pressure of the producing formation
(not accounting for over-pressurization from hydraulic
fracturing)
Production at both the water well and the gas well;
Production at only the water well;
Production at only the gas well;
No production
Fracture pathway scenarios
Connecting feature permeability
lD(lxlO"12m2);
10D(lxlO"1:Lm2);
1,000 D (1 x 10"9 m2)
Offset well pathway scenarios
Lateral distance from production well to offset well
Cement permeability of offset well
33 ft (10 m)
1 u.D (1 x 10"18 m2);
lmD(lxlO"15m2);
lD(lxlO"12m2);
1,000 D (1 x 10"9 m2)
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1 Based on the results of the Reagan etal. [2015] study, gas production from the reservoir appears
2 likely to mitigate gas migration, both by reducing the amount of available gas and depressurizing
3 the induced fractures (which counters the buoyancy of any gas that may escape from the
4 production zone into the connecting fracture). Production at the gas well also creates pressure
5 gradients that drive a downward flow of water from the aquifer via the fracture into the producing
6 formation, increasing the amount of water produced at the gas well. Furthermore, the effective
7 permeability of the connecting feature is reduced during water (downward) and gas (upward)
8 counter-flow within the fracture, further retarding the upward movement of gas or allowing gas to
9 dissolve into the downward flow. In contrast, Reagan etal. (2015) found an increased potential for
10 gas release from the producing formation in cases where there is no gas production following
11 hydraulic fracturing. The potential for gas migration during shut-in periods following hydraulic
12 fracturing and prior to production may be more significant, especially when out-of-zone fractures
13 are formed. Without the producing gas well, the gas may rise via buoyancy, with any downward-
14 flowing water from the aquifer displacing the upward-flowing gas.
15 Reagan etal. (2015) also found that the permeability of a connecting fault or fracture may be an
16 important factor for the potential upward migration of gas (although not as significant as the
17 production regime). For the cases where gas escaped from the production zone, the maximum
18 amount of migrating gas depended upon the permeability of the connecting feature: the higher the
19 permeability, the larger the amount. The results also showed that lower permeabilities delay the
20 down ward flow of water from the aquifer, allowing the trace amount of gas that entered into the
21 fracture early in the modeled period to reach the aquifer, which was otherwise predicted to
22 dissolve in the water flowing downward in the feature. Similarly, the permeabilities of the target
23 reservoir, fracture volume, and the separation distance were found to affect gas migration, because
24 they affected the initial amount of gas stored in the hydraulically induced fractures. In contrast, the
25 permeability of the drinking water aquifer was not found to be a significant factor in their
26 assessment
6.3.2.3. Migration via Fractures Intersecting with Offset Wells and Other Artificial Structures
27 Another potential pathway for fluid migration is one in which injected fluids or displaced
28 subsurface fluids move through newly created fractures into an offset well or its fracture network,
29 resulting in well communication (Jackson etal.. 2013c). This may be a concern, particularly in
30 shallower formations where the local least principal stress is vertical (resulting in more horizontal
31 fracture propagation) and where there are shallow drinking water wells in the same formation.
32 The offset well can be an abandoned, inactive, or active well; if the well has also been used for
33 hydraulic fracturing, the fracture networks of the two wells might intersect The situation where
34 hydraulic fractures unintentionally propagate into other existing, producing hydraulic fractures is
35 referred to as a "frac hit" and is known to occur in areas with a high density of wells (Tacksonetal..
36 2013a). Figure 6-6 provides a schematic to illustrate fractures that intercept an offset well, and
37 Figure 6-7 depicts how the fracture networks of two wells can intersect
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Figure 6-6. Induced fractures intersecting an offset well (in a production zone, as shown, or in
overlying formations into which fracture growth may have occurred).
This image shows a conceptualized depiction of potential pathways for fluid movement out of the
production zone (not to scale).
Figure 6-7. Well communication (a frac hit) via induced fractures intersecting another well or
its fracture network.
This image shows a conceptualized depiction of potential pathways for fluid movement out of the
production zone (not to scale).
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1 Instances of well communication have been known to occur and are described in the oil and gas
2 literature. For example, an analysis of operator data collected by the New Mexico Oil Conservation
3 Division (NM OCD) in 2013-2014 identified 120 instances of well communication in the San Juan
4 Basin [Vaidyanathan, 2014]. In some cases, well communication incidents have led to documented
5 production and/or environmental problems. A study from the Barnett Shale noted two cases of well
6 communication, one with a well 1,100 ft (335 m) away and the other with a well 2,500 ft (762 m)
7 away from the initiating well; ultimately, one of the offset wells had to be re-fractured because the
8 well communication halted production (Craig etal.. 2012). In some cases, the fluids that intersect
9 the offset well flow up the wellbore and spill onto the surface. The EPA (2015n] recorded 10
10 incidents in which fluid spills were attributed to well communication events (see Chapter 7 for
11 more information).1 The subsurface effects of frac hits have not been extensively studied, but these
12 cases demonstrate the possibility of fluid migration via communication with other wells and/or
13 their fracture networks. More generally, well communication events may indicate fracture behavior
14 that was not intended by the treatment design.
15 A well communication event is usually observed at the offset well as a pressure spike, due to the
16 elevated pressure from the originating well, or as an unexpected drop in the production rate (Lawal
17 etal.. 2014: Tackson etal.. 2013a). Ajani and Kelkar (2012) performed an analysis of frac hits in the
18 Woodford Shale in Oklahoma, studying 179 wells over a 5-year period. The authors used fracturing
19 records from the newly completed wells and compared them to production records from
20 surrounding wells. The authors assumed that sudden changes in production of gas or water
21 coinciding with fracturing at a nearby well were caused by communication between the two wells,
22 and increased water production at the surrounding wells was assumed to be caused by fracturing
23 fluid flowing into these offset wells. The results of the Oklahoma study showed that 24 wells had
24 decreased gas production or increased water production within 60 days of the initial gas
25 production at the nearby fractured well. A total of 38 wells experienced decreased gas or increased
26 water production up to a distance of 7,920 ft (2,414 m), measured as the distance between the
27 midpoints of the laterals; 10 wells saw increased water production from as far away as 8,422 ft
28 (2,567 m). In addition, one well showed a slight increase in gas production rather than a decrease.2
29 Other studies of well communication events have relied on similar information. In the NM OCD
30 operator data set, the typical means of detecting a well communication event was through pressure
31 changes at the offset well, production lost at the offset well, or fluids found in the offset well. In
32 some instances, well operators determined that a well was producing fluid from two different
33 formations, while in one instance, the operator identified a potential well communication event due
34 to an increase in production from the offset well (Vaidyanathan. 2014). In another study, Tackson et
35 al. (2013a) found that the decrease in production due to well communication events was much
36 greater in lower permeability reservoirs. The authors note an example where two wells 1,000 ft
37 (305 m) apart communicated, reducing production in the offset well by 64%. These results indicate
38 that the subsurface interactions of well networks or complex hydraulics driven by each well at a
1 Line numbers 163,236,265,271,286,287, 375,376,377, and 380 in Appendix B of U.S. EPAf2015n).
2 The numbers of wells cited in the study reflect separate analyses, and the numbers cited are not additive.
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1 densely populated (with respect to wells) area are important factors to consider for the design of
2 hydraulic fracturing treatments and other aspects of oil and gas production.
3 The key factor affecting the likelihood of a well communication event and the impact of a frac hit is
4 the location of the offset well relative to the well where hydraulic fracturing was conducted [Ajani
5 andKelkar. 2012]. In the Ajani and Kelkar [2012] analysis, the likelihood of a communication event
6 was less than 10% in wells more than 4,000 ft (1,219 m] apart, but rose to nearly 50% in wells less
7 than 1,000 ft (305 m] apart Well communication was also much more likely with wells drilled from
8 the same pad. The affected wells were found to be in the direction of maximum horizontal stress in
9 the field, which correlates with the expected direction of fracture propagation.
10 Well communication may be more likely to occur where there is less resistance to fracture growth.
11 Such conditions may be related to existing production operations (e.g., where previous
12 hydrocarbon extraction has reduced the pore pressure, changed stress fields, or affected existing
13 fracture networks] or the existence of high-permeability rock units (Jackson etal.. 2013a]. As Ajani
14 and Kelkar (2012] found in the Woodford Shale, one of the deepest major shale plays (see Table
15 6-2], hydraulic fracturing treatments tend to enter portions of the reservoir that have already been
16 fractured as opposed to entering previously unfractured rocks, ultimately causing interference in
17 offset wells. Mukherjee etal. (2000] described this tendency for asymmetric fracture growth
18 toward depleted areas in low-permeability gas reservoirs due to pore pressure depletion from
19 production at offset wells. The authors note that pore pressure gradients in depleted zones would
20 affect the subsurface stresses. Therefore, depending on the location of the new well with respect to
21 depleted zone(s] and the orientation of the existing induced fractures, the newly created fracture
22 may be asymmetric, with only one wing of the fracture extending into the depleted area and
23 developing significant length and conductivity (Mukherjee etal., 2000]. The extent to which the
24 depleted area affects fracturing depends on factors such as cumulative production, pore volume,
25 hydrocarbon saturation, effective permeability, and the original reservoir or pore pressure
26 (Mukherjee etal., 2000]. Similarly, high-permeability rock types acting as thief zones may also
27 cause preferential fracturing due to a higher leakoff rate into these layers (Tacksonetal., 2013a].
28 In addition to location, the potential for impact on a drinking water resource also depends on the
29 condition of the offset well (see Section 6.2 for information on the integrity of well components]. In
30 their analysis, Ajani and Kelkar (2012] found a correlation between well communication and well
31 age: older wells were more likely to be affected. If the cement in the annulus between the casing
32 and the formation is intact and the well components can withstand the stress exerted by the
33 pressure of the fluid, nothing more than an increase in pressure and extra production of fluids may
34 occur during a well communication event. However, if the offset well is not able to withstand the
35 pressure of the fracturing fluid, well components may fail, allowing fluid to migrate out of the well.
36 The highest pressures most wells will face during their life spans occur during fracturing. In some
37 cases, temporary equipment is installed in wells during fracturing to protect the well against the
38 increased pressure. Therefore, many producing wells may not be designed to withstand pressures
39 typical of hydraulic fracturing (Enform, 2013] and may experience problems when fracturing
40 occurs in nearby wells. Depending on the location of the weakest point in the offset well, this could
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1 result in fluid being spilled onto the surface, rupturing of cement and/or casing and hydraulic
2 fracturing fluid leaking into subsurface formations, or fluid flowing out through existing flaws in the
3 casing and/or cement (see Chapters 5 and 7 for additional information on how such spills can affect
4 drinking water resources). For example, a documented well communication event near Innisfail,
5 Alberta, Canada (see Text Box 6-4) occurred when several well components failed because they
6 were not rated to handle the increased pressure caused by the well communication (ERCB. 2012).
7 In addition, if the fractures were to intersect an uncemented portion of the wellbore, the fluids
8 could potentially migrate into any formations that are uncemented along the wellbore.
Text Box 6-4. Well Communication at a Horizontal Well near Innisfail, Alberta, Canada.
9 In most cases, well communication during fracturing may only result in a pressure surge accompanied by a
10 drop in gas production and additional flow of produced water or fracturing fluid at an offset well. However, if
11 the offset well is not capable of withstanding the high pressures of fracturing, more significant damage can
12 occur.
13 In January 2012, fracturing at a horizontal well near Innisfail in Alberta, Canada, caused a surface spill of
14 fracturing and formation fluids at a nearby operating vertical oil well. According to the investigation report by
15 the Alberta Energy Resources Conservation Board (ERCB. 20121. pressure began rising at the vertical well
16 less than two hours after fracturing ended at the horizontal well.
17 Several components of the vertical well facility—including surface piping, discharge hoses, fuel gas lines, and
18 the pressure relief valve associated with compression at the well—were not rated to handle the increased
19 pressure and failed. Ultimately, the spill released an estimated 19,816 gallons (75 m3) of fracturing fluid,
20 brine, gas, and oil covering an area of approximately 656 ftby 738 ft (200 m by 225 m).
21 The ERCB determined thatthe lateral of the horizontal well passed within 423 ft (129 m) of the vertical well
22 at a depth of approximately 6,070 ft (1,850 m) below the surface, in the same formation. The operating
23 company had estimated a fracture half-length of 262 to 295 ft (80 to 90 m) based on a general fracture model
24 for the field. While there were no regulatory requirements for spacing hydraulic fracturing operations in
25 place at the time, the 423 ft (129 m) distance was out of compliance with the company's internal policy to
26 space fractures from adjacent wells at least 1.5 times the predicted half-length. The company also did not
27 notify the operators of the vertical well of the fracturing operations. The incident prompted the ERCB to issue
28 Bulletin 2012-02—Hydraulic Fracturing: Interwellbore Communication between Energy Wells, which outlines
29 expectations for avoiding well communication events and preventing adverse effects on offset wells.
30 In older wells near a hydraulic fracturing operation, plugs and cement may have degraded over
31 time; in some cases, abandoned wells may never have been plugged properly. Before the 1950s,
32 most well plugging efforts were focused on preventing water from the surface from entering oil
33 fields. As a result, many wells from that period were abandoned with little or no cement (NPC.
34 2011b). This can be a significant issue in areas with legacy (i.e., historic) oil and gas exploration and
35 when wells are re-entered and fractured (or re-fractured) to increase production in a reservoir. In
36 one study, 18 of 29 plugged and abandoned wells in Quebec were found to show signs of leakage
37 (Council of Canadian Academies. 2014). Similarly, a PA DEP report cited three cases where natural
38 gas migration had been caused by well communication events with old, abandoned wells (PA DEP,
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1 2009b). The Interstate Oil and Gas Compact Commission flOGCC. 2008] estimates that over 1
2 million wells may have been drilled in the United States prior to a formal regulatory system, and the
3 status and location of many of these wells are unknown. Various state programs exist to plug
4 identified orphaned wells, but they face the challenge of identifying and addressing a large number
5 of wells.1 For example, as of 2000, PADEP's well plugging program reported that it had
6 documented 44,700 wells that had been plugged and 8,000 that were in need of plugging, and
7 approximately 184,000 additional wells with an unknown location and status [PA PEP. 2000]. A
8 similar evaluation from New York State found that the number of unplugged wells was growing in
9 the state despite an active well plugging program [Bishop, 2013].
10 The Reagan etal. [2015] numerical modeling study included an assessment of migration via an
11 offset well as part of its investigation of potential fluid migration from a producing formation into a
12 shallower ground water unit (see Section 6.3.2.2]. In the offset well pathway, it was assumed that
13 the hydraulically induced fractures intercepted an older offset well with deteriorated components.
14 (This assessment can also be applicable to cases where potential migration may occur via the
15 production well-related pathways discussed in Section 6.2.] More specifically, this analysis was
16 designed to assess transport through deteriorating cement between the subsurface formations and
17 the outermost casing, through voids resulting from incomplete cement coverage, through breached
18 tubing, or in simpler well installations without multiple casings. The highest permeability value
19 tested for the connecting feature represented a case with an open wellbore. A key assumption for
20 this investigation was that the offset well was already directly connected to a permeable feature in
21 the reservoir or within the overburden. Similar to the cases for permeable faults or fractures
22 discussed in the previous section, the study investigated the effect of multiple well- and formation-
23 related variables on potential fluid migration (see Table 6-3].
24 Based on the simulation results, an offset well pathway may have a greater potential for gas release
25 from the production zone into a shallower ground water unit than the fault/fracture pathway
26 discussed in Section 6.3.2.2 (Reagan etal.. 2015]. This difference is primarily due to the total pore
2 7 volume of the connecting pathway within the offset well; the offset well pathway may have a
28 significantly lower pore volume compared to the fault/fracture pathway, which reduces possible
29 gas storage in the connecting feature and increases the speed of buoyancy-dependent migration.
30 However, as with the fault/fracture scenario, the gas available for migration in this case is still
31 limited to the gas that is initially stored in the hydraulically induced fractures. Therefore, any
32 incidents of gas breakthrough observed in this study were found to be limited in both duration and
33 magnitude.
34 Reagan etal. (2015] found that production at the gas well (the well used for hydraulic fracturing]
35 also affects the potential upward migration of gas and its arrival times at the drinking water
36 formation due to its effect on the driving forces (e.g., pressure gradient]. Similar to the
37 fault/fracture cases described in Section 6.3.2.2, production in the target reservoir appears to
38 mitigate upward gas migration, both by reducing the amount of gas that might otherwise be
1 An orphaned well is an inactive oil or gas well with no known (or financially solvent) owner.
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1 available for upward migration and creating a pressure gradient toward the production well. Only
2 scenarios without the mitigating feature of gas production result in any upward migration into the
3 aquifer. This assessment also found a generally downward water flow within the connecting well
4 pathway, which is more pronounced when the gas well is operating. The producing formation and
5 aquifer permeabilities appear not to be significant factors for upward gas migration via this
6 pathway. In addition, Reagan etal. [2015] found the permeability of the connecting offset well to be
7 one of the main factors affecting the migration of gas to the aquifer and the water well. Very low
8 permeabilities (less than 1 mD) lead to no migration of gas into the aquifer regardless of the
9 vertical separation distance, whereas larger permeabilities present a greater potential for gas
10 breakthrough.
11 In the same way that fractures can propagate to intersect offset wells, they can also potentially
12 intersect other artificial subsurface structures including mine shafts or solution mining sites. No
13 known incidents of this type of migration have been documented. However, the Bureau of Land
14 Management (BLM) has identified over 28,000 abandoned mines in the United States and is adding
15 new mines to its inventory every year [BLM. 2013a]. In addition, the Well File Review identified an
16 estimated 800 cases where wells used for hydraulic fracturing were drilled through mining voids,
17 and an additional 90 cases of drilling through gas storage zones or wastewater disposal zones [U.S.
18 EPA, 2015o]. The analysis suggests that emplacing cement within such zones may be challenging,
19 which, in turn, could lead to a loss of zonal isolation (as described in Section 6.2) and create a
2 0 pathway for fluid migration.
6.3.2.4. Migration via Fractures Intersecting Geologic Features
21 Potential fluid migration via natural fault or fracture zones in conjunction with hydraulic fracturing
22 has been recognized as a potential contamination hazard for several decades (Harrison. 1983].
23 While porous flow in unfractured shale or tight sand formations is assumed to be negligible due to
24 very low formation permeabilities (as discussed in Section 6.3.2.1), the presence of natural
25 "microfractures" within tight sand or shale formations is widely recognized, and these fractures
26 affect fluid flow and production strategies. Naturally occurring permeable faults and larger scale
27 fractures within or between formations may allow for more significant flow pathways for migration
28 of fluids outof the production zone (Tacksonetal., 2013c: Myers, 2012a). Figure 6-4 illustrates the
29 concept of induced fractures intersecting with natural faults or fractures extending out of the target
30 reservoir.
31 Natural fracture systems have a strong influence on the success of a fracture treatment, and the
32 topic has been studied extensively from the perspective of optimizing treatment design (e.g.. Weng
33 etal.. 2011: DahiTaleghani and Olson. 2009: Vulgamore etal.. 2007). Small natural fractures,
34 known as "microfractures," could affect fluid flow patterns near the induced fractures by increasing
35 the effective contact area. Conversely, the natural microfractures could act as capillary traps for the
36 fracturing fluid during treatment (contributing to fluid leakoff) and potentially hinder hydrocarbon
37 flow due to lower gas relative permeabilities (Dahi Taleghani etal.. 2013). Rutledge and Phillips
38 (2003) suggested that, for a hydraulic fracturing operation in East Texas, pressurizing existing
39 fractures (rather than creating new hydraulic fractures) may be the primary process that controls
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1 enhanced permeability and fracture network conductivity at the site. Ciezobka and Salehi [2013]
2 used microseismic data to investigate the effects of natural fractures in the Marcellus Shale and
3 concluded that fracture treatments are more efficient in areas with clusters or "swarms" of small
4 natural fractures, while areas without these fracture swarms require more thorough stimulation.
5 However, there is very little attention given in the literature to studying unintended fluid migration
6 during hydraulic fracturing operations due to existing micro fractures.
7 In some areas, larger-scale geologic features may affect potential fluid flow pathways. As discussed
8 in Text Box 6-2, baseline measurements taken before shale gas development show evidence of
9 thermogenic methane in some shallow aquifers, suggesting that natural subsurface pathways exist
10 and allow for naturally occurring migration of gas over millions of years [Robertson etal.. 2012].
11 There is also evidence demonstrating that gas undergoes mixing in subsurface pathways
12 fBaldassareetal.. 2014: Molofsky etal.. 2013: Fountain and Tacobi. 20001 Warner etal. f20121
13 compared recent sampling results to data published in the 1980s and found geochemical evidence
14 for migration of fluids through natural pathways between deep underlying formations and shallow
15 aquifers—pathways that the authors suggest could lead to contamination from hydraulic fracturing
16 activities. In northeastern Pennsylvania, there is evidence that brine from deep saline formations
17 has migrated into shallow aquifers over geologic time, preferentially following certain geologic
18 structures [Llewellyn, 2014]. As described in Chapter 7, karst features (created by the dissolution
19 of soluble rock] can also serve as a potential pathway of fluid movement on a faster time scale.
2 0 Monitoring data show that the presence of natural faults and fractures can affect both the height
21 and width of hydraulic fractures. When faults are present, relatively larger microseismic responses
2 2 are seen and larger fracture growth can occur, as described below. Concentrated swarms of natural
2 3 fractures within a shale formation can result in a fracture network with a larger width-to-height
24 ratio (i.e., a shorter and wider network] than would be expected in a zone with a low degree of
25 natural fracturing (Ciezobka and Salehi. 2013].
26 A few studies have used monitoring data to specifically investigate the effect of natural faults and
2 7 fractures on the vertical extent of induced fractures. A statistical analysis of microseismic data by
28 Shapiro etal. (2011] found that fault rupture from hydraulic fracturing is limited by the extent of
29 the stimulated rock volume and is unlikely to extend beyond the fracture network. (However, as
30 demonstrated by microseismic data presented by Vulgamore etal. (2007], in some settings the
31 fracture network can extend laterally for thousands of feet] In the Fisher and Warpinski (2012]
32 data set (see Section 6.3.2.2], the greatest fracture heights occurred when the hydraulic fractures
33 intersected pre-existing faults. Similarly, Hammacketal. (2014] reported that fracture growth seen
34 above the Marcellus Shale is consistent with the inferred extent of pre-existing faults at the Greene
35 County, Pennsylvania, research site (see Section 6.3.2.2 and Text Box 6-3]. The authors suggested
36 that clusters of microseismic events may have occurred where preexisting small faults or natural
37 fractures were present above the Marcellus Shale. At a site in Ohio, Skoumal etal. (2015] found that
38 hydraulic fracturing induced a rupture along a pre-existing fault approximately 0.6 miles (1 km]
39 from the hydraulic fracturing operation. Using a new monitoring method known as tomographic
40 fracturing imaging, Lacazette and Geiser (2013] also found vertical hydraulic fracturing fluid
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1 movement from a production well into a natural fracture network for distances of up to 0.6 miles
2 (1 km). However, Daviesetal. [2013] questioned whether this technique actually measures
3 hydraulic fracturing fluid movement
4 Modeling studies have also investigated whether hydraulic fracturing operations are likely to
5 reactivate faults and create a potential fluid migration pathway into shallow aquifers. Myers
6 [2012a, 2012b] found that a highly conductive fault could result in rapid (<1 year) fluid migration
7 from a deep shale zone to the surface (as described in Section 6.3.2.1). Other researchers reject the
8 notion that open, permeable faults would coexist with hydrocarbon accumulation [Fiewelling etal.,
9 2013), although it is unclear whether the existence of faults in low permeability reservoirs would
10 affect the accumulation of hydrocarbons because, under natural conditions, the flow of gas maybe
11 limited due to capillary tension. Results from another recent modeling study suggest that, under
12 specific circumstances, interaction with a conductive fault could result in fluid migration to the
13 surface only on longer (ca. 1,000 year) time scales [Gassiatetal., 2013). Rutqvist et al. [2013) found
14 that, while somewhat larger microseismic events are possible in the presence of faults, repeated
15 events and aseismic slip would amount to a total rupture length of 164 ft (50 m) or less along a
16 fault, not far enough to allow fluid migration between a deep gas reservoir and a shallow aquifer. A
17 follow-up study using more sophisticated three-dimensional modeling techniques also found that
18 deep hydraulic fracturing is unlikely to create a direct flow path into a shallow aquifer, even when
19 fracturing fluid is injected directly into a fault [Rutqvist etal., 2015). Similarly, a modeling study
20 that investigated potential fluid migration from hydraulic fracturing in Germany found potential
21 vertical fluid migration up to 164 ft (50 m) in a scenario with high fault zone permeability, although
22 the authors note this is likely an overestimate because their goal was to "assess an upper margin of
23 the risk" associated with fluid transport (Lange etal., 2013). More generally, results from Rutqvist
24 etal. (2013) indicate that fracturing along an initially impermeable fault (as is expected in a shale
25 gas formation) would result in numerous small microseismic events that act to prevent larger
26 events from occurring (and, therefore, prevent the creation of more extensive potential pathways).
2 7 Other conditions in addition to the physical presence of a pathway would need to exist for fluid
28 migration to a drinking water resource to occur. The modeling study conducted by (Reagan etal.,
29 2015) discussed in Section 6.3.2.2 indicates that, if such a permeable feature exists, the transport of
30 gas and fluid flow would strongly depend upon the production regime and, to a lesser degree, the
31 features' permeability and the separation between the reservoir and the aquifer. In addition, the
32 pressure distribution within the reservoir (e.g., over-pressurized vs. hydrostatic conditions) will
33 affect the fluid flow through fractures/faults. As a result, the presence of multiple natural and we 11-
34 based factors may increase the potential for fluid migration into drinking water resources. For
35 example, in the Mamm Creek area of Colorado (see Section 6.2.2.2), well integrity and drilling-
36 related problems likely acted in concert with natural fracture systems to result in a gas seep into
37 surface water and shallow ground water (Crescent, 2011).
6.4. Synthesis
38 In the injection stage of hydraulic fracturing, operators inject fracturing fluids into a well under
39 high pressure. These fluids flow through the well and into the surrounding formation, where they
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1 increase pore pressure and create fractures in the rock, allowing hydrocarbons to flow through the
2 fractures and up the well.
3 The production well and the surrounding geologic features function as a system that is often
4 designed with multiple elements that can isolate hydrocarbon-bearing zones and water-bearing
5 zones, including drinking water resources, from each other. This physical isolation optimizes oil
6 and gas production and can protect drinking water resources via isolation within the well (by the
7 casing and cement) and the presence of multiple layers of subsurface rock between the target
8 formations where hydraulic fracturing occurs and drinking water aquifers.
6.4.1. Summary of Findings
9 Potential pathways for impacts on drinking water (i.e., the movement of hydrocarbons, formation
10 brines, or other fracturing-related fluids into drinking water resources), may be linked to one or
11 more components of the well and/or features of the subsurface system. If present, these potential
12 pathways can, in combination with the high pressures under which fluids are injected and pressure
13 changes within the subsurface, have an impact on drinking water resources.
14 The potential for these pathways to exist or form has been investigated through modeling studies
15 that simulate subsurface responses to hydraulic fracturing, and demonstrated via case studies and
16 other monitoring efforts. In addition, the development of some of these pathways—and fluid
17 movement along them—has been documented.
18 It is important to note that the development of one pathway within this system does not necessarily
19 result in an impact to a drinking water resource. For example, if cracks were to form in the cement
20 of a well, the vertical distance between the production zone and a drinking water resource (and the
21 multiple layers of rock in between) could isolate and protect the drinking water aquifer if pressures
22 were insufficient to allow fluid movement to the level of the drinking water resource. Conversely, if
23 an undetected fault were present in a rock formation, intact cement within the production well
24 could keep fluids from migrating up along the well to the fault and protect drinking water
25 resources.
6.4.1.1. Fluid Movement via the Well
26 A production well undergoing hydraulic fracturing is subject to higher stresses during the relatively
27 brief hydraulic fracturing phase than during any other period of activity in the life of the well. These
28 higher stresses may contribute to the formation of potential pathways associated with the casing or
29 cement that can result in the unintentional movement of fluids through the production wellbore if
30 the well cannot withstand the stresses experienced during hydraulic fracturing operations (see
31 Section 6.2).
32 Multiple barriers within the well, including casing, cement, and a completion assembly, isolate
33 hydrocarbon-bearing formations from drinking water resources. However, inadequate
34 construction, defects in or degradation of the casing or cement, or the absence of redundancies such
35 as multiple layers of casing, can allow fluid movement, which can then affect the quality of drinking
36 water resources. Ensuring proper well design and mechanical integrity—particularly proper
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1 cement placement and quality—are important actions for preventing unintended fluid migration
2 along the wellbore.
6.4.1.2. Fluid Movement within Subsurface Geologic Formations
3 Potential subsurface pathways for fluid migration include flow of fluids out of the production zone
4 into formations above or below it, fractures extending out of the production zone or into other
5 induced fracture networks, intersections of fractures with abandoned or active wells, and fractures
6 intersecting with faults or natural fractures (see Section 6.3).
7 Vertical separation between the production zone where hydraulic fracturing operations occur and
8 drinking water resources, and lateral separation between wells undergoing hydraulic fracturing
9 and other wells can reduce the potential for fluid migration that can impact drinking water
10 resources.
11 Well communication incidents or "frac hits" have been reported in New Mexico, Oklahoma, and
12 other locations. While some operators design fracturing treatments to communicate with the
13 fractures of another well and optimize production, unintended communication between two
14 fracture systems can lead to spills in the offset well and is an indicator of hydraulic fracturing
15 treatments extending beyond their planned design. Surface spills from well communication
16 incidents have been documented in the literature, which provides evidence for occurrence of frac
17 hits. Based on the available information, frac hits most commonly occur on multi-well pads and
18 when wells are spaced less than 1,100 ft (335 m) apart, butthey have been observed at wells up to
19 8,422 ft (2,567 m) away from a well undergoing hydraulic fracturing.
6.4.1.3. Impacts to Drinking Water Resources
20 We identified an impact on drinking water resources associated with hydraulic fracturing
21 operations in Bainbridge, Ohio. Failure to cement over-pressured formations through which the
22 production well passed—and proceeding with the fracturing operation without adequate cement
23 and an extended period during which the well was shut in—led to a buildup of natural gas within
24 the well annulus and high pressures within the well. This ultimately resulted in movement of gas
25 from the production zone into local drinking water aquifers (see Section 6.2.2.2).
26 Casings at a production well near Kill deer, North Dakota, ruptured following a pressure spike
27 during hydraulic fracturing, allowing fluids to escape to the surface. Brine and tert-butyl alcohol
28 were detected in two nearby water wells. Following an analysis of potential sources, the only
29 potential source consistent with the conditions observed in the two impacted wells was the well
30 that ruptured. There is also evidence that out-of-zone fracturing occurred at the well (see Sections
31 6.2.2.1 and 6.3.2.2).
32 There are other cases where hydraulic fracturing could be a contributing cause to impacts on
33 drinking water resources, or where the specific mechanism that led to an impact on a drinking
34 water resource cannot be definitively determined. For example:
35 • Migration of stray gas into drinking water resources involves many potential routes for
36 migration of natural gas, including poorly constructed casing and naturally existing or
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1 induced fractures in subsurface formations. Multiple pathways for fluid movement may be
2 working in concert in northeastern Pennsylvania (possibly due to cement issues or
3 sustained casing pressure) and the Raton Basin in Colorado (where fluid migration may
4 have occurred along natural rock features or faulty well seals). While the sources of
5 methane identified in drinking water wells in each study area could be determined with
6 varying degrees of certainty, attempts to definitively identify the pathways of migration
7 have generally been inconclusive (see Text Box 6-2).
8 • At the East Mamm Creek drilling area in Colorado, inadequate placement of cement
9 allowed the migration of methane through natural faults and fractures in the area. This
10 case illustrates how construction issues, sustained casing pressure, and the presence of
11 natural faults and fractures, in conjunction with elevated pressures associated with well
12 stimulation, can work together to create a pathway for fluids to migrate toward drinking
13 water resources (see Sections 6.2.2.2 and 6.3.2.4).
14 Additionally, some hydraulic fracturing operations involve the injection of fluids into formations
15 where there is relatively limited vertical separation from drinking water resources. The EPA
16 identified an estimated 4,600 wells that were located in areas with less than 2,000 ft (610 m) of
17 vertical separation between the fractures and the base of protected ground water resources.
18 There are places in the subsurface where oil and gas reservoirs and drinking water resources co-
19 exist in the same formation. Evidence we examined suggests that some hydraulic fracturing for oil
20 and gas occurs within formations where the ground water has a salinity of less than 10,000 mg/L
21 TDS. By definition, this results in the introduction of fracturing fluids into formations that meet the
22 Safe Drinking Water Act (SDWA) salinity-based definition of a source of drinking water and the
23 broader definition of a drinking water resource developed for this assessment. According to the
24 data we examined, these formations are generally in the western United States.
25 The practice of injecting fracturing fluids into a formation that also contains a drinking water
26 resource directly affects the quality of that water, since it is likely some of that fluid remains in the
27 formation following hydraulic fracturing. Hydraulic fracturing in a drinking water resource may be
28 of concern in the short-term (where people are currently using these zones as a drinking water
29 supply) or the long-term (if drought or other conditions necessitate the future use of these zones
30 for drinking water).
31 There are other cases in which production wells associated with hydraulic fracturing are alleged to
32 have caused drinking water contamination. Data limitations in most of those cases (including the
33 unavailability of information in litigation settlements resulting in sealed documents) make it
34 impossible to definitively assess whether or not hydraulic fracturing was a cause of the
35 contamination in these cases.
6.4.2. Factors Affecting Frequency and Severity of Impacts
36 Proper cementing across oil-, gas-, or water-bearing zones prevents the movement of brines, gas, or
3 7 hydraulic fracturing fluids along the well into drinking water resources. The likelihood of
38 contamination is reduced when the well is fully cemented across these zones; however, this is not
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1 the case in all hydraulically fractured wells, either because the cement does not extend completely
2 through the base of the drinking water resource or the cement that is present is not of adequate
3 quality. Fully cemented surface casing that extends through the base of drinking water resources is
4 a key protective component of the well. Most, but not all, wells used in hydraulic fracturing
5 operations have fully cemented surface casing.
6 Deviated and horizontal wells, which are increasingly being used in hydraulic fracturing operations,
7 may exhibit more casing and cement problems compared to vertical wells. Sustained casing
8 pressure—a buildup of pressure within the well annulus that can indicate the presence of small
9 leaks—occurs more frequently in deviated and horizontal wells compared to vertical wells. Cement
10 integrity problems can also arise as a result of challenges in placing cement in these wells, because
11 they are more challenging than vertical wells to center properly.
12 Older wells may exhibit more integrity problems compared to newer wells, which may be an issue
13 if older wells are hydraulically fractured or re-fractured. Degradation of the casing and cement as
14 they age or the cumulative effects of stresses exerted on the well over time may result in changes in
15 well integrity. Integrity problems can also be associated with the inadequate design of wells that
16 were constructed pursuant to older, less stringent requirements. Well components that are subject
17 to corrosive environments, high pressures, or other stressors tend to have more problems than
18 wells without these additional stressors.
19 The extent of subsurface fluid migration within subsurface rock formations and the potential for the
2 0 development of pathways that can adversely affect drinking water depend on site-specific
21 characteristics. These include the physical separation between the production zone and drinking
22 water resources, the geological and geomechanical characteristics of the formations, hydraulic
23 fracturing operational parameters, and the physical characteristics of any connecting feature (e.g.,
24 abandoned wells, faults, and natural fractures).
25 As noted above, vertical separation between the production zone and drinking water resources
26 protects drinking water. Additionally, the proximity of wells undergoing hydraulic fracturing to
27 other wells increases the potential for the formation of pathways for fluids to move via these wells
28 to drinking water resources. For example, if there is a deficiency in the construction of a nearby
29 well (or degradation of the well components), that well could serve as a pathway for movement of
30 fracturing fluids, methane, or brines that might affect a drinking water resource. If the fractures
31 were to intersect an uncemented portion of a nearby wellbore, the fluids could migrate along that
32 wellbore into any uncemented formations.
33 Fractures created during hydraulic fracturing can extend out of the target production zone. Out-of-
34 zone fracturing could be a concern for fluid migration if the hydraulic fracturing operation is not
35 designed to address site-specific conditions, for example if the production zone is thin and fractures
36 propagate to unintended vertical heights, or if the production zone is not horizontally continuous
37 and fractures extend to unintended horizontal lengths. The presence of natural faults or fractures
38 can affect the extent of hydraulic fractures. When faults are present, relatively larger microseismic
39 responses are seen during hydraulic fracturing, and larger fracture growth can occur than in the
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1 absence of natural faults or fractures. However, modeling studies indicate that fluid migration from
2 deep production zones to shallow drinking water resources along natural faults and fractures or
3 offset wells is unlikely. These studies indicate that, in both cases, gas available for migration is
4 limited to the amount that existed in the fractures and pore space of connecting features following
5 hydraulic fracturing prior to production. Following the completion of a hydraulic fracturing
6 treatment, depressurization of the production formation surrounding the fractures due to
7 hydrocarbon production would make upward fluid migration into drinking water resources
8 unlikely to occur.
9 Based on the information presented in this chapter, the increased deployment of hydraulic
10 fracturing associated with oil and gas production activities, including techniques such as horizontal
11 drilling and multi-well pads, may increase the likelihood that these pathways could develop. This, in
12 turn, could lead to increased opportunities for impacts on drinking water resources.
6.4.3. Uncertainties
13 Generally, less is known about the occurrence of (or potential for) impacts of injection-related
14 pathways in the subsurface than for other components of the hydraulic fracturing water cycle,
15 which can be observed and measured at the surface. Furthermore, while there is a significant
16 amount of information available on production wells in general, there is little information that is
17 specific to hydraulic fracturing operations and much of this data is not readily accessible, i.e., in a
18 centralized, national database.
6.4.3.1. Limited A vailability of Information Specific to Hydraulic Fracturing Operations
19 There is extensive information on the design goals for hydraulically fractured oil and gas wells (i.e.,
20 to address the stresses imposed by high-pressure, high-volume injection), including from industry-
21 developed best practices documents. Additionally, based on the long history of oil and gas
22 production activities, we know how production wells are constructed and have performed over
23 time. Over the years, many studies have documented how these wells are constructed, how they
24 perform, and the rates at which they experience problems that can lead to the formation of
25 pathways for fluid movement However, because we do not know which of these wells were
26 hydraulically fractured, we cannot definitively determine whether the rates at which integrity
27 problems arise (or other data pertaining to oil and gas wells in general) directly correspond to
28 wells used in hydraulic fracturing operations.
29 Because wells that have been hydraulically fractured must withstand many of the same downhole
30 stresses as other production wells, we consider studies of the pathways for impacts to drinking
31 water resources in production wells to be relevant to identifying the potential pathways relevant to
32 hydraulic fracturing operations. However, without specific data on the as-built construction of wells
33 used in hydraulic fracturing operations, we cannot definitively state whether these wells are
34 consistently constructed to meet the stresses they may encounter.
35 There is also, in general, very limited information available on the monitoring and performance of
36 wells used in hydraulic fracturing operations. Published information is sparse regarding
37 mechanical integrity tests (MITs) performed during and after hydraulic fracturing, including MIT
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1 results, the frequency at which mechanical integrity issues arise in wells used for hydraulic
2 fracturing, and the degree and speed with which identified issues are addressed. There is also little
3 information available regarding MIT results for the original hydraulic fracturing in wells built for
4 that purpose, for wells that are later re-fractured, or for existing, older wells not initially
5 constructed for hydraulic fracturing but repurposed for that use.
6 There are also a limited number of published monitoring studies or sampling data that provide
7 evidence to assess whether formation brines, injected fluids, or gas move in unintended ways
8 through the subsurface during and after hydraulic fracturing. Subsurface monitoring data (i.e., data
9 that characterize the presence, migration, or transformation of fluids in the subsurface related to
10 hydraulic fracturing operations) are scarce relative to the tens of thousands of oil and gas wells that
11 are estimated to be hydraulically fractured across the country each year (see Chapter 2).
12 Information on fluid movement within the subsurface and the extent of fractures that develop
13 during hydraulic fracturing operations is also limited. For example, limited information is available
14 in the published literature on how flow regimes or other subsurface processes change at sites
15 where hydraulic fracturing is conducted. Instead, much of the available research, and therefore the
16 literature, addresses how hydraulic fracturing and other production technologies perform to
17 optimize hydrocarbon production.
18 These limitations on hydraulic fracturing-specific information make it difficult to provide definitive
19 estimates of the rate at which wells used in hydraulic fracturing operations experience the types of
20 integrity problems that can contribute to fluid movement.
6.4.3.2. Limited Systematic, Accessible Data on Well Performance or Subsurface Movement
21 While the oil and gas industry generates a large amount of information on well performance as part
22 of operations, most of this is proprietary or otherwise not readily available to states or the public in
23 a compiled or summary manner. Therefore, no national or readily accessible way exists to evaluate
24 the design and performance of individual wells or wells in a region, particularly in the context of
2 5 local geology or the presence of other wells and/or hydraulic fracturing operations. Many states
26 have large amounts of operator-submitted data, but information about construction practices or the
2 7 performance of individual wells is typically not in a searchable or aggregated form that would
2 8 enable assessments of well performance under varying settings, conditions, or timeframes.
29 Although it is collected in some cases, there is also no systematic collection, reporting, or publishing
30 of empirical baseline (pre-drilling and/or pre-fracturing) and post-fracturing monitoring data that
31 could indicate the presence or absence of hydraulic fracturing-related fluids in shallow zones and
32 whether or not migration of those fluids has occurred. Ideally, data from ground water monitoring
33 are needed to complement theories and modeling on potential pathways and fluid migration.
34 While some of the types of impacts described above may occur quickly (i.e., on the scale of days or
35 weeks, as with integrity problems or well communication events), other impacts (e.g., in slow-
36 moving, deep ground waters) may only occur or be able to be detected on much longer timescales.
37 Given the surge in the number of modern high-pressure hydraulic fracturing operations dating
38 from the early 2000s, evidence of any fracturing-related fluid migration affecting a drinking water
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1 resource (as well as the information necessary to connect specific well operation practices to a
2 drinking water impact) could take years to discover.
3 The limited amount of information hinders our ability to evaluate whether—or how frequently—
4 drinking water impacts are occurring (or the potential for these impacts to occur) or to tie possible
5 impacts to specific well construction, operation, or maintenance practices. This also significantly
6 limits our ability to evaluate the aggregate potential for hydraulic fracturing operations to affect
7 drinking water resources or to identify the potential cause of drinking water contamination or
8 suspected contamination in areas where hydraulic fracturing occurs.
6.4.4. Conclusions
9 Fluids can migrate from the wellbore and surrounding subsurface formations due to inadequate
10 casing or cement, and via natural and man-made faults, fractures, and offset wells or mines (see
11 Text Box 6-5). To prevent fluid migration through the wellbore or through subsurface pathways,
12 wells must have adequate casing and cement, and induced fractures must not intersect existing
13 fractures or permeable zones that lead to drinking water resources. Evidence shows that the quality
14 of drinking water resources may have been affected by hydraulic fracturing fluids escaping the
15 wellbore and surrounding formation in certain areas, although conclusive evidence is currently
16 limited.
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Text Box 6-5. Research Questions Revisited.
How effective are current well construction practices at containing fluids—both liquids and gases—
before, during, and after fracturing?
• Wells that were designed with uncemented intervals of casing across porous or permeable zones, wells in
which cementing does not resist formation or operational stresses, and wells in which cementing does
not meet design specifications have the potential to promote unintended subsurface fluid movement.
Even in optimally designed wells, metal casings and cement can degrade over time, either as a result of
aging or of exposure to stresses exerted over years of operations. See Section 6.2.2.2.
• We have limited information on the degree to which wells are designed and constructed with the
multiple layers of casing that can withstand hydraulic fracturing pressures and contact with injected and
produced fluids. We also are lacking information about whether wells have suitable cements that can
prevent fluid movement outside the wellbore and between the production zone and drinking water
resources. We also do not have information on the degree to which mechanical integrity is verified before
or after hydraulic fracturing operations. See Section 6.2.2.1.
Can subsurface migration of fluids—both liquids and gases—to drinking water resources occur and
what local geologic or artificial features might allow this?
• The presence of artificial penetrations, especially poorly constructed offset wells or undetected
abandoned wells, mines, or other subsurface structures, provides pathways that, in the presence of a
driving force, could allow for fluid movement to shallow geologic zones such as drinking water resources.
See Section 6.3.2.3.
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1 • Intersections of induced fractures with transmissive faults or naturally occurring fractures or
2 porous/permeable rock zones can allow fluids to move out of the targeted fracture areas. However,
3 modeling studies indicate that fluid migration from production zones to drinking water resources along
4 natural faults and fractures is unlikely. See Section 6.3.2.4.
5 • Some hydraulic fracturing operations involve the injection of fluids into formations where there is
6 relatively limited vertical separation from drinking water resources. Other hydraulic fracturing is
7 performed within formations that meet the SDWA or state salinity-based definition of a source of
8 drinking water, in addition to the broader definition of a drinking water resource developed for this
9 assessment. See Section 6.3.2.
6.5. References for Chapter 6
Adachi. I: Siebrits. E: Peirce. A: Desroches. I. (2007). Computer simulation of hydraulic fractures. International
Journal of Rock Mechanics and Mining Sciences 44: 739-757.
http://dx.doi.0rg/10.1016/j.ijrmms.2006.ll.006
Ajani. A: Kelkar. M. (2012). Interference study in shale plays. Paper presented at SPE Hydraulic Fracturing
Technology Conference, February 6-8, 2012, The Woodlands, TX.
Ali. M: Taoutaou. S: Shafqat. AU: Salehapour. A: Noor. S. (2009). The use of self healing cement to ensure long
term zonal isolation for HPHT wells subject to hydraulic fracturing operations in Pakistan. Paper
presented at International Petroleum Technology Conference, December 7-9, 2009, Doha, Qatar.
ALL Consulting (ALL Consulting, LLC). (2004). Coal bed methane primer: New source of natural gas and
environmental implications. Tulsa, OK: U.S. Department of Energy, National Petroleum Technology Center.
http://bogc.dnrc.mt.gov/PDF/Web%20Version.pdf
Arkadakskiy. S: Rostron. B. (2012a). Stable isotope geochemistry helps in reducing out-of-zone hydraulic
fracturing and unwanted brine production from the Bakken Reservoir. Available online at
http://isobrine.com/resources/
Arkadakskiy. S: Rostron. B. (2013a). Tracking out-of-zone hydraulic fracturing in the Bakken with naturally
occuring tracers. Paper presented at GeoConvention 2013: Integration, May 6-10, 2013, Calgary, Alberta.
Bachu. S: Bennion. DB. (2009). Experimental assessment of brine and/or C02 leakage through well cements
at reservoir conditions. Int J Greenhouse Gas Control 3: 494-501.
http://dx.doi.0rg/10.1016/i.iiggc.2008.ll.002
Bair. ES: Freeman. DC: Senko. IM. (2010). Subsurface gas invasion Bainbridge Township, Geauga County, Ohio.
(Expert Panel Technical Report). Columbus, OH: Ohio Department of Natural Resources.
http://oilandgas.ohiodnr.gov/resources/investigations-reports-violations-reformstfTHR
Baldassare, F. (2011). The origin of some natural gases in Permian through Devonian Age systems in the
Appalachian Basin and the relationship to incidents of stray gas migration. Presentation presented at
Technical workshop for hydraulic fracturing study, chemical and analytical methods, February2425,2011,
Arlington, VA.
Baldassare. Fl: McCaffrey. MA: Harper. IA. (2014). A geochemical context for stray gas investigations in the
northern Appalachian Basin: Implications of analyses of natural gases from Neogene-through Devonian-
age strata. AAPG Bulletin 98: 341-372. http://dx.doi.org/10.1306/06111312178
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Barker. IF: Fritz. P. (1981). Carbon isotope fractionation during microbial methane oxidation. Nature 293:
289-291. http://dx.doi.org/10.1038/293289aO
Bertoncello. A: Wallace. I: Honarpour. MM: Kabir. C: Blyton. CA. (2014). Imbibition and water blockage in
unconventional reservoirs: Well management implications during flowback and early production. SPE
Journal 17.
Bishop. RE. (2013). Historical analysis of oil and gas well plugging in New York: Is the regulatory system
working? New Solutions: A Journal of Environmental and Occupational Health Policy 23:103-116.
http://dx.doi.Org/10.2190/NS.23.l.g
BLM (Bureau of Land Management). (2013a). Abandoned mine lands: A new legacy. Washington, DC: U.S.
Department of the Interior, Bureau of Land Management.
http://www.blm.gov/pgdata/etc/medialib/blm/wo/MINERALS REALTY AND RESOURCE PROTECTIO
N /ami/ami documents.Par.81686.File.dat/AML NewLegacy.pdf
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
Chapter 7
Flowback and Produced Water
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
7. Flowback and Produced Water
7.1. Introduction
1 Water is a byproduct of oil and gas production. After hydraulic fracturing is completed, either in its
2 entirety or for a specified stage, the operator reduces the injection pressure. Water is allowed to
3 flow back from the well to prepare for oil or gas production. This return-flow water may contain
4 chemicals injected as part of the hydraulic fracturing fluid, chemicals characteristic of the
5 formation, hydrocarbons, and in-formation reaction and degradation products. Initially this water,
6 called flowback, is mostly fracturing fluid, but as time goes on, it becomes more similar to the
7 formation water. For formations containing saline water (brine), the salinity of the water increases
8 as time passes, marking the increased contact time with the formation and in some cases the flow of
9 formation water itself. This later stage water is called produced water, a term which can also refer
10 to flowback and produced water collectively.
11 Flowback and produced water are stored and accumulated at the surface for eventual reuse or
12 disposal. Typical storage facilities include open air impoundments and closed containers such as
13 those shown in Figure 1-1. Produced water is collected and may be taken to disposal wells,
14 recyclers, waste water treatment plants, or in some cases the water may be left in pits to evaporate
15 or infiltrate. Flowback and produced water leaks can occur on the well pad as a result of human
16 error, failure of container integrity, equipment failure, communication between wells, pipeline
17 leaks, and blowouts.: Above-ground piping systems can connect multiple well pads to
18 impoundments, and piping or impoundments may leak. Much produced water is transported by
19 truck, and pad incidents leading to spills of produced water can occur when trucks are filled.
20 On-road accidents are also possible, some of which could release produced water loads to the
21 environment
22 Impacts to drinking water resources can occur if spilled flowback or produced water enters surface
23 water bodies or aquifers. Environmental transport of chemical constituents depends on the
24 characteristics of the spill, the fluid (e.g., density, as for highly saline water), the chemicals, and the
25 environment Attenuation processes (e.g., dilution, biodegradation of organics) in surface water and
26 aquifers tend to reduce concentrations.
27 We begin this chapter with a review of definitions for flowback and produced water. We then
28 discuss typical volumes of flowback and produced water on a per-we 11 basis. This information is
29 aggregated to the state and basin level in Chapter 8. The characteristics of hydraulically fractured
30 shale, tight, and coalbed methane (CBM) formations are described. Spatial and temporal trends on
31 composition of produced water are illustrated with examples from the literature and data compiled
32 for this report The processes controlling the chemical composition of produced water are
33 described in Appendix E. The potential for impacts on drinking water resources of flowback and
34 produced water are described based on reported spill incidents, contaminant transport principles,
35 and field study examples. The chapter concludes with a discussion of uncertainties and knowledge
For discussion of well communication, see Chapter 6.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 gaps, factors that influence the severity of impacts, and a synthesis based on the EPA research
2 questions.
7.1.1. Definitions
3 Multiple definitions exist for the terms flowback and produced water. These differing definitions
4 indicate challenges in determining the distinctions between the two terms or indicate that different
5 usage of the terms routinely occurs among various industry, private, and public groups. However,
6 the majority of produced water definitions are fundamentally similar. The following definition is
7 used in this report: water that flows from oil or gas wells.
8 This definition is similar to the definition used by the American Petroleum Institute (API):
9 "Produced water is any of the many types of water produced from oil and gas wells" [API. 2010b]:
10 the definition used by the Department of Energy (DOE): "Produced water is water trapped in
11 underground formations that is brought to the surface along with oil or gas" (DOE, 2004), and a
12 similar definition used by the American Water Works Association (AWWA): "Produced water is the
13 combination of flowback and formation water that returns to the surface along with the oil and
14 natural gas" (AWWA, 2013). Produced water can variously refer to formation water, a mixture of
15 spent hydraulic fracturing fluid and formation water or returned hydraulic fracturing fluid. Thus
16 the term produced water is used when a distinction between fracturing fluid and formation water is
17 not necessary.
18 In general, the term flowback refers either to fluids predominantly containing hydraulic fracturing
19 fluid that returns to the surface or to a process used to prepare the well for production. Because
20 formation water can contact and mix with injection fluids, the distinction between returning
21 hydraulic fracturing fluid and formation water is not clear. In the early stages of operation,
22 however, a higher concentration of chemical additives is expected and later, water that is typical of
23 the formation (Stewart. 2013a). In most cases, a precise distinction between these waters is not
24 determined during operations.
25 Various definitions have been used for the term flowback The American Petroleum Institute
26 defined flowback as "the fracture fluids that return to the surface after a hydraulic fracture is
27 completed," (API. 2010b) and the American Water Works Association used "fracturing fluids that
28 return to the surface through the wellbore after hydraulic fracturing is complete" (AWWA. 2013).
29 Other definitions include production of hydrocarbons from the well (Barbotetal., 2013: U.S. EPA,
30 2012Q. or a time period (USGS. 2014f: Haluszczaketal.. 2013: Warner etal.. 2013b: Hayes and
31 Severin. 2012a: Hayes. 2009). As mentioned above, flowback can also be defined as a process used
32 to stimulate the well for production by allowing excess liquids and proppant to return to the
33 surface. Because we use existing literature in our review, we do not introduce a preferred definition
34 of flowback, but rather we mention the assumptions used by the author(s) we discuss.
7.1. Volume of Hydraulic Fracturing Flowback and Produced Water
3 5 The characteristics and volume of flowback and produced water vary by well, formation, and time.
3 6 This section presents information on flowback and produced water volume over various time
37 scales, and where possible, on a per-well and per-formation basis.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 The amount of flowback from a well varies and depends on several types of factors, including:
2 production, formation, and operational. Production factors include the amount of fluid injected,
3 type of hydrocarbon produced (gas or liquid), and location within the formation. Formation factors
4 include the formation pressure, interaction between the formation and injected fluid (capillary
5 forces) and reactions within the reservoir. Operational factors include loss of mechanical integrity
6 and subsurface communication between wells (U.S. GAP. 2012: Byrnes. 2011: DOE. 2011a: GWPC
7 and ALL Consulting. 2009: Reynolds and Kiker. 2003). The latter two factors might be indicated by
8 an unexpected increase in water production (Reynolds and Kiker. 2003).
9 The processes that allow gas and liquids to flow are related to the conditions along the faces of
10 fractures. Byrnes (2011) conceptualized fluid flow across the fracture face as being composed of
11 three phases. The first is characterized by forced imbibition of fluid into the reservoir and occurs
12 during and immediately following fracture stimulation. Second is an unforced imbibition following
13 stimulation where the fluid redistributes within the reservoir rock, due to capillary forces, when the
14 well is shut-in. The last phase consists of flow out of the formation when the well is opened and
15 pressure reduced in the borehole and fractures. The purpose of this phase is to recover as much of
16 the injected fluid as possible (Byrnes, 2011) in order to reduce high water saturations at the
17 fracture face and eventually allow higher gas flow rates. The length of the last phase and
18 consequently, the amountof water removed depends on factors such as the amount of injected
19 fluid, the permeability and effective permeability of the reservoir, capillary pressure properties of
20 the reservoir rock, the pressure near the fracture faces, and whether the well is flowing or shut in.1
21 The well can be shut in for varying time periods depending on operator scheduling, surface facility
2 2 construction or hookup, or other reasons.
7.1.1. Flowback of Injected Hydraulic Fracturing Fluid
23 Generally, the fluid that initially returns to the surface has been attributed to a mixture of the
24 injected fracturing fluid, its transformation products, and the natural formation water. In some
25 cases, as shown below, the amount of flowback is greater than the amount of injected hydraulic
26 fracturing fluid and the additional water comes from the formation (Nicotetal.. 2014) or an
27 adjacent formation (Arkadakskiy and Rostron. 2013a). Several authors used geochemical analyses
28 to postulate mixing between formation water and injected fluid in the Marcellus Shale (Engle and
29 Rowan. 2014: BarbotetaL 2013: Haluszczaketal.. 20131: Rowan et al., 2015). These possible
30 explanations are summarized in a following section (see Section 7.6.4). Salinity increases in
31 flowback from highly saline formations, so it is not possible to specify precisely the amount of
32 injected fluids that return in the flowback (GWPC and ALL Consulting. 2009). Rather, such
33 estimates relate the amount of produced water measured at a given time after fracturing as a
34 percentage of the total amountof injected fluid.
35 Estimates vary butin composite indicate on average that between 5% and 75% (see Table 7-1,
36 Table 7-2, and Table 7-3) of the volume of injected fracturing fluid may flow back to the surface
1 When multiple fluids (water, oil, gas) occupy portions of the pore space, the permeability to each fluid depends on the
fraction of the pore space occupied by the fluid and the fluid's properties. As defined by Pake (1978). when this effective
permeability is normalized by the absolute permeability, the resulting relationship is known as the relative permeability.
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Chapter 7 - Flowback and Produced Water
1 after hydraulic fracturing is complete [U.S. EPA. 2015q: Vengoshetal.. 2014: Mantell. 2013b: Vidic
2 etal.. 2013: Minnich. 2011: Xuetal.. 2011). These data (see Table 7-1] illustrate thatthe formations
3 differ in their water requirements for hydraulic fracturing and generation of produced water over
4 the short term.: Low percentages of flowback are typical, as is the decrease of flowback volume
5 with time as the wells enter the production phase [Gregory etal.. 2011: McElreath. 2011: GWPC and
6 ALL Consulting. 2009]. Some formations produce higher volumes, as noted for the Barnett Shale in
7 Texas [Nicotetal., 2014] and discussed below.
Table 7-1. Data from one company's operations indicating approximate total water use and
approximate produced water volumes within 10 days after completion of wells
(Mantell. 2013b).
Formation
Approx. total
average water use
per well (million gal)
Produced water within the first
10 days after completion
Low estimate
(million gal)
High or only
estimate
(million gal)
Produced water as a percentage of
average water use per well
Low estimate
(% of total
water use)
High or only
estimate (% of
total water use)
Gas shale plays (primarily dry gas)
Barnett3
Marcellus3
Haynesville
3.4
4.5
5.4
0.3
0.3
--
1.0
1.0
0.25
9
7
--
29
22
5
Liquid plays (gas, oil, condensate)
Mississippi Lime
Cleveland/Tonkaw
Niobrara
Utica
Granite Wash
Eagle Ford
2.1
2.7
3.7
3.8
4.8
4.9
--
0.3
0.3
0.3
0.3
0.3
1.0
1.0
1.0
1.0
1.0
1.0
--
11
8
8
6
6
48
37
27
26
21
20
a Mantell (2011) reported produced water for the first 10 days at 500,000 to 600,000 gal for the Barnett, Fayetteville and
Marcellus Shales.
Flowback estimates may be based on specific time periods (e.g., the flowback during the first 10,15, or 30 days).
This document is a draft for review purposes only and does not constitute Agency policy.
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Table 7-2. Additional short-, medium-, and long-term produced water estimates.
Location-formation
Produced water as
percentage of injected fluid
Reference
Comment
Estimates without reference to a specific data set
Unspecified Shale
Marcellus Shale
ND-Bakken
5% - 35%
10% - 25%
25%
Haves (2011)
Minnich (2011)
EERC (2013)
Initial flowback
Estimates with reference to specific data evaluation
Short duration
Marcellus Shale
TX— Barnett
TX— Haynesville
AR— Fayetteville
10%
20%
5%
10%
Clark etal. (2013)
Clark etal. (2013)
Clark etal. (2013)
Clark etal. (2013)
0-10 days
0-10 days
0-10 days
0-10 days
Mid duration
WV-Marcellus
Marcellus Shale
8%
24%
Hansen etal. (2013)
Hayes (2011, 2009)
30 days
Average from 19 wells, 90 days
Long duration
TX— Barnett
WV-Marcellus
TX-Eagle Ford
~100%a
10% - 30%
<20%
Nicot etal. (2014)
Ziemkiewicz et al. (2014)
Nicot and Scanlon (2012)
72 months
Up to 115 months
Lifetime
Unspecified duration
PA— Marcellus
6%
Hansen etal. (2013)
a Approximate median with large variability: 5* percentile of 20% and 90* percentile of 350%.
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 7 - Flowback and Produced Water
Table 7-3. Flowback and long-term produced water characteristics for wells in unconventional
formations (U.S. EPA, 2015e).
Source: (U.S. EPA, 2015q).
Resource
type
Shale
Tight
Drill type
Horizontal
Directional
Vertical
Horizontal
Directional
Vertical
Fracturing flu id
(million gal)
Median
4.0
1.6
1.2
2.2
0.60
0.31
Range
0.13-15
0.051-12
0.015-22
0.042-9.4
0.056-4.0
0.019-4.0
Number
of data
points
50,053
124
4,152
765
693
1,287
Long-term produced water (gal/day per well)
Shale
Tight
Horizontal
Directional
Vertical
Horizontal
Directional
Vertical
900
480
380
620
750
570
0-19,000
22-8,700
0-4,600
0-120,000
12-1,800
0-4,000
22,222
695
12,393
2,394
3,816
21,393
Flowback
(percent of fracturing fluid returned)
Median
6%
14%
24%
7%
6%
8%
Range
1% - 50%
4% -31%
7% - 75%
7% - 60%
0% - 60%
1% - 83%
Number of
data points
6,488
19
18
39
263
48
1 In the following subsections, we first discuss water produced during the flowback period, then
2 longer-term produced water.
7.1.1.1. Produced Water during the Flowback Period
3 Data were collected from six vertical and eight horizontal wells in the Marcellus Shale of
4 Pennsylvania and West Virginia [Hayes. 2009]. The author collected samples of flowback after one,
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 five, and 14 days after hydraulic fracturing was completed, as well as a produced water sample 90
2 days after completion of the wells. Both the vertical and horizontal wells showed their largest
3 volume of flowback between one and five days after fracturing, as shown in Figure 7-1. The wells
4 continued to produce water, and at 90 days, samples were available from four each of the
5 horizontal and vertical wells. The vertical wells produced on average 180 bbl/day (7,600 gal/day or
6 29,000 L/day) and the horizontal wells a similar 200 bbl/day (8,400 gal/day or 32,000 L/day).
7 Results from one Marcellus Shale study were fitted to a power curve, as shown in Figure 7-2
8 (Ziemkiewicz etal.. 2014). These and the Hayes (2009) data show decreasing flowback with time.
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 7 - Flowback and Produced Water
MSC Study FB volumes {Vertical Wells)
-Avert teal
-B Vertical
- H Vertical
-N Vertical
-QVertical
-SVertial
20
40 60
Time (days)
80
100
MSC Study FB volumes (Horizontal Wells)
-C Horizontal
-D Horizontal
-E Horizontal
— F Horizontal
-GHorizontal
-KHorizontal
-M Horizontal
-OHonzontal
20
40 60
Time (days)
80
100
Figure 7-1. Fraction of injected hydraulic fracturing fluid recovered from six vertical (top) and
eight horizontal (bottom) wells completed in the Marcellus Shale.
Data from Hayes (2009).
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 7 - Flowback and Produced Water
60
40
V = 0.082xa268B
R2 = 0.9882
35%
30%
75%
20%
15%
10%
ou^oiAo^ou^ou>au"iOu"iOu-tOu"iOu-iOiriau"i
Month after initial frac
a flowback/produced water o % flowback
Figure 7-2. Example of flowback and produced water from the Marcellus Shale, illustrating
rapid decline in water production and cumulative return of approximately 30% of
the volume of injected fluid.
Source: Ziemkiewicz et al. (2014). Reprinted with permission from Ziemkiewicz, P; Quaranta, JD;
Mccawley, M. (2014). Practical measures for reducing the risk of environmental contamination in
shale energy production. Environmental Science: Processes & Impacts 16:1692-1699. Reproduced by
permission of The Royal Society of Chemistry. http://dx.doil.org/10.1039/C3EM00510K.
1 In West Virginia, water recovered at the surface within 30 days following injection or before 50% of
2 the injected fluid volume is returned to the surface is reported as flowback. Data from 271 wells in
3 the Marcellus Shale in West Virginia [Hansenetal.. 2013] reveals the variability of recovery from
4 wells in the same formation and that the amount of injected fluid recovered was less than 15%
5 from over 80% of the wells (see Figure 7-3].
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-9 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
Percent recovered
Figure 7-3. Percent of injected fluid recovered for Marcellus Shale wells in West Virginia
(2010-2012).
Source: Hansen et al. (2013). One data point showing 98% recovery omitted. Reprinted with
permission from Hansen, E; Mulvaney, D; Betcher, M. (2013). Water resource reporting and water
footprint from Marcellus Shale development in West Virginia and Pennsylvania. Durango, CO:
Earthworks Oil & Gas Accountability Project. Copyright 2013. Permission Downstream Strategies, San
Jose State University, and Earthworks Oil & Gas Accountability Project.
1 The amount of flowback water produced by wells within the first few days of fracturing varies from
2 formation to formation. Wells in the Mississippi Lime and Permian Basin can produce 10 million gal
3 (37.8 million L) in the first 10 days of production. Wells in the Barnett, Eagle Ford, Granite Wash,
4 Cleveland/Tonkawa Sand, Niobrara, Marcellus, and Utica Shales can produce 300,000 to 1 million
5 gal (1.14 to 3.78 million L) within the first 10 days; while Haynesville wells produce less, about
6 350,000 gal (1.32 million L) (Mantell. 2013bj.
7.1.2. Produced Water
7 During oil and gas production, other fluids which contain water are produced with hydrocarbons.
8 Throughout this production phase at oil and certain wet gas production facilities, produced water is
9 stored in tanks and pits that may contain free phase, dissolved phase, and emulsified crude oil in
10 the produced water.1 This crude oil can be present in the produced water container or pit, because
11 the crude oil is not efficiently separated out by the flow-through process vessels (such as three-
12 phase separators, heater treaters, or gun barrels) and passes through to these containers/pits. The
1 Dry natural gas occurs in the absence of liquid hydrocarbons; wet natural gas typically contains less than 85% methane
along with ethane and more complex hydrocarbons [Schlumberger. 2014).
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-10 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 produced water containers and pits containing oil at production facilities are typically regulated
2 under 40 CFR part 112, produced water containers or pits may also be subject to other applicable
3 state and or local laws, regulations and/or ordinances.
4 Lutz etal. [2013] evaluated data reported to the Pennsylvania Department of Environmental
5 Protection (PA DEP) for the time period January 2000 to December 2011. The data were divided
6 between conventional gas wells that might have been hydraulically fractured and hydraulically
7 fractured completions in the Marcellus Shale. The conventional wells produced less drilling water,
8 less flowback (when fractured), and less brine than the shale wells (Lutz etal., 2013: see Table Ij.
9 The average amount of produced water per well was 136,000 gal (514,000 L) for the conventional
10 wells and 1.38 million gal (5.211 million L) for the shale wells. The produced water to gas ratio was
11 1.27 gal (4.8 L) water per MMBtu for the shale wells, which was 2.8 times lower than for
12 conventional wells. Both the produced water and gas produced per well decreased over the four-
13 year period covered by the study. In contrast, conventional oil wells tend to have increased volumes
14 of produced water as they age, and in some cases, older wells may produce five times as much
15 water as new wells (U.S. GAP. 20121.
16 From experience in several shale formations, Mantell (2013b, 2011] characterized the amount of
17 produced water over the long term as high, moderate, or low. Wells in the Barnett Shale,
18 Cleveland/Tonkawa Sand, Mississippi Lime, and the Permian Basin can produce more than
19 1,000 gal (3,800 L) of water per million cubic feet (MMCF) of gas because of formation
20 characteristics. The most productive of these can be as high as 5,000 gal (19,000 L) per MMCF. As a
21 specific example, a high-producing formation in the western United States was described as
22 producing 4,200 gal (16,000 L) per MMCF for the life of the well (McElreath. 20111. The well was
23 fractured and stimulated with about 4 million gal (15 million L) of water and returned
24 60,000 gal (230,000 L) per day in the first 10 days, followed by 8,400 gal (32,000 L) per day in the
2 5 remainder of the first year.
2 6 Similarly, produced water from horizontal wells in the Barnett Shale decreased rapidly after the
27 wells began producing gas (Nicotetal.. 2014] (see Figure 7-4]. The data show a high degree of
28 variability, which was attributed by Nicotetal. (2014] to a few wells with exceptionally high water
29 production. When the produced water data were presented as the percentage of injected fluid, the
30 median exceeded 100% at around 36 months, and the 90th percentile was 350% (see Figure 7-5].
31 This means that roughly 50% of the wells were producing more water than was used in stimulating
32 production. Nicotetal. (2014] noted an inverse relationship between gas and water production but
33 did not identify the source or mechanism for the excess water. Systematic breaching of the
34 underlying karstic Ellenburger Formation was not believed likely; nor was operator efficiency or
35 skill. A number of geologic factors that could impact water migration were identified by (DOE,
36 2011a] in the Barnett Shale, including fracture height, aperture size, and density, fracture
37 mineralization, the presence of karst chimneys underlying parts of the Barnett Shale, and others,
38 but the impact of these on water migration was undetermined.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-11 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
20.000
S. 15.000 -
1
10.000
5000
12.000
10,000
- 8000 ra
6000
- 4000
- 2000
o
12
36
48
60
72
Months
Figure 7-4. Barnett Shale monthly water-production percentiles (5th, 30th, 50th, 70th, and 90th)
and number of wells with data (dashed line).
Source: Nicot et al. (2014). FP is the amount of water the flows back to the surface, commingled with
water from the formation. Reprinted with permission from Nicot, JP; Scanlon, BR; Reedy, RC; Costley,
RA. (2014). Source and fate of hydraulic fracturing water in the Barnett Shale: a historical perspective.
Environ Sci Technol 48: 2464-2471. Copyright 2014 American Chemical Society.
200
|g150 H
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100 -
II
Q
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Figure 7-5. Barnett Shale production data for approximately 72 months.
Source: Nicot et al. (2014). Flowback and produced water are reported as the percentage of injected
fluid. The dashed line shows the number of horizontal wells included. Data for each percentile show
declining production with time, but the median production exceeds 100% of the injected fluid. FP is
the amount of water the flows back to the surface, commingled with water from the formation.
Reprinted with permission from Nicot, JP; Scanlon, BR; Reedy, RC; Costley, RA. (2014). Source and fate
of hydraulic fracturing water in the Barnett Shale: a historical perspective. Environ Sci Technol 48:
2464-2471. Copyright 2014 American Chemical Society.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-12 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 The Niobrara, Granite Wash, Eagle Ford, Haynesville, and Fayetteville Shales are relatively dry and
2 produce between 200 and 2,000 gal (760 to 7,600 L) of produced water per MMCF (Mantell, 2013).
3 The Utica and Marcellus Shales are viewed as drier and produce less than 200 gal (760 L)
4 per MMCF. DOE (2011a] concluded that the characteristic small amount of produced water from
5 the Marcellus Shale was due either to its low water saturation or low relative permeability to water
6 (see Chapter 6). For dry formations, low shale permeability and high capillarity cause water to
7 imbibe into the formation, where it is retained permanently (He, 2011]. Engelder (2012] estimated
8 that more than half of the fracturing fluid could be captured within the Marcellus if imbibition
9 drove fluid just 5 cm (2 in] deep into reservoir rocks across the fracture surfaces. This estimate is in
10 agreement with the generalized analysis presented by Byrnes (2011], who estimated depths of 5 to
11 15 cm (2 to 6 in].
12 After fracture of coalbeds, water is withdrawn to liberate gas. CBM tends to produce large volumes
13 of water early on: more in fact, than conventional gas-bearing formations (U.S. GAP, 2012]. Within
14 producing formations, water production can vary for unknown reasons (U.S. GAP, 2012]. Data show
15 that CBM production in the Powder River Basin produces 16 times more water than in the San Juan
16 Basin (U.S. GAP. 2012].
17 The EPA (2015q] reported characteristics of long-term produced water for shale and tight
18 formations (see Table 7-3]. For shale, horizontal wells produced more water (900 gal/day] than
19 vertical wells (380 gal/day]. Typically, this would be attributed to the longer length of horizontal
20 laterals than vertical wells, but the data were not normalized to these lengths. The formation-level
21 data used to develop Table 7-3 appear in Table E-l of Appendix E.
22 The EPA (2015q] reported that a general rule of thumb is that flowback occurring in the first 30
23 days of production is roughly equal to the long-term produced water for unconventional
24 formations. As a specific example, from Pennsylvania Marcellus Shale data, the EPA determined that
25 for vertical wells in unconventional formations, 6% of water came from drilling, 35% from
26 flowback, and 59% from long-term produced water; and for horizontal wells the corresponding
27 numbers were 9%, 33%, and 58%. These values deviate from the rule of thumb, because the
28 Marcellus Shale was believed to generate low levels of flowback relative to other formations (U.S.
29 EPA. 2015q].
7.2. Flowback and Produced Water Data Sources
30 Unlike the evaluation of hydraulic fracturing fluid itself where the chemical composition may be
31 disclosed, knowledge concerning flowback and produced water composition comes from
32 measurements made on samples.
33 A number of factors are involved in the proper sampling and analyzing of environmental media
34 (U.S. EPA. 2013e: ATSDR. 2005: U.S. EPA. 1992]. There may be significant issues obtaining samples,
35 because the specialized equipment used to contain high-pressure natural gas is not designed for
36 producing environmental samples (Coleman, 2011].
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-13 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 To choose the correct analytical methods, it is necessary to have information on:
2 • Physical state of the sample.
3 • Identification of analytes of interest.
4 • Required sensitivity and quantitation limits.
5 • Analytical objective (i.e., unknown identification, monitoring).
6 • Required sample containers, preservation, and holding times.
7 Because some components of hydraulic fracturing fluid are proprietary chemicals, and subsurface
8 reaction products may be unknown, prior knowledge of the identity of analytes may not be
9 available. Consequently, studies may be limited in their ability to determine the presence of either
10 unknown or proprietary constituents contained in flowback or produced water simply because of
11 the lack of knowledge of the identities of the constituents.
12 After laboratory analysis, the results are evaluated according to quality criteria. Data may be judged
13 to meet applicable quality criteria as determined by the analytical methods or they may be
14 "flagged." Typically, encountered flags are non-detect, below reporting limit or diluted to meet
15 calibration requirements or because of matrix interference [e.g., Hayes, 2009].1 For produced
16 water, a primary interference is from high total dissolved solids (TDS). Interferences also arise from
17 agents which cause foaming and alter surface tension [Coleman. 2011). Diluted samples result in
18 higher detection limits, and thus lessen ability to identify lower concentrations in samples.
19 Because of identified limitations in existing methods, the EPA developed new methods for some
20 reported components of hydraulic fracturing fluids, including ethanols and glycols [U.S. EPA.
21 2014k], certain nonionic surfactants [DeArmond and DiGoregorio, 2013a], and acrylamide
22 [DeArmond and DiGoregorio. 2013b].2'3 Each of these methods are applicable to ground and surface
23 waters, and the last [DeArmond and DiGoregorio. 2013b] to waters with TDS well above 20,000
24 mg/L.
25 Generally, analytical methods are impacted by elevated TDS and chloride concentrations, especially
26 inorganic and wet chemistry methods [Nelson etal.. 2014: U.S. EPA. 2014b: Coleman. 2011). Matrix
27 interference impacts standard analysis (EPA Method 8015) for glycols, resulting in high detection
28 limits (10,000 [ig/L to 50,000 [ig/L) (Coleman. 2011).
29 Produced water levels of naturally occurring radionuclides may be 1,000 to 10,000 times the levels
30 of activity found in typical environmental water samples (U.S. EPA. 2014b). The standard EPA
31 method (Method 900.0) for gross alpha and gross beta involves evaporation of the sample to a layer
32 of residue and analyzing emitted alpha and beta particles. The method has several noted
1 Matrix interference occurs when components of the sample other than the analyte of interest have an effect on a
measurement [IUPAC. 2014).
2 The compounds included were: Diethylene Glycol, Triethylene Glycol, Tetraethylene Glycol, 2-Butoxyethanol and 2-
Methoxyethanol.
3 The compounds included were: C12-C16 and C18 alcohol ethoxylates, and alkylphenol ethoxylates.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-14 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 limitations, including known under representation of radium 228, and applicability to drinking
2 water samples with low levels (<500 mg/L) of TDS. As discussed below, produced water can have
3 much higher TDS levels. Because of these limitations, the EPA [2014b] developed an updated
4 method for the detection of gross alpha and gross beta to reduce the matrix interferences, although
5 further improvement is possible.1
6 Due to the high ionic strength and dissolved solids concentration of flowback water from shale
7 operations, Nelson et al. [2014] similarly found that traditional wet chemistry techniques (EPA
8 Methods 903.0 and 904.0) inefficiently recover radium from samples, with radium-226 recovery
9 sometimes less than 1% . This concern, which could lead to false negatives, was previously noted by
10 Demorest and Wallace [1992]. Nelson and coauthors demonstrated that an accurate assessment of
11 flowback radium levels can be performed through nondestructive high-purity germanium gamma
12 spectroscopy and emanation techniques. Studies reporting radium concentrations obtained directly
13 via wet chemistry techniques or studies reporting third-party radium data via wet chemistry
14 techniques may need to be evaluated appropriately as these techniques may underestimate the
15 total radium loads of produced water [Nelson etal., 2014].
16 Data have been generated from specific produced water studies [e.g.. Hayes. 2009] or compilations
17 from various sources, such as the USGS produced water database developed in 2002 [Breit, 2002]
18 and updated in 2014 [Blondes etal., 2014]. In this database, data were compiled from a variety of
19 sources, some of which we cite as examples below. The data that appear in this chapter and
20 Appendix E are drawn individually from scientific literature and published reports, where
21 necessary we have filled gaps with data from the USGS database.
7.3. Background on Formation Characteristics
2 2 Subsurface processes and resulting flowback and produced water composition vary depending
23 upon the mineralogy, geochemistry, and structure of formation solids, as well as, residence time
24 and other factors [Dahm etal.. 2011: Blauch etal.. 2009]. The mineralogy and structure of
25 formation solids are determined initially by deposition, when rock grains settle out of their
26 transporting medium [Marshak. 2004]. Generally, shale results from clays deposited in deep,
27 oxygen-poor marine environments, and sandstone results from sand deposited in shallow marine
28 environments [Alietal.. 2010: U.S. EPA. 2004]. Coal forms when carbon-rich plant matter collects in
29 shallow peat swamps. In the United States, coal is formed in both freshwater and marine
30 environments [NRG, 2010]. In the northern Rocky Mountains, coal formed within freshwater
31 alluvial systems of streams, lakes, and peat swamps. In contrast are parts of the Black Warrior
32 formation, which were deposited in brackish and marine settings [Horsey, 1981].
33 Variation in produced water composition follows, in part, from differences in formations which are
34 related to geologic processes. After deposition, physical, chemical, and biological processes occur as
1 The method developed for determining gross alpha (Th, U, and Po) by liquid scintillation is based on: manganese dioxide
coprecipitation followed by group separation of thorium, uranium and polonium on TRU Resin, stripping with ammonium
bioxalate, and pulse-shape discrimination liquid scintillation analysis. The average recovery was 74±11% of the known
concentration of 230Th with recoveries which ranged from 57% to 104%.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-15 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 sediments and are consolidated and cemented into rocks in a process called diagenesis. These
2 processes, which can also occur in existing sedimentary rocks, are caused by increased pressure,
3 temperature, and reaction with mineral-rich ground water [Rushing etal.. 2013: Marshak. 2004).
4 Diagenesis may either decrease or increase porosity and permeability through sediment
5 compaction and mineral precipitation, or through grain and cement dissolution [Alietal., 2010:
6 Schmidt and McDonald, 1979]. Temperature and pressure greatly affect the types and extent of
7 subsurface reactions, influencing the solubility of formation solids, saturation of pore waters, and
8 prevalence of precipitates [Rushing etal.. 2013).
7.4. Flowback Composition
9 The composition of returning hydraulic fracturing fluid changes with increasing residence time. In
10 this section, we present several examples from individual wells which demonstrate how
11 concentrations approach apparently asymptotic values during the first few days or weeks after
12 hydraulic fracturing.
7.4.1. General Characteristics
13 Several interacting factors that influence the composition of hydraulic fracturing flowback and
14 produced water are recognized in the scientific literature: (1] the composition of injected hydraulic
15 fracturing fluids, (2) the targeted geological formation and associated hydrocarbon products,
16 (3) the stratigraphic environment, and (4) subsurface processes and residence time [Barbotetal..
17 2013: Chapman etal.. 2012: Dahm etal.. 2011: Blauch etal.. 20091.
18 By design, hydraulic fracturing exposes fresh, organic- and mineral-rich surfaces. Subsurface
19 interactions between injected hydraulic fracturing fluids, formation solids, and formation waters
20 follow. As residence time increases, allowing in situ interactions between injected fluids, formation
21 fluids, and formation solids, changes in the geochemical content of flowback occur such that it still
22 largely reflects that of injected fluids, while later flowback and produced water reflect that of
23 formation-associated fluid [Rowan etal.. 2011).
7.4.2. Temporal Changes in Flowback Composition
24 Ionic loads, metals, naturally occurring radioactive material (NORM), and organics increase in
25 concentration as water production continues [Barbotetal., 2013: Murali Mohan et al., 2 013: Rowan
26 etal.. 2011). The causes include precipitation and dissolution of salts, carbonates, sulfates, and
27 silicates; pyrite oxidation; leaching and biotransformation of organic compounds; and mobilization
28 of NORM and trace elements. Multiple geochemical studies confirm this trend [Barbotetal., 2013:
29 Haluszczaketal.. 2013: Chapman etal.. 2012: Davis etal.. 2012: Gregory etal.. 2011: Blauch etal..
30 20091.
31 Concurrent precipitation of sulfates (e.g., BaS04) and carbonates (e.g., CaCOs] alongside decreases
32 in pH, alkalinity, and dissolved carbon load occur over time (Orem etal., 2014: Barbotetal., 2013:
33 Blauch etal.. 2009: Brinck and Frost. 2007). Orem and colleagues showed that organics within CBM
34 produced waters also decrease over time, possibly due to the exhausting of coal-associated waters
35 through formation pumping (Orem etal., 2007]. Decreases in microbial abundance and diversity
36 also occur over time after hydraulic fracturing (Murali Mohan et al., 2 013: Davis etal., 2012].
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-16 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 The primary dissolution of native and emplaced salts within the formation and the mobilization of
2 in situ brines constitute the major subsurface processes that control TDS levels in flowback and
3 produced water [Dresel and Rose. 2010: Blauch etal.. 2009).* Leaching of organics appears to be a
4 result of injected and formation fluids associating with shale and coal strata [Orem etal., 2014].
7.4.3. Total Dissolved Solids Enrichment
5 To varying degrees, produced water is enriched in dissolved solids, and the enrichment is
6 dependent upon residence time [Rowan etal., 2011]. As an example, TDS concentrations increased
7 until a limit was reached in flowback and produced water samples from four Marcellus Shale gas
8 wells in three southwestern Pennsylvanian counties [Chapman etal., 2012] (see Figure 7-6]. As is
9 shown in Figure 7-7, TDS in flowback from both Westmoreland County wells became consistent
10 with TDS concentrations cited for typical seawater (35,000 mg/L] within three days, and became
11 consistent with TDS cited for brines (greater than 50,000 mg/L] within five days (Chapman etal.,
12 2012]. TDS concentrations during production exceeded 188,000 mg/L for one well in Greene
13 County. Chapman et al.'s findings are further substantiated by Hayes and colleagues' earlier report
14 of produced water TDS concentrations in 19 Marcellus Shale wells in Pennsylvania and West
15 Virginia (Hayes, 2009]. From an initial injected median value of less than 1,000 mg/L, TDS
16 concentrations increased to a median value exceeding 200,000 mg/L within 90 days (Hayes, 2009].
17 In the Marcellus Shale, the cation portion of TDS is typically dominated by sodium and calcium,
18 whereas the anion portion is dominated by chloride (Chapman etal.. 2012: Blauch etal.. 2009]. In
19 section 7.6.4, we note that there is disagreement over whether increased salinity in Marcellus Shale
20 produced water is due to dissolution of salts or mixing of formation water with hydraulic fracturing
21 fluid.
1 Native salts are formed inside the rock matrix, and can include evaporite minerals such as halite (NaCl), polyhalite
(K2Ca2Mg(S04)4«2H20), celestite (SrS04),anhydrite (CaS04), kieserite (MgS04«H20), or sylvite (KC1) [Blauch etal.. 2009).
Hydrologic intrusion emplaces salts within formation pores and fractures [Blauch etal.. 2009).
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-17 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
200,000
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Figure 7-6. TDS concentrations measured through time for injected fluid (at 0 days), flowback,
and produced water samples from four Marcellus Shale gas wells in three
southwestern Pennsylvanian counties.
Data from Chapman etal. (2012).
7.4.4. Radionuclide Enrichment
1 Injected fluids used in hydraulic fracturing typically do not contain radioactive material [Rowan et
2 al., 2011].1 Shales and sandstones, however, are naturally enriched in various radionuclides, as
3 described below [Sturchio etal.. 2001]. Radium in pore waters or adsorbed onto clay particles and
4 grain coatings can dissolve and return within flowback [Langmuir and Riese, 1985]. Where data are
5 available, radium and TDS produced water concentrations are positively correlated with time
6 passed since hydraulic fracturing [Rowan etal., 2011: Fisher, 1998]. Radium remains adsorbed to
7 mineral surfaces in low saline environments, and then desorbs with increased salinity into solution
8 [Sturchio etal.. 2001]. Over the course of 20 days, Marcellus Shale produced waters from a gas well
9 were enriched almost fourfold in radium and from another gas well were enriched over twofold in
10 TDS concentrations as residence time increased [Chapman etal., 2012: Rowan etal., 2011] (see
11 Figure 7-7].
1 Recycling produced water may introduce radioactive material into hydraulic fracturing fluid. See section 8.4.3 and PA
DEPf2015b1.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 7-18 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
7,000
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Figure 7-7. Total radium and TDS concentrations measured through time for injected (day 0),
flowback, and produced water samples from mutually exclusive Greene County,
PA, Marcellus Shale gas wells.
Data from Rowan etal. (2011) and Chapman etal. (2012).
7.4.5. Leaching and Biotransformation of Naturally Occurring Organic Compounds
1 Many organics are known to leach naturally into formation water through association with shale,
2 sandstone, and coal strata [Benko and Drewes. 2008: Orem etal.. 2007). Oremetal. [2014] show
3 that formation and produced waters from shale plays that were not impacted by production
4 chemicals contain an array of organic compound classes associated with the formation. When
5 unconventional formations are hydraulically fractured, additional organics from the freshly
6 fractured hydrocarbon-bearing formation and the chemical additives contribute to a large increase
7 in flowback and produced water organic loads [Orem etal.. 2014).
8 The nature of the in-situ hydrocarbons reflects the formation's thermal maturity and heavily
9 influences the organic content of the produced water.1 The Marcellus Shale is largely considered a
10 mature formation and therefore consists of wet and dry gas [Barbotetal.. 2013: Repetskietal..
11 2008). Conversely, the Utica Shale is less thermally mature; available hydrocarbon resources
12 consist of oil, condensate, and gas [Repetski et al., 2008]. Additionally, some coals within the
13 eastern and west-central regions of the San Juan Basin produce little to no water during production,
14 due to the regional thermal maturity, hydrostratigraphy, and in situ trapping mechanisms [New
15 Mexico Bureau of Mines and Mineral Resources. 1994).
1 With increasing subsurface temperature after burial, petroleum source material (kerogen) produces hydrocarbons in a
sequence from methane (immature), to oil (more mature), to gas (mature). Gas is produced by thermal cracking of oil (PA
DCNR.2015).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 Dissolved organic carbon (DOC) concentrations decrease from hydraulic fracturing through
2 flowback in shales and coalbeds [Murali Mohan et al.. 2013: Orem etal.. 2007]. DOC sorption,
3 dilution with injected or formation water, biochemical reactions, and microbial transformation (i.e.,
4 biotransformation in the form of degradation or uptake) may all cause decreased concentrations of
5 DOC during flowback. Organic chemical additives injected during hydraulic fracturing offer a novel
6 carbon and energy source for biotic and abiotic reactions at depth. Injected organics include many
7 sugar-based polymer formulations, most notably of galactose and mannose (i.e., guar gum used as a
8 gelling agent); hydrocarbon distillates used in crosslinkers, friction reducers, and gelling agents;
9 and ethyl and ether glycol formulations used in non-emulsifiers, crosslinkers, friction reducers, and
10 gelling agents. (Wuchter etal.. 2013: Arthur etal.. 2009b: Hayes. 2009).
11 DOC and chloride concentrations exhibit strongly correlated inverse temporal trends (Barbotetal.,
12 2013: Chapman et al.. 2012] for flowback and produced water samples obtained from three
13 Marcellus Shale wells from the same well pad in Greene County, Pennsylvania (Cluff etal., 2014], as
14 shown in Figure 7-8. Chloride concentrations increased five- to six-fold as a function of residence
15 time (i.e., cumulative volumes of produced water). These chloride concentrations followed an
16 increasing linear trend during the first two weeks of flowback (see Figure 7-8a, inset) then began to
17 approach asymptotic levels later in production, indicating that injected fluids had acquired a brine
18 signature as a result of subsurface mixing, fluid-solid interactions, and mineral dissolution
19 processes.
20 DOC concentrations exhibit an inverse trend and decreased through flowback and production
21 (Figure 7-8b) (Cluff etal.. 2014). DOC levels decreased approximately twofold between injected
22 fluid and initial flowback samples (Figure 7-8b, inset). DOC concentrations decreased by 11-fold
23 over the study's time frame (nearly 11 months) and leveled off several months after hydraulic
24 fracturing, presumably as a result of in situ attenuation processes (Cluff etal.. 2014).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
100,000
90,000
80,000
70,000
c?
ao 60,000
;
.
__„„--'
_ --"
-
ir
£ 50,000 V
'C fmm
-2 40,000 J
30,000 I
b
20,000 r
10,000 T
7o,pga -i
60,000
^ 50,000
£ 40,000
~ 30,000
°
g 20,000
10,000
A • •
•
' " •*"
' • Welll
• Well 2
A Well 3
0 5 -10" 15
Days Post-Fracturing
„ i .--,-.--:-;--
0 50 100
150 200 250 300 350
Days Post-Fracturing
(a)
500
400 i
OD
&3QQ
u
0
Q
200
100
0
0
1 •- J
- - " 500
^400 1
to
£300 1
0 200
Q
100
0
(
• Well 1
* • Well 2
A Well 3
A* M
• • ,
AA
) 5 ^lO---"" 15
Da,ys •Post-Fracturing
•
50 100 150 200 250 300 350
Days Post-Fracturing
(b)
Figure 7-8. (a) Chloride (Cl) and (b) DOC concentrations measured through time for injected
(day 0), flowback, and produced water samples obtained from three Marcellus
Shale gas wells from a single well pad in Greene County, PA used for hydraulic
fracturing.
Data from Cluff et al. (2014). Reprinted with permission from Cluff, M; Hartsock, A; Macrae, J; Carter,
K; Mouser, PJ. (2014). Temporal changes in microbial ecology and geochemistry in produced water
from hydraulically fractured Marcellus Shale Gas Wells. Environ Sci Technol 48: 6508-6517. Copyright
2014 American Chemical Society.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 Orem etal. [2014] conducted a temporal study of two coalbed wells over the course of one year.
2 Their results suggest that organic compound concentrations decrease over time. This trend may be
3 due to pumping of water to the surface, which may exhaust coal-associated produced water.
4 Subsequent produced water would not be associated with the coal. This suggests that the early
5 produced water would contain the highest organic load [Orem etal., 2014].
6 As noted above, most literature addresses general organic parameters such as bulk total organic
7 carbon (TOG] or DOC instead of individual organic compounds [Sirivedhin and Dallbauman. 2004].
8 Emphasis on the prevalence of bulk organics as opposed to unique organics is due largely to the
9 lack of analytical standards for many compounds and also a lack of knowledge regarding the types
10 of organics to test in produced water samples [Schlegel etal., 2013: Strong etal., 2013].
7.5. Produced Water Composition
11 In this section, we discuss the characteristics of aggregated produced water data without regard for
12 temporal changes. Similarities between conventional and unconventional produced water are
13 noted and the variability between formation types is described. As we discuss below, produced
14 water may contain a range of constituents, but in widely varying amounts. Generally, these may
15 include:
16 • Salts, including those composed from chloride, bromide, sulfate, sodium, magnesium and
17 calcium.
18 • Metals including barium, manganese, iron, and strontium.
19 • Dissolved organics including BTEX and oil and grease.
20 • Radioactive materials including radium (radium-226 and radium-228].
21 • Hydraulic fracturing chemicals and their transformation products.
2 2 We discuss these groups of chemicals and then conclude by discussing variability within formation
2 3 types and within production zones.
7.5.1. Similarity of Produced Water from Conventional and Unconventional Formations
24 Unconventional produced water is reported to be similar to conventional produced waters in terms
25 of TDS, pH, alkalinity, oil and grease, TOG, and other organics and inorganics [Wilson, 2014:
2 6 Haluszczak etal.. 2013: Alley etal.. 2011: Hayes. 2009: Sirivedhin and Dallbauman. 2004]. Although
27 salinity varies in shales and tight formations, produced water is typically characterized as saline
28 [Lee andNeff. 2011: Blauch et al.. 2009]. Produced water is also enriched in major anions (e.g.,
29 chloride, bicarbonate, sulfate], cations (e.g., sodium, calcium, magnesium], metals (e.g., barium,
30 strontium], naturally occurring radionuclides (e.g., radium-226 and radium-228] (Chapman etal.,
31 2012: Rowan etal.. 2011]. and organics (e.g., hydrocarbons] (Orem etal.. 2007: Sirivedhin and
32 Dallbauman. 2004].
7.5.2. Variability in Produced Water Composition Among Unconventional Formation Types
33 Alley etal. (2011] compared geochemical parameters of shale gas, tight gas, and CBM produced
34 water. This comparison aggregated data on produced water from original analyses, peer-reviewed
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
1 literature, and public and confidential government and industry sources and determined the
2 statistical significance of the results. As shown in Table 7-4, Alley etal. [2011] found that of the
3 constituents of interest common to all three types of unconventional produced water (calcium,
4 chloride, potassium, magnesium, manganese, sodium, and zinc):
5 1) Shale gas produced water had significantly different concentrations from those of CBM;
6 2) Shale gas produced water constituent concentrations were significantly similar to those of
7 tight gas, except for potassium and magnesium; and
8 3) Five tight gas produced water constituent concentrations (calcium, chloride, potassium,
9 magnesium, and sodium) were significantly similar to those of CBM (Alley etal.. 2011).
10 The degree of variability between produced waters of these three resource types is consistent with
11 the degree of mineralogical and geochemical similarity between shale and sandstone formations,
12 and the lack of the same between shale and coalbed formations (Marshak. 2004).
Table 7-4. Compiled minimum and maximum concentrations for various geochemical
constituents in unconventional shale gas, tight gas, and CBM produced water (Alley
et al., 2011).
Source: (Alley et al., 2011).
Parameter
Alkalinity
Ammonium-N
Bicarbonate
Conductivity
Nitrate
Oil and grease
PH
Phosphate
Sulfate
Radium-226
Aluminum
Arsenic
Boron
Barium
Unit
mg/L
mg/L
mg/L
uS/cm
mg/L
mg/L
sud
mg/L
mg/L
pCi/g
mg/L
mg/L
mg/L
mg/L
Shale gasa
160-188
-
ND-4,000
-
ND-2,670
-
1.21-8.36
ND-5.3
ND-3,663
0.65-1.031
ND-5,290
-
0.12-24
ND-4,370
Tight gasb
1,424
2.74
10-4,040
24,400
-
42
5-8.6
-
12-48
-
-
0.17
-
-
CBMC
54.9-9,450
1.05-59
-
94.8-145,000
0.002-18.7
-
6.56-9.87
0.05-1.5
0.01-5,590
-
0.5-5,290
0.0001-0.06
0.002-2.4
0.01-190
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
Parameter
Bromine
Calcium
Cadmium
Chlorine
Chromium
Copper
Fluorine
Iron
Lithium
Magnesium
Manganese
Mercury
Nickel
Potassium
Sodium
Strontium
Uranium
Zinc
Unit
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Shale gasa
ND-10,600
0.65-83,950
-
48.9-212,700
-
ND-15
ND-33
ND-2,838
ND-611
1.08-25,340
ND-96.5
-
-
0.21-5,490
10.04-204,302
0.03-1,310
-
ND-20
Tight gasb
-
3-74,185
0.37
52-216,000
0.265
0.539
-
0.015
-
2-8,750
0.525
-
0.123
5-2,500
648-80,000
-
-
0.076
CBMC
0.002-300
0.8-5,870
0.0001-0.01
0.7-70,100
0.001-0.053
ND-0.06
0.05-15.22
0.002-220
0.0002-6.88
0.2-1,830
0.002-5.4
0.0001-0.0004
0.0003-0.20
0.3-186
8.8-34,100
0.032-565
0.002-0.012
0.00002-0.59
-, no value available; ND, non-detect. If no range, but a singular concentration is given, this is the maximum concentration.
3 n = 541. Alley etal. (2011) compiled data from USGS (2006): Mclntosh and Walter (2005): Melntosh et al. (2002) and
confidential industry documents.
b n = 137. Alley etal. (2011) compiled data from USGS (2006) and produced water samples presented in Alley etal. (2011).
c Alley etal. (2011) compiled data from Montana GWIC (2009): Thordsen etal. (2007): ESN Rocky Mountain (2003): Rice etal.
(2000); Rice (1999); Hunter and Moser (1990).
SU = standard units.
1 Shale gas produced water tends to be more acidic, as well as, enriched in strontium, barium, and
2 bromide. CBM produced water is highly alkaline, and it contains relatively low concentrations of
3 TDS (one to two orders of magnitude lower than in shale and sandstone). It also contains lower
4 levels of sulfate, calcium, magnesium, DOC, sodium, bicarbonate, and oil and grease than typically
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 observed in shale and sandstone produced waters [Alley etal., 2011: Dahmetal., 2011: Benko and
2 Drewes. 2008: Van Voast. 2003 j.1
7.5.3. General Water Quality Parameters
3 For this assessment, the EPA identified data characterizing the content of unconventional flowback
4 and produced water in a total of 12 shale and tight formations and CBM basins. These formations
5 and basins span 18 states. Note that in this subsection we treat all fluids as produced. As a
6 consequence, the variability of reported concentrations is likely higher than if the data could be
7 standardized to a specific point on the flowback-to-produced water continuum.
8 For most formations, the amount of general water quality parameter data is variable (see Table E-2
9 of Appendix E). Average pH levels range from 5.87 to 8.19, with typically lower values for shales.
10 Larger variations in average specific conductivity are seen among unconventional formations and
11 range from 213 microsiemens (n.S)/cm in the Bakken Shale to 184,800 [j.S/cm in Devonian
12 sandstones (see Table E-2 of Appendix E). Shale and tight formation produced waters are enriched
13 in suspended solids, as reported concentrations for total suspended solids and turbidity exceed
14 those of coalbeds by one to two orders of magnitude.
15 Of the data presented in Table E-3 of Appendix E, differences are evident between the Black
16 Warrior and the three western formations (Powder River, Raton, and San Juan). The Black Warrior
17 is higher in average chloride, specific conductivity, TDS, TOG and total suspended solids; and lower
18 in alkalinity and bicarbonate than the other three. These differences are due to the saline or
19 brackish conditions during deposition in the Black Warrior that contrast to the freshwater
2 0 conditions for the western basins.
21 The average dissolved oxygen (DO) concentrations of CBM produced water range from 0.39-1.07
22 mg/L (see Table E-3 Appendix E). By comparison, well-oxygenated surface water can contain up to
23 10 mg/L DO at 15 °C fU.S. EPA. 2012a). Thus, coalbed produced water is either hypoxic (less than 2
24 mg/L DO) or anoxic (less than 0.5 mg/L DO) and could contribute to aquatic organism stress (USGS,
25 2010: NSTC. 2000).
7.5.4. Salinity and Inorganics
26 The TDS profile of unconventional produced water is dominated by sodium and chloride, with large
27 contributions to the profile from mono- and divalent cations (Sun etal.. 2013: Guerraetal.. 2011).
28 In order of relative abundance, the following inorganic ions are typically found in highly saline
29 conventional produced water: sodium, chloride, calcium, magnesium, potassium, sulfate, bromide,
30 strontium, bicarbonate, and iodide (Lee and Neff, 2011). Shale and sandstone produced water tend
31 to be characterized as sodium-chloride-calcium water types, whereas CBM produced water tends to
32 be characterized as sodium chloride or sodium bicarbonate water types (Dahm etal., 2011).
33 Elevated levels of bromide, sulfate, and bicarbonate are also present (Sun etal., 2013). Elevated
34 strontium and barium levels are characteristic of Marcellus Shale flowback and produced water
1 Several had low representation in the Alley etal. (2011) data set, including the Appalachian Basin (western New York
and western Pennsylvania), West Virginia, eastern Kentucky, eastern Tennessee, and northeastern Alabama.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 [Barbotetal.. 2013: Haluszczaketal.. 2013: Chapman etal.. 20121. Data representing shales and
2 tight formations are presented in Table E-4 of Appendix E.
3 Rowan etal. [2015] acknowledge that the origin of saline water produced from the Marcellus Shale
4 is a matter of debate. One idea is that injected fluid returns at higher salinity, because of dissolving
5 halite and other minerals found in shale [Blauchetal., 2009]. Blauch and colleagues hypothesized
6 that salt layers bearing barium, calcium, iron, potassium, magnesium, sodium, and strontium likely
7 dissolve and contribute to flowback and produced water salinity [Blauchetal.. 2009]. However,
8 actual mixing of formation water and fracturing fluid was postulated by Haluszczaketal. [2013]
9 from arguments based on the near-neutral pH and low levels of chloride and sulfate in the
10 Marcellus data from Hayes [2009], as well as, the relationship between chloride and bromide. Engle
11 and Rowan determined that water chemistry during the first 90 days of production is controlled by
12 mixing of injected and formation waters and stimulation of bacterial sulfate reduction [Engle and
13 Rowan, 2014: Haluszczaketal., 2013]. Rowan etal. [2015] argue, based on an observed shift to
14 isotopically heavier water, that produced water actually contains formation water.: Alternately,
15 Barbotetal. [2013] concluded from analysis of Marcellus Shale produced water that mixing (with
16 formation water] alone could not explain the observed patterns in chloride concentrations.
17 Marcellus Shale produced water salinities range from less than 1,500 mg/L to over 300,000 mg/L,
18 as shown by Rowan etal. [2011]. By comparison, the average salinity concentration for seawater is
19 35,000 mg/L. The TDS concentration of CBM produced water can be as low as 500 mg/L ranging to
20 nearly 50.000 mg/L fDahm etal.. 2011: Benko and Drewes. 2008: Van Voast. 20031. Lower
21 dissolved solids are expected from CBM produced water, in part, because some coals developed in
22 fresh water environments [Bouska, 1981]. Dahm etal. [2011] report TDS concentrations from a
23 composite CBM produced water database (n = 3,255] for western basins that often are less than
24 5,000 mg/L (85% of samples]. In other cases, as for the Black Warrior basin, TDS can be higher
25 along with concentrations of species that contribute to TDS (See Table E-5 Appendix E], such as
26 calcium, chloride, and sodium.
7.5.5. Metals
27 The metals content of unconventional produced water varies by well and site lithology, but is
28 typically dominated by the same metals that are associated with conventional produced water.
29 Unconventional produced water may also contain low levels of heavy metals (e.g., chromium,
30 copper, nickel, zinc, cadmium, lead, arsenic, and mercury] [Hayes. 2009]. Data illustrating metal
31 concentrations in produced water appear in Tables E-6 and E-7 of Appendix E.
1 The produced water becomes isotopically heavier because of increased prevalence of Oxygen-18 in the water, compared
to the more prevalent Oxygen-16.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
7.5.6. Naturally Occurring Radioactive Material (NORM) and Technologically Enhanced
Naturally Occurring Radioactive Material (TENORM)
7.5.6.1. formation Solids Levels of NORM
1 Elevated uranium levels in formation solids have been used to identify potential areas of natural
2 gas production for decades [Fertl and Chilingar, 1988]. Marine black shales are estimated to contain
3 an average of 15-60 ppm uranium depending on depositional conditions [Fertl and Chilingar,
4 1988]. Shales that bear significant levels of uranium include the Barnett in Texas, the Woodford in
5 Oklahoma, the New Albany in the Illinois Basin, the Chattanooga Shale in the southeastern United
6 States, and a group of black shales in Kansas and Oklahoma [Swanson, 1955].
7.5.6.2. Produced Water Levels of TENORM
7 When exposed to the environment or concentrated NORM is termed technologically-enhanced
8 naturally-occurring radioactive material (TENORM].1 Radioactive materials commonly present in
9 shale and sandstone sedimentary environments include uranium, thorium, radium, and their decay
10 products. These are present in most unconventional produced water, but particularly so in
11 Marcellus Shale produced water [Rowanetal., 2011: Fisher, 1998]. Low levels of uranium and
12 thorium return during flowback, typically in the concentrated form of mineral phases or organic
13 matter, due to insolubility under prevailing reducing conditions encountered within shale
14 formations (Nelson etal.. 2014: Sturchio etal.. 20011
15 Conversely, radium, a decay product of uranium and thorium, is known to be relatively soluble
16 within the redox range encountered in subsurface environments [Sturchio etal.. 2001: Langmuir
17 andRiese, 1985]. Dissolved radium primarily occurs as Ra2+, but it complexes with carbonate,
18 chloride, and sulfate ions as well [Sturchio etal.. 2001: Langmuir and Riese. 1985]. Ra2+ can also
19 substitute for various cations (e.g., Ba2+, Ca2+, and Sr2+] during mineral precipitation, as is
20 sometimes the case with barite or anhydrite precipitation (Rowanetal., 2011].
21 Data from the Marcellus Shale show that radium and TDS produced water concentrations are
22 positively correlated (Rowanetal.. 2011: Fisher. 1998]. This pattern is expected for other
23 formations because radium remains adsorbed to mineral surfaces in low salinity environments,
24 then desorbs as solution salinity increases (Sturchio etal., 2001]. Controlling for this TDS
25 dependence, Marcellus Shale produced water contains statistically more radium than
26 non-Marcellus Shale produced water, with a median total radium content of 2,460 picocuries per
27 liter (pCi/L] (n = 52] compared to 1,011 pCi/L (n = 91], respectively (Rowan etal., 2011]. Radium
28 levels in Marcellus produced water are at several thousand picocuries per liter, with maximum
29 concentrations of total radium (radium-226 and radium-228], radium-226 and radium-228
30 reported at approximately 18,000, 9,000, and 1,300 pCi/L, respectively fRo wan etal.. 20111 (see
31 Table E-8 in Appendix E]. Data from the Pennsylvania TENORM produced water study (PA DEP,
1 The U.S. EPA Office of Radiation rhttp://www.epa.gov/radiation/tenorm/) states that technologically enhanced
naturally occurring radioactive material (TENORM) is produced when activities such as uranium mining, or sewage
sludge treatment, concentrate or expose radioactive materials that occur naturally in ores, soils, water, or other natural
materials. Formation water containing radioactive materials would contain NORM, because they are not exposed;
produced water would contain TENORM because it has been exposed to the environment.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
1 2015) showed similar elevated levels, and consistently showed higher medians in unconventional
2 compared to conventional formations (Table E-8 in Appendix E).
7.5.7. Organics
3 The organic content of produced water varies by well and lithology, but consists of certain naturally
4 occurring and injected organic compounds. These organics may be dissolved in water or, for the
5 case of oil production, in the form of a separate or emulsified phase. Produced water organics can
6 contain any of the following: (1) volatile organic compounds (VOCs) such as benzene and toluene,
7 (2) semi-volatile organic compounds (SVOCs) such as phenols; and/or (3) non-VOCs such as
8 macromolecular natural organic matter [Orem etal.. 2014: Hayes. 2009: Benko and Drewes. 2008:
9 Orem etal.. 2007: Sirivedhin and Dallbauman. 2004). Table 7-5 presents data from naturally
10 occurring organic chemicals in produced water.
Table 7-5. Concentration ranges (mg/L) of several classes of naturally occurring organic
chemicals in conventional produced water worldwide (reported in Neff, 2002).
Source: (Neff, 2002)
Chemical class
TOC
Total organic acids
Total saturated hydrocarbons
Total benzene, toluene, ethylbenzene, and xylenes (BTEX)
Total PAH
Total steranes/triterpanes
Ketones
Total phenols (primarily C0-C5 phenols)
Concentration range (mg/L)
<0.1->11,000
<0.001-10,000
17-30
0.068-578
0.040-3
0.140-0.175
1-2
0.400-23
11 Several classes of naturally occurring organic chemicals are present in conventional and
12 unconventional produced waters, with large concentration ranges (Lee and Neff. 2011]. In addition
13 to data on total organic carbon (TOC) and dissolved organic carbon (DOC) as indicators of the
14 presence of organics, specifically identified organics include saturated hydrocarbons, BTEX, and
15 polycyclic aromatic hydrocarbon (PAHs) (see Table E-9 of Appendix E). Data are lacking on the
16 presence and concentration of many other types of organic chemicals that might be present in
17 produced water, because of their use in hydraulic fracturing fluid. There are a number of reasons
18 for this difference, some of which could be related to analytical limitations, limited focus of
19 produced water studies, and undocumented subsurface reactions.
7.5.8. Reactions within Formations
2 0 The introduction of hydraulic fracturing fluids into the target formation induces a number of
21 changes to formation solids and fluids that influence the chemical evolution and composition of
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 flowback and produced water. These changes can result from physical processes (e.g., rock
2 fracturing and fluid mixing) and geochemical processes (e.g., introducing novel, oxygenated fluids)
3 that mobilize trace or major constituents into solution.
4 The creation of fractures exposes new formation surfaces to interactions involving hydraulic
5 fracturing fluids and existing formation fluids. Formations targeted for unconventional
6 development are composed of detrital, cement, and organic fractions. For example, elements
7 potentially available for mobilization when exposed via fracturing include calcium, magnesium,
8 manganese, and strontium in cement fractions, and silver, chromium, copper, molybdenum,
9 niobium, vanadium, and zinc in organic fractions. The storage or release of these elements in newly
10 exposed surfaces is variable and not well studied, in part due to the vast number of possible
11 interactions occurring continuously in the environment at the rock surface (Vine and Tourtelot,
12 19701
13 Contact with and physical mixing of hydraulic fracturing fluids with existing formation brines also
14 influences the geochemical evolution of produced water. For instance, Marcellus Shale brines have
15 high concentrations of bromide, calcium, chloride, magnesium, sodium, and strontium (Engle and
16 Rowan, 2014). Hydraulic fracturing fluid contains elevated levels of DOC, alkalinity, and sulfate
17 (Engle and Rowan, 2014). Consequently, flowback acquires a geochemical signature reflecting both
18 injected and formation fluids. Produced water containing bothAlthough some constituents of
19 hydraulic fracturing fluids are known to readily degrade in the environment, little is known
20 regarding how the subsurface degradation proceeds or how the constituents interact within a
21 complex matrix of organics (Mouser et al., In Press).
7.6. Spatial Trends
22 As was reported for the volume of produced water (see Section 7.2.2), the composition of produced
23 water varies spatially on a regional to local scale according to the geographic and stratigraphic
24 locations of each well within a hydraulically fractured formation (Bibby etal.. 2013: Lee and Neff,
25 2011). Spatial variability of produced water content occurs (1) between plays of different rock
26 sources (e.g., coal vs. sandstone), (2) between plays of the same rock type (e.g., Barnett Shale vs.
27 Bakken Shale), and (3) within formations of the same source rock (e.g., northeastern vs.
28 southwestern Marcellus Shale) (Barbotetal.. 2013: Alley etal.. 2011: Breit. 2002).
29 Geographic variability in produced water content has been established at a regional scale for
30 conventional produced water. As an example, Benko and Drewes (2008) demonstrate TDS
31 variability in conventional produced water among fourteen western geologic basins (e.g., Williston,
32 San Juan, and Permian Basins). Median TDS in these basins range from as low as 4,900 mg/L in the
33 Big Horn Basin to as high as 132,400 mg/L in the Williston Basin based on over 133,000 produced
34 water samples from fourteen basins (Benko and Drewes. 2008).*
1 Data were drawn from the USGS National Produced Water Geochemical Database v2.0. Published updates made in
October 2014 to the database (v2.1) are not reflected in this document.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 High IDS (more than 200,000 ppm) is common throughout the central portion of the United States
2 in various basins. Low TDS (<10,000 ppm) was found in the basins of the Rocky Mountains, and
3 sometimes in Texas and California. In other areas, there was a mixture of mid-range, which in the
4 case of Illinois was correlated to the depth of producing zones [Breit, 2002].
5 Data further illustrating variability within shale, tight-gas and coalbed formations at both the
6 formation and local scales are presented and discussed in Section E-3 of Appendix E.
7.7. Spill Impacts on Drinking Water Resources
7 Surface spills of flowback and produced water from unconventional oil and gas production have
8 occurred across the country and in some cases have caused impacts to drinking water resources, as
9 described in this section. Released fluids, if not contained on-site, may flow into nearby surface
10 waters or infiltrate into ground water via soil. In this section, we first briefly describe the potential
11 for spills from produced water handling equipment Next, we address individually-reported spill
12 events. These have originated from pipeline leaks, well blowouts, well communication events, and
13 leaking pits and impoundments. We then summarize several studies of aggregated spill data, most
14 of which are based on state agency spill reports. The section concludes with discussion of two cases.
7.7.1. Produced Water Management and Spill Potential
15 Produced water is typically transported from the wellhead through a series of pipes or flowlines to
16 on-site storage or treatment units [GWPC and IOGCC, 2014]. Faulty connections at either end of the
17 transfer process or leaks or ruptures in the lines carrying the fluid can result in surface spills.
18 Recovered fluids may be transferred to surface impoundments for long-term storage and
19 evaporation. Surface impoundments are typically uncovered earthen pits that may or may not be
20 lined. Recovered fluids may overflow from surface impoundments due to improper pit design and
21 weather events.
22 Produced water that is to be treated or disposed of off-site is typically stored in storage tanks or
23 impoundments until it can be loaded into transport trucks for removal [Gilmore etal.. 2013]. Tank
24 storage systems are typically closed loop systems in which produced water is transported from the
25 wellhead to aboveground storage tanks through interconnecting pipelines [GWPC and IOGCC.
26 2014]. Failure of connections and lines during the transfer process or the failure of a storage tank
2 7 can result in a surface release of fluids.
28 Depending on its characteristics, produced water, may be recycled and reused on-site. It can be
29 directly reused without treatment (after blending with freshwater] or it can be treated on-site prior
30 to reuse (Boschee. 2014]. As with other flowback management options, these systems also present
31 spill potential during transfer of fluids.
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7.7.2. Spills of Hydraulic Fracturing Flowback and Produced Water from Unconventional Oil
and Gas Production
7.7.2.1. Pipeline Leaks
1 In some locations, pipelines are used to transport produced water. Aggregated information on
2 pipeline leaks from the whole country is not available. This section, rather, contains examples of
3 incidents that have occurred. A leak was detailed in a field report from PA PEP (2009a], which
4 described a leak from a 90-degree bend in an overland pipe carrying a mixture of flowback and
5 freshwater between two impoundments. Along a 0.4 mi (0.6 km) length of the impacted stream,
6 168 fish and 6 salamanders were killed; beyond a confluence at 0.6 km with a creek no additional
7 dead fish were found. The release was estimated at 250 bbl (11,000 gal or 40,000 L). In response to
8 the incident, the pipeline was shut off, a dam was constructed for recovering the water, water was
9 vacuumed from the stream, and the stream was flushed with fresh water (PA PEP, 2009a].
10 In January 2015, 70,000 barrels (2,940,000 gal or 11,130,000 L) of produced water containing
11 petroleum hydrocarbons (North Dakota Department of Health. 2015] were released from a broken
12 pipeline that crosses Blacktail Creek in Williams County, ND. The response included placing
13 adsorbent booms in the creek, excavating contaminated soil, removing oil-coated ice, and removing
14 produced water from the creek. The electrical conductivity and chloride concentration in water
15 along the creek, the Little Muddy River, and Missouri River were found to be elevated above
16 background levels, as were samples taken from ground water recovery trenches.
17 More incidents from North Dakota are documented at the North Dakota Department of Health
18 (NDDOH) Environmental Health web site (see http://www.ndhealth.gov/EHS/Spills/]. For the
19 period from November, 2012 to November 2013, NDDOH reported 552 releases of produced water
20 which were retained within the boundaries of the production or exploration facility and 104 which
21 were not (see http://www.ndhealth.gov/ehs/foia/spills/ChartWebPageOG 20121101
22 20131111.pdf).
7.7.2.2. Well Blowouts
23 Fingerprinting of water from two monitoring wells in Killdeer, ND, was used to determine that
24 brine contamination in the two wells resulted from a well blowout during a hydraulic fracturing
25 operation. Although the target formation was the Bakken Shale, data indicated that the residual
26 signatures of the brine were characteristic of the overlying Madison limestone formation (U.S. EPA,
27 2015)]. Prior research into out-of-zone hydraulic fracturing of the Bakken formation indicated that
28 a large number of hydraulically fractured wells contain water that is external to the Bakken Zone
29 fArkadakskiy and Rostron. 2013a: Arkadakskiy and Rostron. 2012a: PetermanetaL 20121 The
30 Bakken wells that contained external water were found to all contain water from the Mississippian
31 Lodgepole formation (part of the Madison Group]. The average volume of external water was 34%
32 and the external water volume ranged from 10% to 100% (Arkadakskiy and Rostron, 2013a].
33 Another example of a well blowout associated with a hydraulic fracturing operation occurred in
34 Clearfield County, PA. The well blew out, resulting in an uncontrolled flow of approximately
35 35,000 gal (132,000 L] of brine and fracturing fluid, along with an unquantified amount of gas;
36 some of the fluids reportedly reached a nearby stream (Barnes, 2010]. The blowout occurred while
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 the company was drilling out the plugs used to isolate one fracture stage from another. An
2 independent investigation found that the primary cause of the incident was that the only blowout
3 preventer on the well had not been properly tested. In addition, the company did not have certified
4 well control experts on hand or a written pressure control procedure [Vittitow, 2010]. In North
5 Dakota, a blowout preventer failed, causing a release of between 50 and 70 barrels per day (2,100
6 gal/day or 7,900 L/day and 2,940 gal/day or 11,000 L/day) of flowback and oil [Reuters. 20141. A
7 3-ft berm was placed around the well for containment. Frozen droplets of oil and water sprayed on
8 a nearby frozen creek. Liquid flowing from the well was collected and trucked offsite. Multiple well
9 communication events reported by the media have also led to flowback and produced water spills
10 ranging from around 700 to 35,000 gal (2,600 L to 130,000 L) (Vaidyanathan. 2013a].
7.7.2.3. Leaks from Pits and Impoundments
11 Leaks of flowback and produced water from on-site pits and impoundments have caused releases
12 as large as 57,000 gal (220,000 L) and have caused surface and ground water impacts
13 (Vaidyanathan. 2013b: PBFC2011: PADEP 2010]. VOCs have been measured in groundwater near
14 the Duncan Oil Field in New Mexico downgradient of an unlined pit storing produced water (Sumi,
15 2004: Eiceman. 1986]. Aspects of environmental transport from unlined pits are discussed below in
16 Section 7.8.5.
17 Two of the EPA's retrospective case studies found potential impacts from produced water
18 impoundments. In the southwest Pennsylvania case study (U.S. EPA, 2015k], elevated chloride
19 concentrations and their timing relative to historical data suggested a recent ground water impact
20 to a private water well occurred near an impoundment. The water quality trends suggested that the
21 chloride anomaly was related to the impoundment, but site-specific data were not available to
22 provide definitive assessment of the causes(s] and the longevity of the impact Evaluation of other
23 water quality parameters did not provide clear evidence of flowback or produced water impacts.
24 In the Wise County, TX case study (U.S. EPA, 2015m], impacts to two water wells were attributed to
25 brine, but the data collected for the study were not sufficient to distinguish among four possible
26 sources, one of which was leaks from reserve pits and/or impoundments. The others were: brine
27 migrating from underlying formations along wellbores, brine migrating from underlying formations
28 along natural fractures, and brine migrating from a nearby brine injection well. Alternate sources
29 for the impacts were considered, including road salting, landfill leachate, septic tanks, and animal
30 wastes, but evaluation of data showed that these were not likely. A third well experienced similar
31 impacts, but a landfill leachate source could not be ruled out in that case. Ricther and Kreitler
32 (1993] reviewed sources of salinity to ground water resources by evaluating reviewing major
33 sources, which included natural saline ground water, halite dissolution, sea-water intrusion, oil-
34 field brine, agriculture, saline seeps and road salt For each source Ricther and Kreitler (1993]
35 provided a state-by-state review of the potential occurrence, which can be used as a general guide
36 to potential sources of salt at a specific area of interest.
7.7.2.4. Data Compilation Studies
37 Environmental impacts from hydraulic fracturing-related fluids have been explored to a limited
38 extent in recent scientific literature (Brantley etal.. 2014: Farag and Harper. 2014: Gross etal..
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1 2013: Olmsteadetal.. 2013: Papoulias and Velasco. 2013: Vidic etal.. 2013: Considine etal.. 2012:
2 Rozell and Reaven. 20121.
3 From an Oklahoma Corporation Commission database of almost 13,000 releases reported from
4 1993 to 2003, Fisher and Sublette [2005] determined that the primary origins of produced water
5 releases were leaks from lines, tanks, wellheads, with lesser numbers of releases from surface
6 equipment, and pits. The most common cause was overflows followed by illegal activity, storms, fire
7 accidents and corrosion. For these types of releases, the median release volume ranged from 20 bbl
8 (840 gal or 3,180 L) to 60 bbl (2,500 gal or 9,500 L), and the maximums from 200 bbl (8,400 gal or
9 31,800 L) to 2,800 bbl (118,000 gal or 445,200 L).
10 As noted in Text Box 5-14 of Chapter 5, U.S. EPA(2015n] characterized hydraulic fracturing-related
11 spills. Of the spills related to hydraulic fracturing activities (457 spills), 225 (49%) were spills of
12 flowback and produced water. These spills were characterized with respect to volumes, spilled
13 materials, sources, causes, environmental receptors, containment, and response. Most of the
14 produced water spills in the EPA study occurred in Colorado (48%) and Pennsylvania (21%).
15 Flowback and produced water constitute 84% (approximately 2.0 million gal or 7.6 million L) of the
16 total volume of hydraulic fracturing-related spills as calculated from Appendix B of U.S. EPA
17 [2015I1J.1 Flowback and produced water spills were characterized by numerous low-volume spills;
18 half of the spills with reported volumes were less than 1,000 gal (3,800 L), and few spills exceeded
19 10,000 gal (38,000 L). Of the volume of spilled flowback and produced water, 16% was recovered
20 for on-site use or disposal, 76% was reported as unrecovered, and 8% was unknown. The potential
21 impact of the unknown and unrecovered volume on drinking water resources is unknown.
22 Known sources for flowback and produced water spills include storage containers (e.g., pits,
23 impoundments, or tanks), wells or wellheads, hoses or lines, and equipment. Storage containers
24 accounted for 58% of flowback and produced water spills. The fewest spills occurred from wells
25 and wellheads, but these spills had the greatest spill volumes compared to all other sources.
26 The causes of these spills were human error (38%), equipment failure (17%), failures of container
27 integrity (13%), miscellaneous causes (e.g., well communication, well blowout), and unknown
28 causes. Most of the volume spilled (74%), however, came from spills caused by a failure of
29 container integrity.
30 In some of the cases, spills reached environmental receptors: soil (141 spills), surface water (17
31 spills), and ground water (1 spill); of these spills, 13 reached both soil and surface water.
32 Consequently 146 unique produced water spills reached environmental receptors, accounting for
33 65% of the 225 cases and accounting for approximately 422,000 gal (1.60 million L) of flowback
34 and produced water. Spills with known volumes that reached a surface water body ranged from
Chemicals and products, fracturing fluid, fracturing water, equipment fluids, hydrocarbons, and unknown fluids
constitute the additional 16% (approximately 360,000 gal or 1.4 million L) of the total volume of hydraulic
fracturing-related spills as calculated from Appendix B of U.S. EPAf2015d).
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 less than 170 gal (640 L) to almost 74,000 gal (280,000 L). In 30 cases, it is unknown whether a spill
2 of flowback and produced water reached an environmental receptor of any type.
3 Gross etal. (2013) analyzed the Colorado Oil and Gas Conservation Commission's database for
4 ground water BTEX concentrations linked to hydraulic fracturing-related surface spills between
5 July 2010 and July 2011 in Weld County, CO. Only spills with an impact on ground water were
6 included in the study. The 77 reported spills accounted for less than 0.5% of nearly 18,000 active
7 wells. Forty-six of the 77 spills consisted of produced water and oil. Of the remaining spills, 23
8 consisted of only oil and 8 consisted of only produced water. Thus the results that follow include
9 cases with no produced water spill. From these composited spills, benzene concentrations in 90%
10 of the ground water samples exceeded 5 [ig/L, the U.S. drinking water standard. Additionally, 30%
11 of toluene, 12% of ethylbenzene, and 8% of xylene sample concentrations exceeded 1 mg/L, 0.7
12 mg/L and 10 mg/L, respectively (Gross etal.. 2013).
13 Based on five spills for which volumes were reported, the average volume of a produced water spill
14 was 294 gal (1,110 L), ranging from 42 (160 L) to 1,176 gal (4,450 L) (Gross etal.. 2013). Spill areas
15 averaged 2,120 ft2, with an average depth of 7 ft Tank battery systems and production facilities
16 were the biggest volume sources of spills with ground water impacts. Equipment failure was the
17 most common cause of spills with ground water impacts. Shallow ground water within the study
18 area (Niobrara Shale within the Denver-Julesburg Basin) is the main source of water for residents
19 due to limited surface water availability. Of the 77 reported spills, secondary containment was
20 absent from 51 of them (Gross etal.. 2013).
21 As noted from the Colorado (Gross etal., 2013) and Oklahoma (Fisher and Sublette, 2005) studies,
22 oil releases may occur alongside produced water spills. Review of recent oil field incidents in North
23 Dakota also shows incidents with both produced water and oil releases
24 (http://www.ndhealth.gov/EHS/Spills/). Oil releases are characterized by a number of features
25 including their unique hydrocarbon composition and physical properties. Impacts can include:
26 surface runoff, infiltration into soils, formation of sheens and oil slicks on surface waters,
27 evaporation, oxidation, biodegradation, emulsion formation, and particle deposition (U.S. EPA.
28 1999).
29 A statistical analysis of oil and gas violations in Pennsylvania found that violations regarding
30 structurally unsound impoundments or inadequate freeboard (vertical distance from the surface
31 water level to the overflow elevation) were the second most frequent type of violation with 439
32 instances in the period from 2 008 to 2010 (Olawoyin et al.. 2013). In a study of pits and
3 3 impoundments in West Virginia, Ziemkiewicz etal. (2014) found common problems of slope
34 stability and liner deficiencies. Construction quality control and quality assurance were often
35 inadequate; the authors found a lack of field compaction testing, use of improper types of soil,
36 excessive slope lengths, buried debris, and insufficient erosion control (Ziemkiewicz etal.. 2014).
37 Brantley et al. (2014) reviewed PA DEP's online oil and gas compliance database for notices of
38 violation issued to companies developing unconventional gas resources. Between May 2009 and
39 April 2013, 8 spills of flowback and produced water ranging from more than 4,000 gal (15,000 L) to
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1 more than 57,000 gal (220,000 L) reached surface water resources. The spills typically resulted in
2 local impacts to environmental receptors and required remediation and monitoring. However, the
3 study indicated the likelihood of a leak or spill of hydraulic fracturing-related fluids was low (less
4 than 1%, based on 32 large spills outof more than 4,000 complete wells). Due to lack of data,
5 specific impacts to the eight receiving surface waters were not discussed, other than noting the
6 produced water had contacted the surface water.
7 The Brantley et al. (2014) analysis of the PA DEP positive determination letters written in response
8 to water-user complaints illustrates the importance of pre-drilling sampling, as it is one criterion
9 that allows operators to refute the presumption that drilling caused water supply impacts (see
10 Chapter 6). The importance of this pre-drilling sampling and analysis is highlighted by naturally
11 occurring exceedances of EPA secondary MCLs for manganese and iron in private wells in
12 Pennsylvania (Boyer etal.. 2011: Williams etal.. 19981 Boyer etal. (2011) state that more than
13 40% of private water wells in Pennsylvania fail to meet federal drinking water standards. Boyer et
14 al. (2011) analyzed pre-drilling samples from private water wells in northeastern and
15 southwestern Pennsylvania and showed that 20% (of 222 wells) failed the drinking water standard
16 for iron and 27% (of 203 wells) failed for manganese.1 Williams etal. (1998). in their evaluation of
17 over 200 wells in Bradford, Tioga, and Potter counties in northeastern Pennsylvania, indicate about
18 50% of the wells exceeded secondary MCLs for iron and manganese.2 According to Boyer et al.
19 (2011), higher concentrations of these constituents tend to be associated with the sodium chloride
20 (Na-Cl) type ground water often found in valleys in zones of more restricted ground water flow
21 (portions of aquifers with low permeability). Saline water can be found at shallow depths in these
22 areas (Williams etal.. 1998).
23 As an example of another set of criteria for assessing sites potentially contaminated by hydraulic
24 fracturing activities, the EPA (2012f) developed an approach to study sites where the impacts to
25 drinking water resources and the potential sources of the impacts are unknown, but may have been
26 the object of water-user complaints. The approach is based on a tiered scheme where results from
27 each tier are used to refine activities in higher tiers. The four tiers were as follows:
28 • Verify potential issue:
29 o Evaluate existing data and information from operators, private citizens, state and
30 local agencies, and tribes (as appropriate).
31 o Conduct site visits.
32 o Interview stakeholders and interested parties.
33 • Determine approach for detailed investigations:
34 o Conduct initial sampling of water wells, taps, surface water and soils.
1 Percentage of other parameters failing standards: 17% of 233 wells for pH, 3% of 233 wells for TDS, <1% of 226 wells
for chloride, 1% of 218 wells for Barium, <1% of 177 wells for sulfate, 33% of 125 wells for coliforms, 4% of 115 wells for
arsenic, 8% of 122 wells for fecal coliforms, 32% of 102 samples for turbidity.
2 Naturally occurring constituents occasionally exceeding EPA primary MCLs in this area include barium, combined
radium-226 and radium-228, and arsenic.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 o Identify potential evidence of drinking water contamination.
2 o Develop conceptual site model describing possible sources and pathways of the
3 reported or potential contamination.
4 o Develop, calibrate, and test fate and transport model(s).
5 • Conduct detailed investigations to detect and evaluate potential sources of contamination:
6 o Conduct additional sampling of soils, aquifer, surface water, and produced water
7 pits/tanks where present
8 o Conduct additional testing, including further water testing with new monitoring
9 points, soil gas surveys, geophysical testing, well mechanical integrity testing, and
10 stable isotope analyses.
11 o Refine conceptual site model and further test exposure scenarios.
12 o Refine fate and transport model(s) based on new data.
13 • Determine the source(s) of any impacts to drinking water resources:
14 o Develop multiple lines of evidence to determine the source(s) of impacts to
15 drinking water resources.
16 o Exclude possible sources and pathways of the reported contamination.
17 o Assess uncertainties associated with conclusions regarding the source(s) of
18 impacts.
19 This tiered assessment strategy provides an outline for collecting data and evaluating lines of
20 evidence for determining whether impacts have occurred.
7.7.3. Case Studies of Potentially Impacted Sites
7.7.3.1. Flowback and Produced Water Release from an Illegal Discharge Impacts Surface
and Ground Water in Lycoming County, Pennsylvania
21 An estimated 6,300 gal to more than 57,000 gal (24,000 to 220,000 L) of Marcellus Shale produced
22 water was illegally discharged atXTO Energy Inc.'s Marquardtpad and flowed into the
23 Susquehanna River watershed in November 2010 [U.S. EPA. 2013g].1 Overland and subsurface flow
24 of released fluids affected proximal surface water, a subsurface spring, and soil. No impacts to
25 drinking water wells and springs within 1 mile of the release were observed at the last sampling
26 date (17 days post-spill). However, residual, soil-associated produced water constituents could
27 reach drinking water resources in the future through surface runoff or infiltration to the ground
28 water (Science Applications International Corporation. 2010). The release, which occurred atXTO's
29 Marquardt 8537H well pad in Penn Township, Lycoming County, PA, was discovered after a routine
3 0 inspection by the Pennsylvania Department of Environmental Protection. Subsequent investigation
1 Violations associated with this incident can be found at the Pennsylvania Department of Environmental Protection's Oil
and Gas Compliance Report database found at http://www.portal.state.pa.us/portal/
server.pt/community/oil and gas compliance report/20299 under the following inspection IDs: 1928978,1928992, and
1929005.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 revealed that flowback and produced water had been discharging into surface waters for over
2 two months after the fluid was released from multiple tanks with open or missing valves on
3 November 16, 2010 fU.S. EPA. 2013gj.
4 Geochemical characterization of this produced water indicated concentrations of barium, chloride,
5 iron, manganese, and IDS above Pennsylvania's surface water quality standards, and above the
6 statewide health standards for medium-specific concentrations (SHS MSCs) for ground water use in
7 residential and nonresidential settings [Science Applications International Corporation. 2010). The
8 produced water also contained elevated levels of bromide, calcium, sodium, and strontium, which
9 lack state surface water quality standards and SHS MSCs [Science Applications International
10 Corporation. 2010].
11 Post-spill surface water delineations indicated that released fluids migrated to an unnamed stream
12 known as Tributary 19617. The released fluids migrated approximately 1,400 ft (427 m) overland
13 to a depression which contains a natural fracture with a hydrological connection to a spring
14 [Schmidley and Smith. 2011). The distance from the depression to the stream is approximately
15 600 ft (183 m). Released fluids also drained through surface soils into ground water, which was
16 then released in seeps to the spring and stream; elevated levels of barium, bromide, calcium,
17 chloride, sodium, strontium, and TDS resulted (U.S. EPA. 2013gj. Elevated levels of these
18 constituents, particularly barium, bromide, and strontium, were indicative of Marcellus Shale
19 flowback and produced water that had mixed with surface water (Brantley etal.. 2014). Barium and
20 chloride were the only dissolved constituents detected in the stream that exceeded state surface
21 water quality standards; the remaining constituents lack established state surface water quality
22 standards.
2 3 Results from XTO's temporal study of surface water quality confirmed impacts to the stream from
24 produced water. Surface water quality was characterized at the confluence of the stream and
25 spring, and at the stream's upstream and downstream segments, for 65 days post-spill (Science
26 Applications International Corporation. 2010]. Downstream barium and bromide levels were one to
27 two orders of magnitude greater than upstream levels through this period. In addition, stream
28 strontium levels were two to three orders of magnitude greater than upstream levels at this time.
29 Chloride was initially detected in the stream with concentrations exceeding state water quality
30 standards (Schmidley and Smith, 2011]. Average chloride concentrations for stream samples were
31 two orders of magnitude greater than upstream concentrations (PADEP, 2011c]. By January 2011,
32 stream chloride concentrations had dropped below the limit established by Pennsylvania's surface
33 water quality standards.
34 Delineation of chloride concentrations within on-site soil indicated soil impacts due to overland
35 flow of flowback and produced water (Science Applications International Corporation, 2010]. Five
36 hundred tons of affected soil was consequently excavated for off-site disposal. Chloride
37 concentrations decreased with increased distance from the spill site but remained elevated above
38 background levels even at distances of a few thousand feet (Science Applications International
39 Corporation. 2010]. Produced water constituents that were present in soil at concentrations above
40 background levels (i.e., barium, sodium, strontium] could be available for long-term runoff and
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 infiltration. For instance, the continued presence of chloride in affected soils is likely due to
2 precipitated chloride salts in soil pores from residual produced water [Science Applications
3 International Corporation. 2010). which may leach later. Near-term sampling (up to 17 days after
4 the spill) found no elevated constituents indicative of runoff or infiltration of produced water when
5 XTO sampled 14 drinking water wells and springs within one mile of the well pad. XTO was ordered
6 to create a storm water collection system for off-site disposal of impacted storm water and to
7 establish on-site water monitoring wells to track long-term ground water quality between the well
8 pad and the stream [Schmidley and Smith. 2011). Other cases of illegal dumping have been
9 reported [Caniglia. 2014: U.S. EPA. 2013g: Paterra. 2011].
7.7.3.2. Flowback Fluid Reaches Towanda Creek Due to Well Blowout in Bradford County,
Pennsylvania, Causing Short-Term Impacts
10 The Chesapeake Energy ATGAS 2H well, located in Leroy Township, Bradford County, PA,
11 experienced a wellhead flange failure on April 19, 2011, during hydraulic fracturing operations.
12 Approximately ten thousand gallons (38,000 L) of flowback fluids spilled into an unnamed tributary
13 of Towanda Creek, a state-designated trout stock fishery and a tributary of the Susquehanna River
14 (USGS. 2013b: SAIC and GES. 2011). Chesapeake conducted post-spill surface and ground water
15 monitoring (SAIC and GES. 2011). In addition, the EPA, PADEP, and Chesapeake collected split
16 samples from seven private wells within the vicinity of the blowout. The EPA requested thatthe
17 Agency for Toxic Substances and Disease Registry (ATSDR) evaluate the environmental data
18 collected from seven private wells to determine whether harmful health effects would be expected
19 from consuming or using the well water. Data from Pre-blowout private well samples, collected
2 0 approximately six months prior to drilling activity at the site, were included in the evaluation.
21 Between the pre- and post-blowout samples, ATSDR (2013] determined that there was factor of ten
22 increases in some analyte concentrations (methane, barium, calcium, chloride, magnesium,
23 manganese, potassium, and sodium) and a factor of 7 increase in iron concentration in one well
24 (RW04) near the site. Other wells showed elevated levels of certain analytes.1 ATSDR concluded
25 that although the available data suggested that the ground water near this site is impacted by gas
26 activities, the data for RW04 did not conclusively indicate an impact ATSDR (2013) concluded that
27 further evaluation is needed to characterize any relationship between the drinking water wells and
28 aquifers as a result of changes in site conditions. Further sampling would be required to determine
29 current impacts, trends, and chronic exposures to ground water constituents related to natural gas
30 activities.
1 Elevated sodium levels were detected in 6 wells, levels in 5 of them (RW02, RW03, RW05, RW06, and RW07) may be of
concern to sensitive subpopulations; while the last (RW04) would exceed the dietary guideline for both sensitive and the
general population. ATSDR judged that elevated lithium concentration in two wells (RW04 and RW06) could be a concern
to individuals undergoing lithium therapy. One well (RW02) showed elevated arsenic concentrations, but these were
similar in the pre- and post-blowout samples. Gross alpha radiation levels were above the EPA maximum contaminant
level in one well (RW03), and ATSDR did not expect adverse health effects from drinking this water. ASTDR did not expect
adverse health effects for the user of five private wells (RW01, RW03, RW05, RW06 (excepting for possible lithium
impacts) and RW07).
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1 Chesapeake concluded that there were short-term impacts to surface waters of a farm pond within
2 the vicinity of the well pad, the unnamed tributary, and Towanda Creek following the event [SAIC
3 and GES. 20111 The lower 500 feet of the unnamed tributary exhibited elevated chloride, IDS, and
4 specific conductance, which returned to background levels in under a week. Towanda Creek
5 experienced these same elevations in concentration, but only at its confluence with the unnamed
6 tributary; elevated chloride, IDS, and specific conductance returned to background levels the day
7 after the blowout [SAIC and GES. 20111.
7.7.4. Roadway Transport of Produced Water
8 Accidents during transportation of hydraulic fracturing produced water are a possible mechanism
9 leading to potential impacts to drinking water. Nationwide data are not available, however, on the
10 number of such accidents that result in impacts. An estimate of releases from truck transport of
11 produced water could be made as follows:
Total number of wells x Produced water volume per well
Total number of truckloads =
Produced water volume per truck
12 Then the total distance traveled by all trucks is given by:
Total distance traveled = Total number of truckloads x Distance per truck
13 The number of crashes impacting drinking water resources can be estimated from:
Total crashes impacting drinking water resources
= Fraction of crashes releasing waste that impacts drinking water resources
x Fraction of all crashes releasing waste x Crashes per distance
14 Estimates of all but one of the quantities in these calculations can be made from various literature
15 sources, which are described in Appendix E. A key parameter is the number of crashes of trucks per
16 distance traveled. In 2012, the U.S. Department of Transportation (DOT) estimated thatthe number
17 of crashes per 100 million highway miles driven of a type of large truck was 110, which is a
18 relatively small number. A key parameter that is unknown is the number of crashes which impact
19 drinking water resources, so definitive estimates of impacts to drinking water resources cannot be
20 made. Alternatively, as an upper bound on drinking water resource impacts, the number of crashes
21 which release waste can be estimated. Based on various assumptions and scenarios presented in
22 Appendix E, the number of crashes with releases is bounded by the low tens of events. At 20 m3per
23 truckload, the volumes are low relative to the typical volume of produced water.
24 Several limitations are inherent in this analysis, including differing rural road accident rates and
25 highway rates, differing produced water endpoints, and differing amounts of produced water
26 transported. Further, the estimates present an upper bound on impacts, because not all releases
27 would reach or impact drinking water resources.
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7.7.5. Studies of Environmental Transport of Released Produced Water
1 In this subsection, we describe transport study results that illustrate how produced waters have
2 been shown to be transported from historical disposal practices and spills. Over the history of oil
3 production in the U.S., produced water disposal methods have evolved from land application to
4 storage in unlined ponds to deep well injection [Whittemore. 2007], although some unlined pits
5 continue in use where allowed by states. The changes in practice occurred because of pollution
6 impacts: first to surface waters and aquatic biota, and then to ground water from disposal ponds.
7 Evaluation of sites contaminated by these historic practices sheds light on the potential for
8 transport of released produced water, as discussed below.
9 Impacts to ground water might occur following a spill on land. When the liquid is highly saline, its
10 migration is affected by its high density and viscosity compared with that of fresh water. When
11 spilled flowback or produced water flows over land, a fraction of the liquid is subject to infiltration.
12 The fraction depends on the rate of release, surface cover (i.e., pavement, cracked pavement,
13 vegetation, bare soil, etc.), slope of the land surface, subsurface permeability, and the moisture
14 content in the subsurface.
15 The potential for impacts from produced water spills depends on the distance from the source to
16 receptor; the distance depends on local topography. One study investigated receptor distances on a
17 formation basis [Entrekinetal., 2011]. The distance between gas wells and drainage ways was
18 determined to average 273 m (890 ft] for the Marcellus Shale and 353 m (1160 ft] for the
19 Fayetteville Shale (Entrekinetal., 2011]. Some wells were much closer, being as close as 1 m (3.28
20 ft]. For one location in each formation a separate analysis gave a mean estimate of 153 m (500 ft]
21 for the Marcellus Shale and 130m (430 ft] for the Fayetteville Shale. The average distance to public
22 drinking water intakes was 15 km (9.32 mi). The average distance to public water supply wells was
23 37 km (23.0 mi) for the Marcellus Shale and 123 km (76.4 mi) for the Fayetteville Shale. As the
24 density of gas development increases the number of gas wells located close to drainage ways and
25 public water supply wells may also increase.
26 For example, Whittemore (2007) described a site with relatively little infiltration due to moderate
27 to low permeability of silty clay soil and low permeability of underlying shale units. Thus, most of
28 the historically surface-disposed produced water at the site flowed into surface drainages.
29 Observed historic levels of chloride in receiving waters resulted from the relative balance of
30 produced water releases and precipitation runoff, with high concentrations corresponding to low
31 stream flows. Persistent surface water chloride contamination was attributed to slow flushing and
3 2 discharge of contaminated ground water.
33 Transport from the land surface to the water table is further characterized in general by flow
34 through variably water-saturated media, preferential flow paths, fractures in clays, and
3 5 macropores. Preferential flow paths along microscale heterogeneities are known to exist and
3 6 dominate transport even after cycles of repeated drying and rewetting. The effect of flowback on
3 7 transport of colloids has recently been evaluated in laboratory sand columns. The authors found
3 8 that flowback increased the mobility of colloidal particles, which potentially serve as a source of
39 aquifer contamination (Sangetal., 2014].
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1 In another study, Ottonetal. [2007] reported on a site in Oklahoma where two abandoned pits
2 were major sources for releases of produced water and oil. Saline water from the pits flowed
3 through thin soils and readily percolated into underlying permeable bedrock. Deeper, less
4 permeable bedrock was contaminated by salt water later in the history of the site, presumably due
5 to fractures [Otton et al., 2007]. The mechanisms proposed were lateral movement through
6 permeable sand bodies, vertical movement along shale fractures, and possibly increased
7 permeability from clay flocculation and shrinkage due to the presence of highly saline water [Otton
8 etal.. 20071
9 Because it is denser than freshwater, saline produced water can migrate downward through
10 aquifers. Whittemore [2007] reported finding oilfield brine with a chloride concentration of 32,900
11 mg/L at the base of the High Plains aquifer. Where aquifers discharge to streams, saline stream
12 water has been reported, although at reduced concentrations [Whittemore. 2007]. likely due to
13 diffusion within the aquifer and mixing with stream water. The stream flow rate, in part,
14 determines mixing of substances in surface waters. High flows are related to lower chemical
15 concentrations, and vice versa, as demonstrated for bromide by States etal. [2013] for the
16 Allegheny River.
17 Generally, the deeper that brine can move into an aquifer, as impacted by the volume and timing of
18 the release, the longer the duration of contamination [Whittemore. 2007]. Kharakaetal. [2007]
19 reported on studies at a site in Oklahoma with one abandoned and two active unlined brine pits.
20 Produced water from these pits penetrated 3- to 7-m thick shale and siltstone units, creating three
21 plumes of high-salinity water (5,000 to 30,000 mg/L TDS). The impact of these plumes on the
22 receiving water body (Skiatook Lake] was judged to be minimal, although the estimate was based
23 on a number of notably uncertain transport quantities [Ottonetal., 2007].
24 Chloride impacts from produced water spills were studied through scenario modeling releases of
25 100 bbl (4,200 gal or 15,900 L] and 10,000 bbl (420,000 gal or 1.59 million L] (API. 2005]. The
26 scenarios included transport through a homogeneous or heterogeneous unsaturated zone using the
27 HYDRUS-1D model (Simuneketal.. 1998] and mixing within the top portion of a shallow aquifer
28 using a specially developed spreadsheet model. The results of the scenario modeling indicated that
29 ground water quality is unlikely to be impaired for spills with small soil penetration depths, which
30 correspond to spills distributed over large areas. Large spills of 100,000 bbl (4.2 million gal or 15.9
31 million L] over sandy unsaturated zones were found to have a high potential to impact ground
32 water quality (API. 2005]. Spills of less than 100 bbl (420 gal or 1,590 L] were not modeled and
33 were presumed to have low impacts based on the results from the larger spills. The results were
34 constrained by the underlying assumptions of HYDRUS-1D—that there were no preferential flow
35 paths, including fractured systems, systems with macropores, or fine scale heterogeneities. More
36 rapid and spatially extensive transport could occur in these settings.
7.7.6. Coalbed Methane
37 A CBM produced water impoundment in the Powder River Basin of Wyoming was studied for its
38 impact on ground water (Healy etal.. 2011: Healy etal.. 2008]. Infiltration of water from the
39 impoundment was found to create a perched water mound in the unsaturated zone above bedrock
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1 in a location with historically little recharge. The subsurface sediments were found to be highly
2 heterogeneous both physically and chemically, which increased the complexity of studying the site.
3 Elevated concentrations of IDS, chloride, nitrate, and selenium were found at the site. For example,
4 IDS exceeded 100,000 mg/L in one lysimeter sample, while the concentration was 2,275 mg/L in a
5 composite CBM produced water sample [Healy etal.. 2008]. Most of the solutes found in the ground
6 water mound did not originate with the CBM produced water, but rather were the consequence of
7 dissolution of previously existing salts and minerals. The mechanisms were thought to be gypsum
8 dissolution, cation exchange, and pyrite dissolution. Data from other sites indicated that the study
9 site's ground water chemistry may not be typical and that the same phenomena may not occur at
10 other sites in the basin [Healy etal., 2011].
7.7.7. Transport Properties
11 The identified constituents of flowback and produced water include inorganic chemicals in the form
12 of cations and anions (including various types of metals, metalloids, and non-metals, and
13 radioactive materials, among others] and organic chemicals, including identified compounds in
14 various classes, and unidentified materials measured as TOG and DOC. Environmental transport of
15 these chemicals depends on properties of the chemical and properties of the environment, and is
16 extensively discussed in Section 5.8.3. In this section we discuss the characteristics of transport for
17 inorganics and note that some inorganics may move with the water, while many of the others are
18 influenced by reactions. For organic chemicals identified in produced water, we discuss EPI Suite™
19 estimates of the main transport parameters identified in Chapter 5, while noting the influences of
2 0 salinity and temperature on these properties.
21 Transport of inorganic chemicals depends on the nature of ground water and vadose zone flow, and
22 potential reactions among the inorganic chemical, solid surfaces, and geochemistry of the water.
23 Some inorganic anions (i.e., chloride and bromide] move with their carrier liquid and are mostly
24 impacted by physical transport mechanisms: flow of water and dispersion. In addition to the flow-
25 related processes, transport of most inorganics is driven by three mechanisms related to
26 partitioning to the solid phase: adsorption, absorption, and precipitation. The effects of these
27 mechanisms depend on both chemical and environmental characteristics, including the surface
28 reactivity, solubility, and redox sensitivity of the contaminant; and the type and abundance of
29 reactive mineral phases, and the ground-water chemistry (U.S. EPA. 2007]. Through the use of
30 transport models, the effects of physical transport mechanisms and chemical processes are
31 integrated. Examples of transport models for reactive metals include the Geochemist's Workbench
32 (Bethke. 2014] and Hydrus (Simuneketal.. 1998].
3 3 Properties of organic chemicals which tend to affect the likelihood that a chemical will reach and
34 impact drinking water resources if spilled include high chemical mobility in water, low volatility,
35 and high persistence in water. Using the EPA chemical database EPI Suite™, we were able to obtain
36 actual or estimated physicochemical properties for 86 of the 134 organic chemicals identified in
37 produced water and listed in Appendix A. A portion of these, 66, are used in the chemical mixing
38 stage (see Appendix Table C-8]. EPI Suite™ results were generated for solubility, octanol water
39 partition coefficient (Kow), and the Henry's constant (see Figure 7-9]. The log Kow values are of the
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Hydraulic Fracturing Drinking Water Assessment
Chapter 7 - Flowback and Produced Water
1 identified organic chemicals skewed positively, indicating some of the chemicals have low mobility
2 which may result in less extensive dissolved contaminant plumes in ground water. These
3 compounds, however, have a higher tendency to sorb to particulate or colloidal materials and hence
4 be transported in systems where particle transport is dominant, for example: colloid transport in
5 ground water and sediment transport in surface water. The log Henry constant values tend to be
6 below 0 indicating that at equilibrium the concentration in air is less than the concentration in
7 water. This behavior is reflected in the log solubility plot, as the solubilities skew conversely toward
8 high values.
9 The EPI Suite™ results are constrained by their applicability to one temperature (25 °C), and
10 salinity (low). Temperature changes impact Henry's constant, Kow, and solubility, and depend on the
11 characteristics of the chemical and ions present (Borrirukwisitsaketal., 2012: Schwarzenbach et
12 al.. 2002). In some cases the effect changes exponentially with salinity (Schwarzenbach etal.. 2002).
13 Therefore, property values that depart from the EPI Suite™ values are expected for produced water
14 at elevated temperature and salinity.
-10 -8 -6 -4 -2 0 2 4 6 8 10
Measured log K,,,, [L/kg]
20 More Mobile
15
ii
e
T 10
0 L
-10 -8 -6 -4 -2 0 2 4 6 8 10
Estimate log Kow [L/kg]
20
10
I 5
-10 -9-8-7-6-5-4-3-2-10 1 2 3 4 5 6 7 8 9 10
Estimated log Solubility [mg/L <§> 25C]
-10 -9-8-7-6-5-4-3-2-10 1 2 3 4 5 6 7 8 9 10
Estimated log Henry's Law Constant [atm m* mole ' @ 25C]
Figure 7-9. Histograms of physicochemical properties of 86 organic chemicals identified in
produced water (physicochemical properties estimated by EPI Suite™).
7.8. Synthesis
15 After hydraulic fracturing is completed, the operator reduces injection pressure and water is
16 allowed to flow back from the well to prepare for oil or gas production. The flowback water may
17 contain fracturing fluid, fluid from the surrounding formation, and hydrocarbons. Initially this
18 flowback is mostly fracturing fluid, but as time passes, the produced water becomes more similar to
19 the water in the formation. This water is stored at the surface for eventual reuse or disposal.
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 Impacts to drinking water from flowback and produced water can occur if spilled flowback or
2 produced water enters surface water bodies or aquifers.
7.8.1. Summary of Findings
3 The volume and composition of flowback and produced water vary geographically, both within and
4 between different formations with time and with other site-specific factors. High initial rates of
5 flowback decrease as time continues. The amount of fracturing fluid returned to the surface varies,
6 and typically averages 10% to 25%. In most cases, lower flow rates of produced water continue
7 throughout gas production.1 In some formations (i.e., the Barnett Shale), the ultimate volume of
8 produced water can exceed the volume of hydraulic fracturing fluid because of inflow of water.
9 The composition of flowback changes with time as the hydraulic fracturing fluid contacts the
10 formation and mixes with the formation water. At the same time, reactions occur between the
11 constituents of the fracturing fluid and the formation. Although varying within and between
12 formations, shale and tight gas produced water typically contains high levels of TDS (salinity) and
13 associated ionic constituents (bromide, calcium, chloride, iron, potassium, manganese, and sodium).
14 Produced water may contain toxic materials, including barium, cadmium, chromium, lead, mercury,
15 nitrate, selenium, and BTEX. CBM produced water can have lower levels of salinity if its coal source
16 was deposited under freshwater conditions.
17 Flowback and produced water spills are known to have occurred across the country. The causes
18 identified for these spills are container and equipment failures, human error, well communication,
19 blowouts, pipeline leaks, and illegal dumping. Spills due to trucking accidents are possible, but
20 accident rates in the United States suggest only a small number of such releases occur.
21 USGS studies of impacts of produced water disposal in unlined pits document the potential for
22 surface releases (in these cases over multiple years) that have led to ground water impacts.
23 Contaminant plumes can be traced to high TDS water disposed of in the pits, or geochemical
24 reaction between infiltrating low-TDS water, in the case of CBM produced water, releasing existing
25 minerals from the unsaturated zone to ground water.
7.8.2. Factors Affecting the Frequency or Severity of Impacts
2 6 The potential of spills of flowback and produced water to affect drinking water resources depends
27 upon the release volume, duration, and composition. Larger spills of greater duration are more
28 likely to reach a nearby drinking water resource than are smaller spills. The composition of the
29 spilled fluid will also impact the severity of a spill, as certain constituents are more likely to affect
30 the quality of a drinking water resource. Low-volume and short-duration spills are less likely to
31 cause impacts, (see Section 7.7.5).
32 Potential impacts to water resources from hydraulic fracturing-related spills are expected to be
3 3 affected by watershed and water body characteristics. For example, overland flow is affected by
34 surface topography and surface cover. Infiltration of spilled produced water reduces the amount of
1 Note that increasing produced water flow rates are indicative of water breakthrough and declining oil production.
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1 water threatening surface water bodies. However, infiltration through soil may lead to ground
2 water impacts. Produced water with lower constituent concentrations may produce lesser impacts,
3 but the USGS studies of CBM produced water impoundments described in section 7.7.5 showed
4 impacts caused by CBM water mobilizing existing minerals. The USGS studies on historical disposal
5 of saline produced water in unlined pits detected ground water plumes discharging into surface
6 water bodies. The potential impact to drinking water in such cases depends on the location of
7 drinking water wells and the size of any surface water supply reservoir.
7.8.3. Uncertainties
8 We first discuss data gaps in our overall knowledge of flowback and produced water; closing such
9 gaps would enable us to better predict impacts on drinking water resources. Second, we present
10 uncertainties that, based on site-specific conditions, also affect our ability to determine potential
11 impacts.
7.8.3.1. General Data Gaps
12 Knowledge of volume and some compositional aspects of flowback and produced water are known
13 from published sources. Most of the available data on TENORM has come from the Marcellus Shale,
14 where these are typically high in comparison to the limited data available from other formations.
15 Only a few studies have attempted to sample and characterize the organic fraction of flowback and
16 produced water; some data are available for shale and CBM, but none are available for tight
17 formations. The reported organic chemical data from flowback likely does not capture the full range
18 of chemicals that may be present, either as original components of the hydraulic fracturing solution
19 or transformation products generated in the subsurface.
20 Characterization of produced water organics is limited by several factors. Development or use of
21 proper analytical procedures depends upon knowing the identities of injected chemicals. Because
22 the formulation of hydraulic fracturing fluids can contain proprietary chemicals, the exact
23 formulations are not available. In addition, subsurface transformations yield degradation products,
24 which themselves must have appropriate analytical methods. Further difficulties are due to matrix
25 interference from high-TDS produced water. These problems result in the need to develop new
26 methods for analyzing both organics and inorganics in produced water.
27 Nationwide data on spills of flowback and produced water are limited in two primary ways: the
28 completeness of reported data cannot be determined, and individual states' reporting requirements
29 differ [U.S. EPA, 2015n]. Despite various studies, the total number of spills occurring in the United
30 States, their release volumes and associated concentrations, can only be roughly estimated because
31 of underlying data limitations.
7.8.3.2. Uncertainties at Individual Spill Sites
3 2 Spills of flowback and produced water present many uncertainties that, in combination, limit our
3 3 ability to predict impacts on drinking water resources. Spills vary in volume, duration, and
34 composition. The spilled liquid could be fracturing fluid mixed with formation water in a
35 proportion that depends on the time that has passed since fracturing. As described in Section 7.7,
36 spills may originate from blowouts, well communication, aboveground or underground pipeline
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1 breaks, leaking impoundments, failed containers, human error (including illegal activities, failure to
2 detect spills, and failure to report spills) or unknown causes. The difference between these causes
3 affect the size and location of the spill. In addition, the factors governing transport of spilled fluid to
4 a potential receptor vary by site: the presence and quality of secondary or emergency containment
5 and spill response; the rate of overland flow and infiltration; the distance to a surface water body or
6 drinking water well; and transport and fate processes. Impacts to drinking water resources from
7 spills of flowback and produced water depend on environmental transport parameters, which can
8 in principle be determined but are unlikely to be known or adequately specified in advance of a
9 spill.
10 Because some constituents of flowback and produced water are constituents of natural waters (e.g.,
11 bromide in coastal surface waters) or can be released into the environment by other pollution
12 events (e.g., benzene from gasoline releases, or bromide from coal mine drainage), baseline
13 sampling prior to impacts is one way to increase certainty of an impact determination. Further
14 sampling and investigation may be used to develop the linkage between a release and a
15 documented drinking water impact Produced water spill response typically includes delineation of
16 the extent of oiled soils, sheens on water surfaces, and the extent of saline water. Extensive
17 characterization of produced water is typically not part of spill response, and therefore the
18 chemicals, and their concentrations, potentially impacting drinking water resources are not usually
19 known.
7.8.4. Conclusions
2 0 Flowback and produced water has the potential to affect the quality of drinking water resources if it
21 enters into a surface or ground water body used as a drinking water resource. This can occur
2 2 through spills at well pads, or during transport of flowback. Specific impacts depend upon the spill
23 itself, the environmental conditions surrounding the spill, water body and watershed
24 characteristics, and the composition of the spilled fluid. Flowback and produced water may contain
25 toxic constituents and can potentially render water unpalatable or unsafe to drink. Conclusive
2 6 determination of impacts to water resources depends on commitment of resources to the
2 7 implementation of sampling, analysis and evaluation strategies
Text Box 7-1. Research Questions Revisited.
2 8 What is currently known about the frequency, severity, and causes of spills of flowback and produced
29 water?
30 • Surface spills of flowback and produced water from unconventional oil and gas production have occurred
31 across the country. Some produced water spills have affected drinking water resources, including a few
32 private drinking water wells. The majority of flowback and produced water spills are under 1,000
33 gallons. The causes identified for these are container and equipment failures, human error, well
34 communication, blowouts, pipeline leaks, and illegal dumping.
3 5 What is the composition of hydraulic fracturing flowback and produced water, and what factors might
3 6 influence this composition ?
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 • The composition of flowback and produced water must be determined through sampling and analysis,
2 both of which have limitations. The former due to the ability to access through production equipment and
3 the latter due to issues with identifying target analytes in advance of analysis and the existence of
4 appropriate analytical methods.
5 • The geochemical content of water flowing back initially reflects injected fluids. After initial flowback,
6 returning fluid geochemistry shifts to reflect the geochemistry of formation waters and formation solids.
7 • According to available literature and data, conventional and unconventional flowback and produced
8 water content are often similar with respect to the occurrence and concentration of many constituents.
9 • The least statistical variability in produced water content is exhibited between shale gas and tight gas
10 produced water, and the most statistical variability is exhibited between shale gas and coalbed methane
11 produced water.
12 • Much produced water is generally characterized as saline (with the exception of most coalbed methane
13 produced water) and enriched in major anions, cations, metals, naturally occurring radionuclides, and
14 organics.
15 • Shale and coalbed produced water is enriched in benzene. Benzene is a constituent of concern in
16 Marcellus Shale, Raton CBM, and San Juan CBM produced water. Shale produced water is more likely to
17 contain elevated average total BTEX levels than other unconventional produced water.
18 • Typically, unconventional produced water contains low levels of heavy metals. Elevated strontium and
19 barium levels, however, are characteristic of Marcellus Shale flowback and produced water. CBM and, in
20 particular, shale produced water are likely to contain NORM levels of concern.
21 • Composition data were limited. Most of the available data on produced water content were for shale
22 formations and CBM basins, while little data were available for sandstone formations. Additionally, the
23 majority of data were for inorganics, and little data were available for organics. Many more organic
24 chemicals have been reported to have been used in hydraulic fracturing fluid than have been identified in
25 produced water. The difference may be due to analytical limitations, limited study scopes, and
26 undocumented subsurface reactions.
27 • Hydraulic fracturing flowback and produced water composition is influenced by the composition of
28 injected hydraulic fracturing fluids, the targeted geological formation and associated hydrocarbon
29 products, the stratigraphic environment, and subsurface processes and residence time.
30 • Spatial variability of produced water content occurs between plays of different rock sources (e.g., coal vs.
31 sandstone), between plays of the same rock type (e.g., Barnett Shale vs. Bakken Shale), and within
32 formations of the same source rock (e.g., northeastern vs. southwestern Marcellus Shale).
3 3 What are the chemical and physical properties of hydraulic fracturing flowback and produced water
34 constituents?
35 • The identified constituents of flowback and produced water include inorganic chemicals (cations and
36 anions in the form of metals, metalloids, non-metals, and radioactive materials), organic chemicals and
37 compounds, and unidentified materials measured as TOG (total organic carbon) and DOC (dissolved
38 organic carbon). Some constituents are readily transported with water (i.e., chloride and bromide), while
39 others depend strongly on the geochemical conditions in the receiving water body (i.e., radium and
40 barium), and assessment of their transport is based on site-specific factors. Using the EPA chemical
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Hydraulic Fracturing Drinking Water Assessment Chapter 7 - Flowback and Produced Water
1 database EPI Suite, we were able to obtain actual or estimated physicochemical properties for 86 (64%)
2 of the 134 chemicals identified in produced water.
3 • As in the case of chemicals in hydraulic fracturing fluid, chemical properties that affect the likelihood of
4 an organic chemical in produced water reaching and impact drinking water resources in the short-term,
5 include: high chemical mobility in water, low volatility, and high persistence in water. In general, EPI
6 suite results suggest that organic chemicals in produced water tend toward lower mobility in water.
7 Consequently these chemicals could remain in soils or sediments nearby spills. Low mobility may result
8 in smaller dissolved contaminant plumes in ground water. Although these compounds are more likely to
9 be transported associated with sediments in surface water or small particles in ground water. Organic
10 chemical properties vary with salinity and the effects depend on the nature of the chemical.
11 If spills occur, how might hydraulic fracturing flowback and produced water contaminate drinking
12 water resources?
13 • Spills of flowback or produced water might impact drinking water resources if the spill or release is of
14 sufficient volume and duration, to reach the resource at a sufficient concentration. Impacts to in-use
15 drinking water depend on proximity to sources. Scientific literature and published reports have shown
16 that produced water spills have impacted drinking water resources.
7.9. References for Chapter 7
Ali. SA: Clark. Wl: Moore. WR: Dribus. IR. (2010). Diagenesis and reservoir quality. Oilfield Rev 22:14-27.
Alley, B: Beebe, A: Rodgers, I: Castle, IW. (2011). Chemical and physical characterization of produced waters
from conventional and unconventional fossil fuel resources. Chemosphere 85: 74-82.
http://dx.doi.0rg/10.1016/j.chemosphere.2011.05.043
API (American Petroleum Institute). (2005). Modeling study of produced water release scenarios.
(Publication Number 4734). Washington, D.C.: API Publishing Services.
http://www.api.Org/~/media/files/ehs/environmental performance/4734.pdf?la=en
API (American Petroleum Institute). (2010b). Water management associated with hydraulic fracturing.
Washington, D.C.: API Publishing Services.
http://www.api.Org/~/media/Files/Policy/Exploration/HF2 el.pdf
Arkadakskiy. S..: Rostron. Bl. (2012a). Stable isotope geochemistry helps in reducing out-of-zone hydraulic
fracturing and unwanted brine production from the Bakken Reservoir. Available online at
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Arkadakskiy. S: Rostron. B. (2013a). Tracking out-of-zone hydraulic fracturing in the Bakken with naturally
occuring tracers. Paper presented at GeoConvention 2013: Integration Canadian Society of Petroleum
Geologists, May 6-10, 2013, Calgary, AB, Canada.
Arthur. ID: Bohm. B: Coughlin. Bl: Layne. M. (2009b). Evaluating the environmental implications of hydraulic
fracturing in shale gas reservoirs. Paper presented at SPE Americas E&P Environmental and Safety
Conference, March 23-25,2009, San Antonio, TX.
ATS PR (Agency for Toxic Substances and Disease Registry). (2005). Public health assessment guidance
manual (Update). Atlanta, GA: U.S. Department of Health and Human Services, Public Health Service.
http://www.atsdr.cdc.gov/hac/PHAManual/toc.html
This document is a draft for review purposes only and does not constitute Agency policy.
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ATSDR [Agency for Toxic Substances and Disease Registry). (2013). Health consultation: Chesapeake ATGAS
2H well site, Leroy Hill Road, Leroy, Leroy Township, Bradford County, PA. Atlanta, GA: ATSDR, Division of
Cummunity Health Investigations.
http://www.atsdr.cdc.gov/HAC/pha/ChesapeakeATGASWellSite/ChesapeakeATGASWellSiteHC1028201
3 508.pdf
AWWA (American Water Works Association). (2013). Water and hydraulic fracturing: A white paper from the
American Water Works Association. Denver, CO.
http://www.awwa.Org/Portals/0/files/legreg/documents/AWWAFrackingReport.pdf
Barbot. E: Vidic. NS: Gregory. KB: Vidic. RD. (2013). Spatial and temporal correlation of water quality
parameters of produced waters from Devonian-age shale following hydraulic fracturing. Environ Sci
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This document is a draft for review purposes only and does not constitute Agency policy.
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Woodlands, TX.
This document is a draft for review purposes only and does not constitute Agency policy.
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
Chapter 8
Wastewater Treatment and Waste Disposal
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8. Wastewater Treatment and Waste Disposal
8.1. Introduction
1 Hydraulic fracturing used for the development of oil and gas resources results in the production of
2 wastewater containing a range of problematic or potentially problematic constituents (see Chapter
3 7) and requiring management For the purposes of this assessment, hydraulic fracturing
4 wastewater encompasses flowback and produced water (often referred to together as produced
5 water) that is managed using any of a number of practices, including treatment and discharge,
6 reuse, or injection into Class IID wells regulated under the Underground Injection Control (UIC)
7 program under the Safe Drinking Water Act (SDWA) (see also Chapter 1).: In this chapter, the term
8 "wastewater" is generally used. In limited cases where more specific information is provided about
9 a wastewater (e.g., a source indicates that the wastewater is flowback), that information is also
10 noted.
11 Although wells producing from either unconventional or conventional oil and gas reservoirs
12 generate produced water during the course of their productive lifespan, wells conducting modern
13 high-volume hydraulic fracturing can generate a large volume of flowback water in the period
14 immediately after fracturing. Stakeholders reported to the U.S. Government Accountability Office
15 that flowback volumes could be 420,000 gal to 2.52 Mgal (10,000 to 60,000 bblor 1.59 million to
16 9.54 million L) per well per hydraulic fracture (U.S. GAP. 20121 (see Chapter 7.1.1 for more
17 information on produced water volumes per well in various geologic basins and plays). This
18 necessitates having a wastewater management strategy in place at the beginning of activities at the
19 well. Selection of management choices may depend upon the quality and volume of the fluids,
20 logistics, and economics.
21 Treatment and disposal strategies vary throughout the United States and may include underground
22 injection, on-site or offsite treatment for reuse in subsequent hydraulic fracturing operations, reuse
23 without treatment, or other uses. In some areas, wastewater may be applied to the land (e.g., for
24 irrigation) or held in pits for evaporation. The large majority of wastewater generated from all oil
25 and gas operations in the United States is disposed of via Class IID wells (Clark and Veil. 2009). As
26 hydraulic fracturing activity matures, costs of different disposal practices may change in various
27 regions due to factors such as regulations, available infrastructure, feasibility and cost of reuse
28 practices, and other concerns that are difficult to anticipate and quantify at the time of this
29 assessment
30 Over the past decade, the rapid increase in modern hydraulic fracturing activities has led to the
31 need to manage the associated wastewater. There has been a shift towards reuse in areas where
1 The term "wastewater" is being used in this study as a general description of certain waters and is not intended to
constitute a term of art for legal or regulatory purposes. This general description does not, and is not intended to, provide
that the production, recovery, or recycling of oil, including the production, recovery, or recycling of produced water or
flowback water, constitutes "wastewater treatment" for the purposes of the Oil Pollution Prevention regulation (with the
exception of dry gas operations), which includes the Spill Prevention, Control, and Countermeasure rule and the Facility
Response Plan rule, 40 CFR 112 et seq.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 there are relatively few Class IID wells (e.g., the Marcellus Shale region) and indications of interest
2 in reuse in areas where access to water for fracturing is limited (e.g., Anadarko Basin in TX and OK).
3 The term reuse is sometimes used to imply no treatment or basic treatment (e.g., media filtration)
4 for the removal of constituents other than total dissolved solids (IDS), while recycling is sometimes
5 used to convey more extensive treatment (e.g., reverse osmosis (RO)) to remove IDS (Slutz etal.,
6 2012). In this document, the term "reuse" will be used to indicate use of wastewater for subsequent
7 hydraulic fracturing, without regard to the level of treatment
8 This chapter provides follow-on to Chapter 7, which discusses the composition and per-well
9 volumes of produced water and the processes involved in its generation. In this chapter,
10 discussions are included on management practices for hydraulic fracturing wastewaters, available
11 wastewater production information, and estimated aggregate volumes of wastewater generated for
12 several states with active hydraulic fracturing (Section 8.2). As a complement to information on the
13 composition of wastewaters in Chapter 7, issues of concern associated with wastewater
14 constituents are also presented (Section 8.3). Management methods that are used in 2014-2015 or
15 have been used in recent years are described (Section 8.4). Information is then presented on the
16 types and effectiveness of treatment processes that are suitable for removal of constituents of
17 concern in hydraulic fracturing wastewaters, either in centralized waste treatment facilities (CWTs)
18 or on-site treatment; examples of CWTs are presented (Section 8.5 and Appendix F). With the
19 background provided in the earlier sections of the chapter, documented and potential impacts on
20 drinking water resources are discussed (Section 8.6), and a final synthesis discussion is then
21 provided (Section 8.7).
22 This chapter makes use of background information collected by the EPA's Office of Water (OW) as
23 part of its development of proposed effluent limitations guidelines and standards for wastewater
24 from unconventional oil and gas resources (U.S. EPA. 2015q). These are defined by guidelines and
25 standards as resources in low permeability formations including oil and gas shales, tight oil, and
26 low permeability sandstones and carbonates. Coalbed methane is beyond the scope of those
27 standards. In this chapter we consider wastewater generated by hydraulic fracturing of those
28 unconventional oil and gas resources included in the background research done by OW in addition
29 to wastewater generated by hydraulic fracturing in coalbed methane plays and conventional
30 reservoirs.
8.2. Volumes of Hydraulic Fracturing Wastewater
31 This section of Chapter 8 provides a general overview of aggregate wastewater quantities
32 generated in the course of hydraulic fracturing and subsequent oil and gas production, including
33 estimates at regional and state levels. It also discusses methodologies used to produce these
34 estimates and the challenges associated with the preparation and use of available estimates.
35 (Chapter 7 provides a more in-depth discussion of the processes affecting produced water volumes
3 6 and presents some typical per-well values and temporal patterns.) Wastewater volumes most likely
3 7 will vary in the future as the amount and locations of hydraulic fracturing activities change and as
38 existing wells age and move into later phases of production. The volumes and management of
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1 wastewater are important factors affecting the potential for wastewater to affect drinking water
2 resources.
3 The volume of wastewater generated is generally tied to the volume of oil and gas production; as
4 operators increase hydrocarbon production, there will be a corresponding increase in wastewater
5 volumes to be managed. For example, data from the Pennsylvania Department of Environmental
6 Protection (PA DEP) [PA PEP, 2015a] (see Figure 8-1) show trends in volumes of wastewater
7 compared to gas produced from wells in the Marcellus Shale in Pennsylvania. Although the data
8 show some variation, they demonstrate a general correlation between wastewater and produced
9 gas.
18000000
115000000
12000000
I 9000000
eoooooo
3000000
2,500,000,000
2,000,000,000
1,500,000,000 —
1,000,000,000
500,000,000
'
' X'
'
Flowback_PW disposed of (bbl)
X
X'X'
'
Gas produced (mcf)
Figure 8-1. Produced and flowback water volumes and produced gas volumes from
unconventional wells in Pennsylvania from July of 2009 through June of 2014.
Source: PA DEP (2015a).
1 0 Information presented in Chapter 7 highlights the initial rapid recovery of fluid in the first weeks
11 after fracturing (see Figure 7-2), with a subsequent substantial reduction in the volume of water
1 2 flowing through the well to the surface. This is followed by recovery of produced water during the
13 longer-term productive phase of the well's life. One source suggests that, as a general rule of thumb,
14 the amount of flowback produced in the days or weeks after hydraulic fracturing is roughly
15 comparable to the amount of long-term produced water generated over a span of years, which may
16 vary considerably among wells (IHS, 2013). Thus, on a local level, operators can anticipate a
17 relatively large volume of wastewater in the weeks following fracturing, with slower subsequent
18 production of wastewater. Wells also generate some amount of drilling- fluid waste. Compared to
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 produced water, however, drilling waste water can constitute a relatively small portion of the total
2 wastewater produced (e.g., <10% in Pennsylvania during 2004-2013) [U.S. EPA. 2015q] and is not
3 discussed further in this assessment
4 In addition to variation in per-well wastewater volumes, aggregate wastewater production for an
5 area or region will vary from year to year with hydraulic fracturing activity. For instance, the
6 average annual volume of wastewater generated by all gas production (both shale gas and
7 conventional) in Pennsylvania quadrupled from the 2001-2006 period to the 2008-2011 period.
8 During the latter period, wastewater volume averaged 1.1 billion gal (26 million bbl or 4.2 billion L)
9 per year (Wilson and Vanbriesen. 2012).
8.2.1. National Level Estimate
10 Clark and Veil (2009) estimated that in 2007, the approximately one million active oil and gas wells
11 in the United States generated approximately 2.4 billion GPD (57.4 million bbl/day; 9.1 billion
12 L/day) of wastewater; no newer comprehensive national-level estimate exists in the literature as of
13 April 2015. Note that this estimate is not limited to wastewater from hydraulic fracturing
14 operations. This national-level estimate is reported to represent total oil and gas wastewater (from
15 conventional and unconventional resources, and from wells hydraulically fractured and wells not
16 hydraulically fractured), but the authors note that it does not include the flowback water
17 component Although Clark and Veil (2009) conducted a state-by-state analysis, the report may
18 have underestimated production due to significant data limitations: 1) data based on a timeframe
19 preceding the dramatic increase in hydraulic fracturing activity seen in more recent years; 2)
20 estimates based on data that were collected and maintained in a variety of ways, making data
21 synthesis difficult; and 3) incomplete data (U.S. GAP. 2012).
8.2.2. Regional/State and Formation Level Estimates
2 2 The amount of wastewater generated in a given region varies widely depending upon the volume of
23 wastewater generated per well and the number of wells in the area. The factors influencing
24 wastewater production are discussed in Chapter 7, which also discusses differences among
25 formations in volumes recovered during flowback and long-term water production. Table 7-2
26 provides rates of produced water generation for a number of formations in the United States.
27 At an aggregate level, wastewater volumes and geographic variability have been assessed for oil
28 and gas production in several studies. A 2011 study by the Bureau of Land Management (BLM)
29 (Guerraetal.. 2011) states that more than 80% of oil and gas wastewater is generated in the
30 western United States, including volumes from both conventional and unconventional resources.
31 The BLM report notes substantial contributions from coalbed methane (CBM) wells, in particular
32 those in the Powder River Basin (Wyoming). The authors state that Wyoming produces the second
33 highest volume of water among the western United States. Guerraetal. (2011) also highlight the
34 large portion of wells and wastewater associated with Texas (44% of U.S. produced water volume).
35 Although the authors do not identify all wastewater contributions from production involving
36 hydraulic fracturing, the regions with established oil and gas production are likely to have methods
37 and infrastructure available for management of hydraulic fracturing wastewater. Figure 8-2
38 summarizes the findings for these western states, demonstrating the wide variability in wastewater
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
1 from state to state (likely reflecting differences in formation geology and oil and gas production
2 activity).
32,515
2,080 19,792
2,040
18,021|
1,603 |
1,733 |
19,221
I California
I Colorado
I Kansas
I Montana
I New Mexico
I Oklahoma
lTexas
I Utah
I Wyoming
I Remaining W. States
Figure 8-2. Wastewater quantities in the western United States (billions of gallons per year).
Source: Guerra et al. (2011).
3 Table 8-1 presents estimates of the numbers of wells and volumes of hydraulic fracturing
4 wastewater generated in North Dakota, Ohio, Pennsylvania, Texas, and West Virginia. The data
5 shown in this table come from publicly available state websites and databases; data for West
6 Virginia reference a report by Hansenetal. [2013] that compiled available flowback data from West
7 Virginia. The reported volumes have been summed by year. These states are represented in Table
8 8-1 because the produced water volumes were readily identifiable as associated with hydraulic
9 fracturing activity. Differences in the years presented for the states are due to differences in data
10 availability from the state agency databases. However, the increases in the numbers of wells
11 producing wastewater and the volumes of wastewater produced are generally consistent with the
12 timing of the expansion of high-volume hydraulic fracturing and track with the increase in
13 horizontal wells seen in Figure 2-12.
14 Several states with mature oil and gas industries (California, Colorado, New Mexico Utah,
15 Wyoming) make produced water volumes publicly available by well as part of their oil and gas
16 production data, but they do not directly indicate which wells have been hydraulically fractured.
17 Some states (Colorado, Utah, and Wyoming) specify the producing formation along with volumes of
18 hydrocarbons and produced water. New Mexico provides data for separate basins as well as for the
19 entire state. Determining volumes of hydraulic fracturing wastewater for these states is challenging
20 because there is a possibility of either inadvertently including wastewater from wells not
21 hydraulically fractured or of missing volumes that should be included. Appendix Table F-l provides
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1 estimates of wastewater volumes in these states in regions where hydraulic fracturing activity is
2 taking place along with notes on data limitations.
3 The data in Table 8-1 and Appendix Table F-l illustrate the challenges both for compiling a national
4 estimate of hydraulic fracturing wastewater as well as comparing wastewater production among
5 states due to dissimilar data types, presentation, and availability.
This document is a draft for review purposes only and does not constitute Agency policy.
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Table 8-1. Estimated volumes (millions of gallons) of wastewater based on state data for selected years and numbers of wells
producing fluid.
State
North
Dakota
Ohio
Pennsylvania
Basin
Williston
Appalachian
Appalachian
Principal
Lithologies
Shale
Shale
Shale
Data Type
Produced water
Wells
Primarily
flowback water
Wells
Flowback water
Wells
Produced water
Wells
2000
2
161
-
-
-
-
-
-
2004
3
152
-
-
-
-
-
-
2008
130
844
-
-
-
-
-
-
2010
790
2,033
-
-
92
334
90
1,035
2011
1,900
3,303
3
9
340
1,564
400
1,826
2012
4,500
5,036
29
86
410
1,622
730
3,665
2013
8,500
6,913
110
400
350
1,465
930
4,761
2014
9,700
8,039
-
-
210
895
440
4,889
Comments
From North Dakota Oil and Gas
Commission website.3 Data
provided for six members of the
Bakken Shale. Produced water
includes flowback (reports are
submitted within 30 days of well
completion.)
Data from Ohio DNR Division of
Oil and Gas.b Utica data for 2011
and 2012. Utica and Marcellus
data for 2013. Brine is noted by
agency to be mostly flowback.
Waste data from PA DEP.C 2nd
half of 2010 and first half of
2014. Data described as
unconventional as determined
by formation. Separate codes are
provided by PA DEP for flowback
and produced water.
June 2015
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Hydraulic Fracturing Drinking Water Assessment
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State
Pennsylvania
cont.
Texas
West Virginia
Basin
Appalachian
cont.
Unspecified
(entire
state)
Appalachian
Principal
Lithologies
Shale,
cont.
Shale,
Sandstone
Shale
Data Type
Flowback and
produced
water
Wells
Flowback water
- injected
volumes
Flowback water
- Estimated
total disposed
2000
-
2004
-
2008
-
2010
180
1,232
120
2011
740
2,434
490
110
2012
1,100
4,039
2,200
59
2013
1,300
5,015
3,100
2014
650
5,150
2,000
Comments
Waste injection data from Texas
Railroad Commission.11 Monthly
totals are provided for entire
state. Oct - Dec for 2011, full
years for 2012 and 2013, and Jan
- Oct for 2014
Estimates from Hansen et al.
(2013).
a North Dakota Industrial Commission. Department of Mineral Resources. Bakken Horizontal Wells By Producing Zone:
https://www.dmr.nd.gov/oilgas/bakkenwells.asp.
b Ohio Department of Natural Resources, Division of Oil and Gas Resources. Oil and Gas Well Production. http://oilandgas.ohiodnr.gov/productiontfARCHl.
c Pennsylvania Department of Environmental Protection. PA DEP Oil and Gas Reporting Web site.
https://www.paoilandgasreporting.state.pa.us/publicreports/Modules/Welcome/Agreement.aspx
d Railroad Commission of Texas. Injection Volume Query.
http://webapps.rrc.state.tx.us/H10/searchVolume.do:isessionid=l3cgVHhK9nkwPrC7ZcWNMgyzF9LCYyRlNmvDy3F1005wqXfcGNGN!1841197795?fromMain=yes&
sessionld= 143075601021612. Texas state data provide an aggregate total amount of flowback fluid injected for the past few years. (Data on brine volumes injected do
not differentiate hydraulically fractured wells and are therefore not presented here.) These values are interpreted as estimates of generated flowback water as based
on reported quantities of "fracture water flow back" injected into Class IID wells.
June 2015
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.2.3. Estimation Methodologies and Challenges
1 Compiling and comparing data regarding wastewater production at the wide array of oil and gas
2 locations in the United States presents challenges, and various approaches are used to estimate
3 wastewater volumes, both at the state and national level. Data from state agency web sites and
4 databases can be a ready source of information, whether publicly available and downloadable or
5 provided directly by agencies upon request. However, due to sometimes significant differences in
6 the types of data collected, mechanisms, formats, and definitions used, data cannot always be
7 directly compared from state to state and can be difficult to aggregate at a national level. The
8 inconsistences encountered in data searches for this assessment agree with recent conclusions by
9 Malone etal. [2015], who noted inconsistences among 10 states with unconventional oil and gas
10 activity in the accessibility, usability, completeness, accuracy, and cost of various types of data (e.g.,
11 wells drilled, production, waste, Class IID wells).
12 One challenge associated with using state production data to estimate the volume of wastewater
13 nationally or regionally is the lack of consistency in data collection [U.S. GAP. 2012). Some states do
14 not include a listing of wastewater (usually listed as produced water volumes) in their publicly
15 available oil and gas production reports, while others do. State tracking of wastewater volumes may
16 or may not include information that helps in determining whether the producing well was
17 hydraulically fractured (e.g., an indicator of resource type or formation). It also might not be clear
18 whether volumes listed as produced water include the flowback component Some states (e.g.,
19 Colorado) include information on disposal and management methods along with production data,
20 and others do not
21 Given these limitations, some studies have generated estimates of wastewater volume using water-
22 to-gas and water-to-oil ratios along with the reports of hydrocarbon production (Murray, 2013).
23 The reliability of any wastewater estimates made using this method will need to be evaluated in
24 terms of the quality, timeframe, and spatial coverage of the available data, as well as the extent of
25 the area to which the estimates will be applied. Water-to-hydrocarbon ratios are empirical
26 estimates. Because these ratios show a wide variation among formations, reliable data are needed
27 to formulate a ratio in a particular region.
2 8 Another approach to estimating wastewater volumes would entail multiplying per-well estimates
29 of flowback and produced water production rates by the numbers of wells in a given area.
30 Challenges associated with this approach include obtaining accurate estimates of the number of
31 new and existing wells, along with accurate estimates of per-well water production both during the
3 2 flowback period and during the production phase of the wells' lifecycle. In particular, it can be
3 3 challenging to correctly match per-well wastewater production estimates, which will vary by
34 formation, with counts of wells, which may or may not be clearly labeled by or associated with
3 5 specific formations. Temporal variability in wastewater generation would also be difficult to
36 capture and would add to uncertainty. Such an approach, however, may be attempted for order of
37 magnitude estimates if the necessary data are available and reliable.
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8.3. Wastewater Characteristics
1 Along with wastewater volume, wastewater characteristics are important for understanding the
2 potential impacts of management and disposal of hydraulic fracturing wastewater on drinking
3 water resources. Chapter 7 provides in-depth detail on produced water chemistry. This section
4 provides brief highlights of the important features of wastewater composition as well as the
5 characteristics of the residuals produced during wastewater treatment
8.3.1. Wastewater
6 This section briefly discusses why the composition of hydraulic fracturing wastewaters needs to be
7 considered when planning for wastewater management, especially if treatment or reuse are
8 planned. Concerns associated with selected constituents are presented; treatment considerations
9 associated with various wastewater constituents are included in Section 8.5.
8.3.1.1. Total Dissolved Solids and Inorganics
10 Wastewaters are generally high in total dissolved solids (TDS), especially waters from shale and
11 tight sandstone formations, with values ranging from less than 1,000 mg/L to hundreds of
12 thousands of mg/L (see Section 7.6.4 and Table 7-4). The TDS in wastewaters from shale
13 formations is typically dominated by sodium and chloride and may also include elevated
14 concentrations of bromide, bicarbonate, sulfate, calcium, magnesium, barium, strontium, radium,
15 organics, and heavy metals [Chapman etal.. 2012: Rowan etal.. 2011: Blauchetal.. 2009: Orem et
16 al.. 2007: Sirivedhin and Dallbauman. 2004). Within each play, the minimum and maximum values
17 shown in Table 7-4 suggest spatial variation that may need to be accommodated when considering
18 management strategies such as reuse or treatment. In contrast to shales and sandstones, TDS
19 values for wastewater from CBM formations are generally lower, with concentrations ranging from
20 approximately 250 mg/L to 39,000 mg/L [Benko and Drewes. 2008: Van Voast. 2003] (see
21 Appendix Table E-3). This results in fewer treatment challenges and a wider array of management
22 options.
23 Although TDS has a secondary maximum contaminant level (MCL) (secondary MCLs are non-
24 mandatory water quality standards) of 500 mg/L for aesthetic purposes, it is not considered a
2 5 health-based contaminant and is therefore not regulated under the EPA's National Primary
26 Drinking Water Regulations, although other standards may apply. For example, a maximum
27 concentration of 500 mg/L has been used by the state of Pennsylvania for some industrial
28 wastewater discharges. Constituents commonly found in TDS from hydraulic fracturing
29 wastewaters may have potential impacts on health or create burdens on downstream drinking
3 0 water treatment plants if discharged at high concentrations to drinking water resources. Bromide,
31 for example, can contribute to the increased formation of disinfection by-products (DBFs) during
32 drinking water treatment (Hammer and VanBriesen. 2012): see Section 8.6.1.
33 Metals (e.g., barium, cadmium, chromium, lead, copper, manganese, nickel, thallium, and zinc)
34 present in TDS can be toxic to humans and aquatic life at certain concentrations. Health effects of
35 these metals can include kidney damage, liver damage, skin conditions, high blood pressure, and
36 developmental problems (U.S. EPA, 2015i). To ensure safe drinking water, the EPA has established
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 primary MCLs for a number of these constituents. MCLs and action levels for these metals vary from
2 0.002 mg/L for thallium to 1.3 mg/L for copper [U.S. EPA. 20151). Cadmium has been found in
3 produced water from tight gas formations at concentrations as high as 0.37 mg/L (the MCL is 0.005
4 mg/L), and chromium has been found at concentrations up to 0.265 mg/L (the MCL is 0.1 mg/L)
5 (see Table 7-4).
6 Other constituents of concern among dissolved solids are chloride, sulfate, barium, and boron.
7 Elevated concentrations of chloride and sulfate are of concern because of drinking water aesthetics,
8 and the EPA has established secondary MCLs for both chloride and sulfate of 250 mg/L (U.S. EPA,
9 20151: Hammer and VanBriesen. 2012). Barium has a primary MCL of 2 mg/L and has been found in
10 some shale gas produced waters at concentrations in the thousands of mg/L (see Table 7-4). Boron
11 is not regulated under the National Primary Drinking Water Regulations, but internal plant
12 specifications for one CWT (e.g., the Pinedale Anticline Facility) and waste discharge requirements
13 (WDR) permit for another (e.g., San Ardo Water Reclamation Facility) limit boron effluent
14 concentrations to 0.75 mg/L (Shafer. 2011: Webb etal.. 20091.
8.3.1.2. Organics
15 Less information is available about organic constituents in hydraulic fracturing waste waters than
16 about inorganic constituents, but there are several studies that include some analyses of organic
17 constituents. The organic content in flowback waters can vary based on the chemical additives used
18 and the formation but generally consists of polymers, oil and grease, volatile organic compounds
19 (VOCs), and semi-volatile organic compounds (SVOCs) fWalsh. 2013: Hayes. 20091. Examples of
20 other constituents detected include alcohols, naphthalene, acetone, and carbon disulfide (U.S. EPA.
21 20151) (see Appendix Table E-10). Wastewater associated with CBM wells may have high
22 concentrations of aromatic and halogenated organic contaminants that that may require treatment
23 depending on how the waste water will be managed or disposed of (Pashinetal., 2014: Sirivedhin
24 and Dallbauman. 2004). Concentrations of BTEX (benzene, toluene, ethylbenzene, and xylenes), in
25 CBM produced waters are, however, lower than in shale produced waters (see Appendix Table E-9).
2 6 Certain organic compounds are of concern in drinking water because they can cause damage to the
2 7 nervous system, kidneys, and/or liver and can increase the risk of cancer if ingested over a period
28 of time (U.S. EPA, 2006). Some organics in chemical additives are known carcinogens, including 2-
29 butoxyethanol (2BE), naphthalene, benzene, and polyacrylamide (Hammer and VanBriesen, 2012).
30 Many organics are regulated for drinking water under the National Primary Drinking Water
31 Regulations. Section 8.6.4 provides further discussion of documented or potential situations in
32 which organic constituents have or might reach drinking water resources.
8.3.1.3. Radionudides
3 3 Radionudides are constituents of concern in some hydraulic fracturing waste waters, with most
34 available data obtained for the Marcellus Shale in Pennsylvania (see Appendix Table E-8). Results
35 from a USGS report (Rowan etal., 2011) indicate that radium-226 and radium-228 are the
36 predominant radionuclides in Marcellus Shale wastewater, and they account for most of the gross
37 alpha and gross beta activity in the waters studied. There are limited data on radionuclides in
38 wastewater from formations other than the Marcellus Shale, but information on the naturally
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 occurring radioactive material (NORM) in the formations themselves, in particular uranium and
2 thorium, may suggest the potential for high levels of radionuclides in produced water, especially
3 where IDS concentrations are also high. Sections 7.5.4 and 7.6.6 provide further information on
4 radionuclides in formations and in produced waters.
5 The primary radioactive contaminants found in hydraulic fracturing wastewaters (radium, gross
6 alpha radiation, and gross beta radiation) can increase the risk of cancer if consumed at elevated
7 levels over time (U.S. EPA. 2015i). Therefore, the EPA has established drinking water MCLs for
8 combined radium (radium-226 plus radium-228), gross alpha, and gross beta of 5 pCi/L, 15 pCi/L,
9 and 4 millirems/year, respectively (see Section 8.6.2).
8.3.2. Constituents in Residuals
10 Depending on the water being treated and treatment processes used, treatment residuals may
11 consist of sludges, spent media (used filter materials), or brines. Residuals can include constituents
12 such as total suspended solids (TSS), TDS, metals, radionuclides, and organics. The treatment
13 process tends to concentrate wastewater constituents in the residuals. As an illustration of the
14 degree of concentration that can take place, processes such as electrodialysis and mechanical vapor
15 recompression have been found to yield residuals streams with TDS concentrations in excess of
16 150,000 mg/L, from treating waters with influent TDS concentrations of approximately 50,000 -
17 70,000 mg/L (Hayes etal.. 2014: Peraki and Ghazanfari. 2014).
18 Also, technologically enhanced naturally occurring radioactive material (TENORM) in wastewaters
19 may cause residual wastes to have elevated gamma radiation emissions (Kappel etal.. 2013). * One
20 study calculated that typical solids produced by precipitation processes designed to remove barium
21 and strontium from Marcellus Shale wastewater would contain between 2,571 and 18,087 pCi/g of
22 radium in the barium sulfate precipitate (Zhang et al., 2014b). Another similar study using mass
23 balances calculated that sludge from a sulfate precipitation process would average a radium
24 concentration of 213 pCi/g in sludge (Silvaetal.. 2012). Silvaetal. (2012) estimated a radium-226
25 concentration of 58 pCi/g in sludge from lime softening processes, a level that would necessitate
26 disposal of low level radioactive waste.
8.4. Wastewater Management Practices
27 Operators have several strategies for management of hydraulic fracturing wastewaters (see Figure
28 8-3), with the most common choice being disposal via Class IID wells (Clark etal.. 2013: Hammer
29 and VanBriesen. 2012). Other practices include reuse in subsequent hydraulic fracturing operations
30 (with varying levels of treatment), treatment at a CWT (often followed by reuse), evaporation (in
31 arid regions), or in some cases, depending on state and local requirements, various other
32 wastewater management strategies (e.g., irrigation, which involves no discharge to waters of the
33 U.S.). The management methods shown in Figure 8-3 represent various strategies, not all of which
34 will happen together.
1 Technologically enhanced naturally occurring radioactive materials (TENORM) are radionuclides that have been
concentrated or enhanced as the result of human activity.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 At one time, treatment of unconventional oil and gas waste waters at publicly owned treatment
2 works (POTWs) was a common practice for wastewater management in the Marcellus region [Lutz
3 etal.. 2013). However, this practice has been essentially discontinued following a request from PA
4 DEP that, by May 19, 2011, oil and gas operators stop sending Marcellus Shale wastewater to 15
5 POTWs and CWTs that discharged to surface waters [U.S. EPA. 2015h1.
6 Each of these wastewater management strategies may potentially lead to an impact on drinking
7 water resources during some phase of their execution. Such impacts may include accidental
8 releases during transport (see Chapter 7), discharges of treated wastewaters from CWTs or POTWs
9 where treatment for certain constituents has been inadequate, migration of constituents in
10 wastewaters that have been applied to land, leakage from on-site storage pits (see Chapter 7),
11 inappropriate management of residuals (e.g., leaching from landfills or land application), or
12 accumulation of constituents in sediments near outfalls of CWTs or POTWs that have treated
13 hydraulic fracturing wastewater.
14 A reliable census of nationwide wastewater management practices is difficult to assemble due to a
15 lack of consistent and comparable data among states, but Table 8-2 illustrates the variability in the
16 primary wastewater management methods using available qualitative and quantitative sources.
17 Disposal via underground injection predominates in most regions. Reuse is most prevalent in the
18 Appalachian Basin in Pennsylvania. Moderate reuse occurs in the Arkoma (OK, AR) and Anadarko
19 (OK, TX) basins, and use of CWTs occurs predominantly in Pennsylvania.
Road spreading,
other uses
Surface
water
discharge
Landfill
(residuals)
Figure 8-3. Schematic of wastewater management strategies.
This document is a draft for review purposes only and does not constitute Agency policy.
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Table 8-2. Hydraulic fracturing wastewater management practices in recent years.
Source: (U.S. EPA, 2015q).
Basin
Michigan
Appalachian
Anadarko
Arkoma
Fort Worth
Permian
TX-LA-MS Salt
Formation
Antrim
Marcellus/Utica (PA)
Marcellus/Utica (WV)
Marcellus/Utica (OH)
Granite Wash
Mississippi Lime
Woodford; Cana;
Caney
Fayetteville
Barnett
Avalon/Bone Springs,
Wolfcamp, Spraberry
Haynesville
Resource type
Shale Gas
Shale Gas
Shale Gas/Oil
Shale Gas/Oil
Tight Gas
Tight Oil
Shale Gas/Oil
Shale Gas
Shale Gas
Shale/tight Oil/gas
Tight Gas
Reuse
XXX
XXX
XX
XX
X
X
XX
X
X
X
Injection
for disposal
XXX
XX
XX
XXX
XXX
XXX
XXX
XX
XXX
XXX
XXX
CWT
facilities
XX
X
X
xa
xa
xa
xa
xa
Notes
Limited Class IID wells in east
Reuse limited but is being evaluated
Few existing Class IID wells; new CWT
facilities are under construction
Reuse not typically effective due to
high TDS early in flowback and
abundance of Class IID wells
Reuse not typically cost effective due
to high TDS early in flowback and
abundance of Class IID wells
Available datab
Qualitative
Quantitative
Quantitative
Mixed
Mixed
Qualitative
Qualitative
Mixed
Mixed
Mixed
Mixed
June 2015
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Basin
West Gulf
Denver
Julesburg
Piceance;
Green River
Williston
Formation
Eagle Ford, Pearsall
Niobrara
Mesaverde/Lance
Bakken
Resource type
Shale Gas/Oil
Shale Gas/Oil
Tight Gas
Shale Oil
Reuse
X
X
X
X
Injection
for disposal
XXX
XXX
XX
XXX
CWT
facilities
X
X
X
Notes
Also managed through evaporation to
atmosphere in ponds in this region
Reuse limited but is being evaluated
Available datab
Mixed
Mixed
Qualitative
Mixed
a CWT facilities in these formations are operator owned.
b This column indicates the type of data on which EPA based the number of X's. In most cases, EPA used a mixture of qualitative and quantitative data sources along with
engineering judgment to determine the number of X's.
XXX—The majority (> 50%) of wastewater is managed with this management practice.
XX—A moderate portion (> 10% and < 50%) of wastewater is managed with this management practice.
X—This management practice has been documented in this location but for a small (< 10%) or unknown percent of wastewater.
June 2015
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1 Management choices are affected by cost and a number of other factors, including the chemical
2 properties of the wastewater; the volume, duration, and flow rate of the water generated; the
3 logistical feasibility of various options; the availability of necessary infrastructure; federal, state,
4 and local regulations; and operator discretion [U.S. GAP, 2012: NPC, 2011a]. The economics (such
5 as transport, storage, and disposal costs) and availability of various treatment and disposal
6 methods are of primary importance [U.S. GAP, 2012]. For example, as of early 2015, Pennsylvania
7 has nine operating Class IID wells within the state, whereas Texas has nearly 7,900 [U.S. EPA,
8 2015qj.
9 The availability and use of management strategies may change in a region over time as oil and gas
10 development increases or decreases, changing the volumes of wastewater that need to be handled
11 on a local, state, and regional level (see Text Box 8-1 for more information on hydraulic fracturing
12 wastewater management in Pennsylvania). Figure 8-4 illustrates shifting wastewater management
13 practices in Pennsylvania over the last several years as shale gas development has proceeded in the
14 Marcellus Shale. On-site reuse (labeled as "Reuse HF" in Figure 8-4) has grown. Also, most CWT
15 managementof Marcellus wastewater in recent years has been at zero-discharge facilities (i.e., for
16 reuse) (an estimated 80% in 2012 and 90% in 2013) (PADEP. 2015a). Combined with the volumes
17 managed via on-site reuse, Pennsylvania reuse rates are approximately 85% to 80%. In contrast,
18 wastewater disposal data for Colorado (see Figure 8-5) show a steady use of injection wells
19 (injected on lease) since 2000, and an apparent decrease in the use of onsite pits (state data were
20 filtered for formations indicated in the literature to be targets for hydraulic fracturing).
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
Text Box 8-1. Temporal Trends in Wastewater Management - Experience of Pennsylvania.
1 Gross natural gas withdrawals from shale formations in the United States increased 518% between 2007 and
2 2012 [EIA. 2014c). This production increase has led to larger volumes of wastewater that require appropriate
3 management [Vidic etal.. 2013: Gregory et al.. 2011: Kargbo etal.. 2010]. The rapid increase in wastewater
4 generated from oil and gas wells used for hydraulic fracturing has led to many changes in the wastewater
5 disposal practices in the oil and gas industry. Changes have been most evident in Pennsylvania, which has
6 experienced more than a 1,400% increase in natural gas production since 2000 [EIA. 2014c).
7 Lutz etal. [20131 estimated that total wastewater generation in the Marcellus region increased 570%
8 between 2004 and 2013 and concluded that this increase has created stress on the existing wastewater
9 disposal infrastructure. In 2010, in response to concerns over elevated TDS in the Monongahela River basin
10 and studies linking high TDS (and in particular high bromide levels) to elevated DBF levels in drinking water
11 systems [PA DEP. 2011a). PA DEP amended Chapter 95 Wastewater Treatment Requirements under the
12 Clean Streams Law for new discharges of TDS in wastewaters. This regulation is also known informally as the
13 2010 TDS regulation. The regulation disallowed any new indirect discharges (i.e., discharges to POTWs) of
14 hydraulic fracturing waste and set limits of treated discharges fromCWTs of 500 mg/LTDS, 250mg/L
15 chloride, 10 mg/L barium, and 10 mg/L strontium. Existing discharges were exempt.
16 In April 2011, PA DEP requested that oil and gas well operators transporting unconventional wastewater to
17 the eight CWTs and seven POTWs that were exempt from the 2010 TDS regulation voluntarily stop
18 discharging to these facilities. Follow-up letters from PA DEP to the owners of the wells specified that the role
19 of bromides from Marcellus Shale wastewaters in the formation of total trihalomethanes (TTHM) was of
20 concern [PA DEP. 2011a).
21 Between early 2011 and late 2011, although reported wastewater flows more than doubled, Marcellus
22 drilling companies in Pennsylvania reduced their wastewater flows to CWTs that were exempt from the 2010
23 TDS regulation by 98%, and discharge to POTWs was Virtually eliminated' [Hammer and VanBriesen. 20121.
24 Along with the decreased discharges from POTWs, there has been increased reuse of wastewater in the
25 Marcellus Shale region. From 2008-2011, reuse of Marcellus wastewater has increased, POTW treatment
26 volumes have decreased, tracking of wastewater has improved, and wastewater transportation distances
27 have decreased [Rahmetal.. 2013]. Maloney and Yoxtheimer [2012] analyzed data from 2011 and found that
28 reuse of flowback water increased to 90% by volume. Disposed flowback water comprised 8% of the total
29 volume. Brine water, which was defined as formation water, was reused (58%), disposed via injection well
30 (27%), or sent to industrial waste treatment plants (14%). Of all the fluid wastes in the analysis, brine water
31 was most likely to be transported to other states (28%). They also concluded that wastewater disposal to
32 municipal sewage treatment plants declined nearly 100% from the first half of 2011 to the second half.
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Chapter 8 - Wastewater Treatment and Waste Disposal
2009 - 2010
0.5%
uic
• CWT
• POTW
Reuse Non-HF
• Reuse HF
• Road Spreading
Other
« Uncertain
4%
2013
0.0003% 0-5%
uic
I CWT
Reuse Non-HF
lReuse HF
I Road Spreading
Other
Figure 8-4. Percentages of Marcellus Shale wastewater managed via various practices for
(top) the second half of 2009 and first half of 2010 (total estimated volume of 216
Mgal), and (bottom) 2013 (total estimated volume of 1.3 billion gallons).
"Reuse HF" indicates on-site reuse. Source: Waste data from PA PEP (2015a).
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70%
60%
50%
40%
30%
20%
10%
0%
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Central disposal pit or well —Commercial disposal facility - Injected on lease
•Onsite pit —Surface discharge
Figure 8-5. Management of wastewater in Colorado in regions where hydraulic fracturing is
being performed.
Source: Production data from COGCC f20151.
1 Regulations also affect management options and vary geographically. At the Federal level, existing
2 oil and gas effluent limitations guidelines and standards (ELGs) can be found under 40 CFR Part
3 435. These ELGs apply to conventional and unconventional oil and gas extraction facilities in
4 various subcategories (e.g., Offshore, Onshore, Stripper Wells), with the exception of CBM
5 discharges, which are not subject to the existing regulations. Subpart C, the Onshore subcategory,
6 prohibits the discharge of wastewater pollutants to waters of the U.S. from onshore oil and gas
7 extraction facilities. This "zero-discharge standard" means that oil and gas produced water
8 pollutants cannot be directly discharged to surface waters. Operators have met these regulations
9 through underground injection, reuse, or transfer of produced water to POTWs and/or CWTs. West
10 of the 98th meridian (the arid western portion of the continental United States), discharges of
11 wastewater from onshore oil and gas extraction facilities may be permitted for direct discharge to
12 waters of the U.S. if the produced water has a use in agriculture or wildlife propagation when
13 discharged into navigable waters. Definitions in 40 CFR 435.51(c) explain that the term "use in
14 agricultural or wildlife propagation" means that (1) the produced water is of good enough quality
15 to be used for wildlife or livestock watering or other agricultural uses; and (2) the produced water
16 is actually put to such use during periods of discharge. The regulations at 40 CFR 435.52 specify
17 that the only allowable discharge is produced water, with an oil and grease concentration not
18 exceeding 35 milligrams per liter (mg/L). The regulations prohibit the discharge of waste
19 pollutants into navigable waters from any source (other than produced water) associated with
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 production, field exploration, drilling, well completion, or well treatment (i.e., drilling muds, drill
2 cuttings, produced sands).
3 Unpermitted discharges of wastes related to hydraulic fracturing have been described in a number
4 of instances. In Pennsylvania, discharges of brine into a storm drain that discharges to a tributary of
5 the Mahoning River in Ohio. Analyses of the brine and drill cuttings that were discharged indicated
6 the presence of contaminants, including benzene and toluene [U.S. Department of Justice, 2014]. In
7 California, an oil production company periodically discharged hydraulic fracturing wastewaters to
8 an unlined sump for 12 days. It was concluded by the prosecution that the discharge posed a threat
9 to groundwater quality [Bacher, 2013]. These unauthorized discharges represent both documented
10 and potential impacts on drinking water resources. However, data do not exist to evaluate whether
11 such episodes are uncommon or whether they happen on a more frequent basis and remain largely
12 undetected.
13 The following section provides an overview of hydraulic fracturing wastewater management
14 methods, with some discussion of the geographic and temporal variations in practices. Discussion is
15 provided on common treatment and disposal methods including on-site storage, underground
16 injection, CWTs, reuse of hydraulic fracturing fluids, and evaporation methods. This section also
17 provides discussion on past treatment of hydraulic fracturing wastewater at POTWs. Other
18 management practices are also covered. Brief descriptions of treatment technologies applicable to
19 hydraulic fracturing wastewater are available in Appendix F.
8.4.1. Underground Injection
20 Oil and gas wastewater may be disposed of via Class II injection wells regulated under the
21 Underground Injection Control (UIC] Program under the Safe Drinking Water Act (SDWA]1. Class II
22 wells include those used for enhanced oil recovery (IIR], disposal (IID], and hydrocarbon storage
23 (HH). Nationwide, injection wells dispose of a large fraction of wastewater from the oil and gas
24 industry, including wastewater associated with hydraulic fracturing. A 2009 study notes that the oil
25 and gas industry in the United States generated about 882 billion gal (21 billion bbl or 3.34 trillion
26 L] of produced water in 2007 (Clark and Veil. 2009]. More than 98% of this volume was managed
27 via some form of underground injection, with 40% injected into Class II wells. However, a good
28 national estimate of the amount of hydraulic fracturing wastewater injected into Class II wells is
29 difficult to develop due to lack of available on data injection volumes specific to hydraulic fracturing
30 operations that are compiled and able to be compared among states. Also, wastewater management
31 methods are not well tracked in all states. Regional numbers of Class IID wells and generally low
32 reuse rates (see Section 8.4.3], however, are consistent with Class IID wells being a primary means
33 of wastewater management in many areas with hydraulic fracturing activity.
34 This assessment does not address whether there are documented or potential impacts on drinking
3 5 water resources associated with the injection of hydraulic fracturing wastewaters into Class IID
3 6 wells. However, should the feasibility of managing hydraulic fracturing wastewater via
1 States may be given federal approval to run a UIC program under Section 1422 or 1425 of SDWA.
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1 underground injection be limited in any way or become less economically advantageous, operators
2 will likely adjust their wastewater management programs to favor other local practices such as
3 treatment and discharge or reuse. Any new wastewater management decisions would then have to
4 be evaluated in terms of potential impacts on drinking water resources.
5 The decision to inject hydraulic fracturing wastewater into Class IID wells depends, in part, on cost
6 and on the proximity of the production well to the disposal well (and, therefore, transportation
7 costs). For oil and gas producers, underground injection is usually the least expensive management
8 strategy unless significant trucking is needed to transport the wastewater to a disposal well [U.S.
9 GAP. 20121.
10 Class IID wells are not distributed uniformly among states due to differences in geology (including
11 depth and permeability of formations), permitting, and historical demand for disposal of oil and gas
12 wastewater. Table 8-3 shows the numbers of active Class IID wells across the United States, with
13 the total count at a little over 27,000. The greatest numbers of wells are found in Texas, Oklahoma,
14 and Kansas. For example, Texas has nearly 7,900 Class IID wells, with an estimated daily disposal
15 volume of approximately 400 million gal per day (MGD) (1.5 billion L/day) (see Table 8-3). This
16 large disposal capacity in Texas is consistent with the availability of formations with suitable
17 geology and the demand for wastewater disposal associated with a mature and active oil and gas
18 industry. In contrast, Class IID wells are a relatively small portion of Marcellus wastewater
19 managementin Pennsylvania (about 10% in 2013 and the firsthalf of 2014) fPADEP. 2015al
20 because the state has nine injection wells as of early 2015. Wastewater is generally transported out
21 of state when being managed through injection into Class IID wells. The local availability of Class
22 IID wells and the capacity to accept large volumes of wastewater may begin to be affected by recent
23 state actions concerning seismic activity associated with injection (U.S. EPA, 2014F).
Table 8-3. Distribution of active Class IID wells across the United States.
Source: U.S. EPA(2015q).
State
Nearby basins with
hydraulic fracturing
Number of active
Class IID wells
(2012-2014)
Average disposal
rate per well
(GPD/well)a
Total state
disposal rate
(MGD)
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State
AK
OH
WV
PA
NY
VA
TN
MD
NC
KS
OK
AR
MO
CO
WY
UT
NE
TX
NM
IN
IL
KY
Ml
CA
Nearby basins with
hydraulic fracturing
North Slope
Appalachian
Multiple basins
Cherokee, Anadarko, Arkoma
Denver-Julesburg, Green
River, Piceance, Uinta
Fort Worth, Western Gulf,
Permian, San Juan, Raton
Illinois
Michigan
San Joaquin
Number of active
Class MD wells
(2012-2014)
45
188
66
9
10b
12
0
0
0
5,516
4,622°
611d
11
294
330
109
113
7,876
736
183
1,054
58
779°
826
Average disposal
rate per well
(GPD/well)a
182,000
8,900
7,180
6,380
3,530
17,500
0
0
0
20,900
35,900
30,900
1,270
50,200
e
74,400
18,100
54,200
48,600
3,580
e
1,750
16,600
77,800
Total state
disposal rate
(MGD)
8.2
1.7
0.47
0.057
0.035
0.21
0
0
0
120
170
19
0.014
15
e
8.1
2.0
430
36
0.66
e
0.10
13
64
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
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State
LA
MS
AL
ND
MT
SD
Nearby basins with
hydraulic fracturing
TX-LA-MS Salt
Williston
All other states (NV, FL, OR, IA, and WA)f
Total (not including missing states)
Number of active
Class IID wells
(2012-2014)
2,448
499
85
395
199
21
42
27,137
Average disposal
rate per well
(GPD/well)a
42,100
69,500
44,200
31,600
31,100
10,200
89,400
40,400
Total state
disposal rate
(MGD)
100
35
3.8
12
6.2
0.21
3.8
1,040
a Typical injection volumes per well are based on historical annual volumes for injection for disposal divided by the number of
active Class IID wells during the same year (primarily data from 2007 to 2013).
bThese wells are not currently permitted to accept unconventional oil and gas extraction wastewater.
c With the exception of Oklahoma and Michigan, wells on tribal lands have not been intentionally included. Wells on tribal
lands may be counted if state databases contained them.
d Only 24 of the 611 active Class II wells in Arkansas are in the northern half of the state, close to the Fayetteville formation.
e Disposal rates and/or number of Class IID wells is unknown.
These are states that have minimal oil and gas activity. The number of wells shown for these states may include all types of
Class II wells (e.g., Class II enhanced recovery wells) and therefore is an upper estimate. All other states not listed in this table
have minimal oil and gas activity and no active Class IID wells.
8.4.2. Centralized Waste Treatment Facilities
1 A CWT facility is generally defined as a facility that accepts industrial materials (hazardous, non-
2 hazardous, solid, or liquid) generated at another facility (off-site) for treatment and/or recovery
3 (EPA. 2000). (A POTW treats local municipal wastewater.) As a group, CWTs that accept oil and gas
4 wastewater offer a wide variety of treatment capabilities and configurations. The fate of treated
5 effluent at CWTs also varies, and can include the following: reuse in fracturing operations, direct
6 discharge (to a receiving water under a National Pollution Discharge Elimination System (NPDES)
7 permit), indirect discharge (to a POTW), or a combination of these. Zero discharge facilities do not
8 discharge to either surface water or a POTW; effluent is generally used for reuse, although
9 evaporation or land application may also be done. Some CWTs may be configured so that they only
10 partially treat the waste stream if allowed by the end use (a reuse application that does not require
11 TDS removal). Potential impacts on drinking water resources associated with treatment in CWTs
12 will depend upon whether the CWT treats adequately for constituents of concern prior to discharge
13 to surface water or to a POTW, and whether treatment residuals are managed appropriately.
14 Clean Water Act (CWA) regulations only apply to facilities that discharge treated wastewater to
15 surface waters or POTWs. For zero-discharge facilities, Pennsylvania and Texas have adopted
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 regulations to control permitting. PA DEP issues permits (General Permit WMGR123) thatallow
2 zero-discharge CWTs to treat and release water back to oil and gas industries for reuse (see the
3 Eureka Resources Facility in Williamsport, PA listed in Table 8-7 as an example of a zero-discharge
4 facility1). The Texas Railroad Commission (TXRRC) regulates and categorizes wastewater recycling
5 facilities into different categories: off-lease commercial recycling facilities (capable of being moved
6 from one location to another) and stationary commercial recycling facilities. The Texas regulations
7 also promote oil and gas wastewater treatment for reuse and water sharing (see
8 http://www.rrc.state.tx.us/rules/rule.php).
9 Wastewater from hydraulically fractured wells can be transported by truck or pipeline to and from
10 a CWT (Easton. 2014): this may present a vulnerability for spills or leaks (see Chapter 7). The
11 treated wastewater from CWTs may be integrated with other sources of water (for example, treated
12 municipal wastewater, storm water drainage, or other treated industrial waste streams) for reuse
13 applications (Easton, 2014).
8.4.2.1. Numbers and Locations of CWTs
14 Although there are CWTs serving hydraulic fracturing operations throughout the country, including
15 the Barnett and Fayetteville shale plays plus oil fields in Texas and Wyoming, historically the
16 majority have served Marcellus Shale operations. This is likely because the low availability of
17 injection wells (Boschee. 2014) in Pennsylvania necessitates other forms of management. An EPA
18 study (U.S. EPA. 2015q) identified 73 CWT facilities that have either accepted or plan to accept
19 hydraulic fracturing wastewater (see Table 8-4). Of these, 39 are located in Pennsylvania. Most of
20 these are zero-discharge facilities; they do not discharge to surface waters or POTWs, and they
21 often do not include TDS removal. According to EPA research (U.S. EPA. 2015q). the number of CWT
22 facilities serving operators in the Marcellus and Utica Shales has increased since the mid-2000s as
23 the number of wells drilled in the Marcellus and Utica Shales has increased, growing from roughly
24 five CWTs in 2004 to over 40 in 2013. A similar trend has been noted for the Fayetteville Shale
25 region in Arkansas, where there are fewer Class IID wells available relative to the rest of the state
26 (U.S. EPA. 2015q).
27 In other regions, a small number of newer facilities have emerged in the last several years, most
28 often with TDS removal capabilities. In Texas, for example, two zero-discharge facilities are
29 available to treat wastewater from the Eagle Ford (beginning in 2011 and 2013), both equipped
30 with TDS removal, and one zero-discharge facility with TDS removal is located in the Barnett Shale
31 region (operational beginning in 2008). In Wyoming, the four facilities in the region of the
32 Mesaverde/Lance formations (operations beginning between 2006 and 2012; two zero-discharge
33 and two with multiple discharge options) are all capable of TDS removal (U.S. EPA. 2015q).
1 The facility is also permitted for indirect discharge to the Williamsport Sewer Authority.
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Table 8-4. Number, by state, of CWT facilities that have accepted or plan to accept
wastewater from hydraulic fracturing activities.
Source: U.S. EPA(2015q).
State
AR
CO
ND
OH
OK
PA
TX
WV
WY
Formation(s)
served where
hydraulic
fracturing
occurs
Fayetteville
Niobrara,
Piceance Basin
Bakken
Utica, Marcellus
Woodford
Utica, Marcellus
Eagle Ford,
Barnett, Granite
Wash
Marcellus, Utica
Mesaverde,
Lance
Total
Zero-discharge
CWT facilities3
Non-TDS
removal
treatment
2
3(1)
0
10(7)
2
23
1
4(2)
0
45
TDS
removal
treatment
0
0
1(1)
0
0
7(3)
3
0
2
13
CWT facilities that
discharge to surface
water or POTWa
Non-TDS
removal
treatment
0
0
0
1
0
6
0
0
0
7
TDS
removal
treatment
0
0
0
0
0
0
0
0
0
0
Discharging CWT
facilities with multiple
discharge options3
Non-TDS
removal
treatment
0
0
0
0
0
0
0
1
0
1
TDS
removal
treatment
1
0
0
0
0
3(1)
0
1
2
7
Total
known
facilities
3
3
1
11
2
39
4
6
4
73
a Number of facilities also includes facilities that have not yet opened but are under construction, pending permit approval, or
in the planning stages. Facilities that are not accepting process wastewater from hydraulic fracturing activities but plan to in
the future are noted parenthetically.
1 Because few states maintain a comprehensive list of CWT facilities and the count provided by the
2 EPA [U.S. EPA. 2015q] includes facilities that plan to accept unconventional oil and gas
3 wastewaters, the data in Table 8-4 do not precisely reflect the number of facilities currently
4 available for handling hydraulic fracturing wastewaters. Additional discussion of CWTs in
5 unconventional oil and gas fields are reviewed in the literature for areas including the Barnett
6 [Hayes and Severin. 2012b] and the Fayetteville [Veil. 2011] as well as other oil fields in Texas and
7 Wyoming [Boschee, 2014, 2012]. In addition, news releases and company announcements indicate
8 that new wastewater treatment facilities are being planned [Greenhunter, 2014: Geiver, 2013:
9 Purestream. 2013: Alanco. 2012: Sionix. 2011].
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 Based on oil and gas waste disposal information available from PA DEP [PA PEP, 2015a] dating
2 back to 2009, the estimated volumes of Marcellus wastewater sent to CWTs range from
3 approximately 113 Mgal (428 million L) in the latter half of 2009 and first half of 2010, to about
4 183 Mgal (693 million L) in 2011, and about 252 Mgal (954 million L) in 2013. These constitute
5 about 52% of the total wastewater volume in 2009-2010, about 25% in 2011, and 20% in 2013,
6 indicating that although total amounts of wastewater have increased (see Table 8-1), the
7 percentage managed through CWTs has decreased.
8 Among the Marcellus wastewater sent to CWTs, an estimated 35% was sent to zero-discharge
9 facilities in Pennsylvania (those with general permits) in the latter half of 2010, and 42% was sent
10 to facilities with NPDES permits (indicating that they can discharge to surface waters). About 23%
11 went to CWTs whose permit types were more difficult to ascertain, generally outside of
12 Pennsylvania. By 2013, the portion sentto zero-discharge facilities had risen to 90%, with about
13 5% sent to CWTs with NPDES permits and 5% sent to CWTs whose discharge permit type is not
14 clear. The high percentage sent to zero-discharge CWTs is consistent with the concerted focus on
15 reuse in Pennsylvania, although CWTs with NPDES permits also often provide treated wastewater
16 for reuse, further limiting discharges to surface waters. The waste records do not indicate if a CWT
17 has more than one permit type.
8.4.2.2. Residuals Management
18 Certain treatment processes at CWTs produce liquid or solids residuals as a by-product of that
19 process. The residuals produced depend on the constituents in the treated water and the treatment
20 process used. Residuals can consist of sludges (from precipitation, filtration, settling units, and
21 biological processes); spent media (media requiring replacement or regeneration from filtration,
22 adsorption, or ion exchange processes); concentrated brines (from membrane processes and some
23 evaporation processes); and regeneration and cleaning chemicals (from ion exchange, adsorption,
24 and membrane processes) (Fakhru'1-Razi etal.. 2009). Residuals from CWTs can constitute a
25 considerable fraction of solid waste in an oil or gas production area. Chiado (2014) found that solid
26 wastes from hydraulic fracturing in the Marcellus accounted for 5% of the weight of waste
27 deposited in landfills in the area, with some area landfills reaching as high as 60% landfill mass
2 8 coming from hydraulic fracturing activities.
2 9 Management of Solid Residuals
3 0 CWTs may apply additional treatment to solid residuals including thickening, stabilization (e.g.,
31 anaerobic digestion), and dewatering processes prior to disposal. The solid residuals are then
32 typically sent to a landfill, land applied, or incinerated (Morillon et al.. 2002). Pollutants may
33 accumulate in sludge, which may limit land application as a disposal option. For example, wastes
34 containing TENORMs can be problematic due to the possibility of radon emissions from the landfill
35 (Walter etal., 2012). In some states, many landfills that are specifically permitted to accept
36 TENORM have criteria written into their permits, including gamma exposure rate (radiation) levels
37 and radioactivity concentration limits. Most non-hazardous landfills have limits on maximum
38 radiation that can be accepted. For example, Pennsylvania requires alarms to be set at all municipal
39 landfills, with a trigger set at 10 u,R/hr above background radiation (Pa Code Title 25, Ch. 273.223
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 c). Texas sets a radioactivity limit, requiring that any waste disposed by burial contains less than 30
2 pCi/g radium or 150 pCi/g of other radionuclides (TX Code Ch 4 Section F Section 4.620). Some
3 states have volumetric limitations on TENORM in their permits (e.g., Colorado).
4 Solid residual wastes have the potential to impact the quality of drinking water resources if
5 contaminants leach to groundwater or surface water. In a recent study by PA DEP, radium was
6 detected in leachate from 34 of 51 landfills, with radium-226 concentrations ranging from 54 to
7 416 pCi/L, and radium-228 ranging from 2.5 to 1,100 pCi/L [PADEP. 2015b). Countess et al. [2014)
8 studied the potential for barium, calcium, sodium, and strontium to leach from sludges generated at
9 a CWT handling hydraulic fracturing wastewaters in Pennsylvania. Tests used various strong acid
10 solutions (to simulate the worst case scenario) and weak acid digestions (to simulate
11 environmental conditions). The extent of leaching varied by constituent and by fluid type; the data
12 illustrate the possibility of leaching of these constituents from landfills.
13 Management of Liquid Residuals
14 Practices for management of liquid residual streams are generally the same as for untreated
15 hydraulic fracturing wastewaters, although the reduced volumes tend to lower costs (Hammer and
16 VanBriesen. 2012). Concentrations of contaminants, however, will be higher. Liquids mixed with
17 other wastes can be disposed of in landfills if the liquid concentration is low enough. If the liquid is
18 not injected into a disposal well, treatment to remove salts would be required for surface water
19 discharge to meet NPDES permit requirements and protect the water quality for downstream users
20 (e.g., drinking water utilities) (see Section 8.6). Because some constituents of concentrated
21 residuals can pass through or impact municipal wastewater treatment processes (Linaric etal.,
22 2013: Hammer and VanBriesen. 2012). these residuals may not be appropriate for discharge to a
23 POTW. Elevated salt concentrations, in particular, can reduce or inhibit microbiological treatment
24 at municipal wastewater systems such as activated sludge treatment (Linaric et al., 2 013).
8.4.3. Water Reuse for Hydraulic Fracturing
25 Water reuse in hydraulic fracturing operations has increased in recent years, with wastewaters
26 being used to formulate hydraulic fracturing fluids for subsequent fracturing jobs (Boschee. 2014,
27 2012: Gregory etal., 2011: Rassenfoss, 2011). Wastewater may be reused after some form of
28 treatment (sometimes only settling), depending on the reuse water quality requirements, and it
29 may be supplied for use in hydraulic fracturing through various routes. Reused water is discussed
30 in Chapter 4 of this report (Water Acquisition) as well as in this chapter, though in a different
31 context. The water reuse rate described in this chapter is the amount or percentage of generated
32 wastewater that is managed by being provided to operators for use in additional hydraulic
33 fracturing operations. In contrast, Chapter 4 discusses reused wastewater as a source water and as
34 one part of the base fluid for new fracturing fluid.
35 Hydraulic fracturing wastewater reuse reduces costs associated with other forms of wastewater
3 6 management, and the economic benefits and feasibility of reuse can be expected to figure into
37 ongoing wastewater management decisions. However, although reuse minimizes other forms of
38 wastewater management on a local and short-term basis (e.g., those involving direct or indirect
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 discharge to surface waters), reuse can result in the accumulation of dissolved solids (e.g., salts and
2 TENORMs) as the process returns water to the subsurface. For example, data from a PA DEP study
3 [PADEP. 2015b) suggests that hydraulic fracturing fluids that include reused wastewater already
4 contain radium-226 and radium-228. Eventually, wastewaters with a component that has been
5 reused more than once will need to be definitively managed, either through treatment or injection.
6 Residuals from treatment will also require proper management to avoid potential impacts on water
7 resources (see Section 8.4.2.2) (Kappeletal., 2013).
8.4.3.1. Factors in Considering Reuse
8 In making the decision whether to manage wastewater via reuse, operators have several factors to
9 consider (Slutz etal.. 2012: NPC. 2011a):
10 • Wastewater generation rates compared to water demand for future fracturing operations,
11 • Wastewater quality and treatment requirements for use in future operations,
12 • The costs and benefits of wastewater management for reuse compared with other
13 management strategies,
14 • Available infrastructure and treatment technologies, and
15 • Regulatory considerations.
16 Among these factors, costs may be the most significant driver, weighing the costs of transportation
17 from the generating well to the treatment facility and to the new well against the costs for transport
18 to alternative locations (a disposal well or CWT). Trucking large quantities of water can be
19 relatively expensive (from $0.50 to $8.00 per barrel), rendering on-site treatment technologies and
20 reuse potentially economically competitive in some settings (Dahm and Chapman. 2014: Guerra et
21 al.. 2011). Also, logistics, including proximity of the water sources for aggregation, may be a factor
22 in implementing reuse. For example, Boschee (2014) notes that in the Permian Basin, older
23 conventional wells are linked by pipelines to a central disposal facility, facilitating movement of
24 treated water to areas where it is needed for reuse.
25 Regulatory factors may facilitate reuse. In 2013, the Texas Railroad Commission adopted rules
26 intended to encourage statewide water conservation. These rules facilitate reuse by eliminating the
27 need for a permit when operators reuse on their own lease or transfer the fluids to another
28 operator for use in hydraulic fracturing (Rushton and Castaneda. 2014). Data for the years after
29 2013 will allow evaluation of whether reuse increases.
30 Recommended compositional ranges for base fluid may shift in the future as fracturing fluid
31 technology continues to develop. Development of fracturing mixture additives that are brine-
32 tolerant have allowed for the use of high TDS wastewaters (up to tens of thousands of mg/L) for
33 reuse in fracturing (Tiemann et al.. 2014: GTI. 2012: Minnich. 2011). Some new fracturing fluid
34 systems are claimed to be able to tolerate salt concentrations exceeding 300,000 mg/L (Boschee,
35 2014). This greater flexibility in acceptable water chemistry can facilitate reuse both logistically
36 and economically by reducing treatment needs. Additional discussion of the water quality feasible
37 for reuse and examples of recommended constituent concentrations are included in Appendix F.
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1 Reuse rates may also fluctuate with changes in the supply and demand of treated waste water and
2 the availability of fresh water. Flowback may be preferable to later-stage produced water for reuse
3 because it is typically generated in larger quantities from a single location as opposed to water
4 produced later on, which is generated in smaller volumes over time from many different locations.
5 Flowback water also tends to have lower IDS concentrations than later-stage produced water; in
6 the Marcellus, IDS has been shown to increase from tens of thousands to about 100,000 mg/L
7 during the first 30 days [BarbotetaL 2013: Maloney and Yoxtheimer. 2012] (see Chapter 7). The
8 changing production rate and quality of waste waters generated in a region as more wells go into
9 production need to be taken into account, as well as possible decreases in the demand for reused
10 water as plays mature [Lutz etal.. 2013: Hayes and Severin. 2012b: Slutz etal.. 20121.
8.4.3.2. Reuse Rates
11 Reliable information on reuse practices throughout the United States is hampered by a limited
12 amountof data thatare available and represent different regions of the country. In Table 8-5,
13 estimates have been compiled from various literature sources. Reuse rates are highest in the
14 Appalachian Basin, associated primarily with the Marcellus Shale. Documentation of reuse practices
15 is also more readily available for that region than for other parts of the country.
16 A number of studies have estimated reuse rates for Marcellus wastewater. Although the reported
17 values can differ substantially (see Table 8-5), the data point to a steep increase in reuse since
18 2008, with rates increasing from 0% to 10% in 2008 to upwards of 90% in 2013. As an example, an
19 analysis of waste disposal information from the PA DEP for Marcellus wells in Pennsylvania
20 (Hansenetal.. 2013] reports an increase in reuse from 9% (7.17 million gal or 27.1 million L] of
21 total wastewater volumes in 2008 to 56% (343.79 million gal or 1.3014 billion L] in 2011. During
22 that same timeframe, the authors report that disposal via brine/industrial waste treatment plants
23 increased from 32% in 2008 to 70% in 2009, and then declined to 30% in 2011. Because some
24 industrial waste treatment plants can treat wastewater for reuse, some of the volumes indicated by
25 Hansenetal. (2013] as managed by this route may have ultimately been used for fracturing,
26 meaning that the 56% value for 2011 is most likely an underestimate.
Table 8-5. Estimated percentages of reuse of hydraulic fracturing wastewater.
Play or Basin
Source and Year
2008
2009
2010
2011
2012
2013
East Coast
Marcellus, PA
Marcellus, PA
Marcellus, PA
Marcellus, WV
Marcellus, PA
Marcellus, PA
Marcellus, PA
Rahm etal. (2013)
Ma etal. (2014)
Shaffer et al. (2013)
Hansenetal. (2013)
Hansenetal. (2013)
Malonev and
Yoxtheimer (2012)
Tiemann etal. (2014)
9
9
8
15-20
6
25-48
88
20
67-80
73
56
71.6
72
90
65 (partial
year)
87
90
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Play or Basin
Marcellus, PA
Marcellus, PA
Marcellus, PA
Marcellus, PA
(SW region)
Marcellus, PA
(NE region)
Marcellus, PA
Source and Year
Rassenfoss (2011)
Wendel (2011)
Lutz et al. (2013)
Rahmetal. (2013)
Rahmetal. (2013)
Rahm and Riha (2014)
2008
2009
2010
~67 overall
(general
estimate)
96 (one
specific
company)
75-85
13 (prior to 2011)
~10
0
~15
0
-25-45
-55-70
2011
90
56
-70-80
-90-100
2012
2013
55-80 (general estimate - appears to
cover recent years)
Gulf Coast & Midcontinent
Fayetteville
West Permian
Midland
Permian
Anadarko
Barnett
Barnett
Eagle Ford
East Texas
Haynesville
Haynesville
Veil (2011)
Nicot et al. (2012)
Nicot et al. (2012)
Nicot et al. (2012)
Nicot et al. (2012)
Rahm and Riha (2014)
Nicot and Scanlon
(2012)
Nicot and Scanlon
(2012)
Argonne National
Laboratory (2014)
Rahm and Riha (2014)
20 (single
company
target)
0
2
20
5
5 (general estimate - appears to
cover recent years)
0
5
20
(estimate
based on
interviews)
0
5 (general estimate - appears to
cover recent years)
West Coast & Upper Plains
Bakken
Argonne National
Laboratory (2014)
0
1 According to Maloney and Yoxtheimer [2012], about 331 million gal (7.9 million bbl or 1.25 billion
2 L) of flowback and about 3 81 milliongal (about9.1 million bbl or 1.4 billion L) of produced water
3 (excluding flowback) were generated in the Marcellus in 2011. For flowback and produced water
June 2015
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 combined, about 72% was reused. Of the flowback, 90% was managed through reuse (other than
2 road spreading). Of produced brine water, 55.7% was reused (with 11.6% treated in CWTs and
3 27.8% injected into Class IID wells in Ohio). Reuse is higher in the northeastern part of the
4 Marcellus; in the southwestern portion, easier access to Class IID wells in Ohio makes disposal by
5 injection more feasible (Rahmetal.. 2013).
6 Data from Marcellus wastewater management reports submitted to PA DEP (PA PEP, 2015a) were
7 compiled for this assessment; the data suggest that rates of reuse for hydraulic fracturing (as
8 indicated by a waste disposal method of either "Reuse Other than Road Spreading" or a zero-
9 discharge CWT) increased from about 28% in the second half of 2010 to about 60% in 2011, 83% in
10 2013, and 89% in the first half of 2014. These values maybe underestimates because wastewater
11 treated at facilities with NPDES permits can be provided to operators for reuse, and the permit
12 types for some facilities could not be determined. Among the forms of reuse, on-site reuse ("Reuse
13 Other than Road Spreading") has risen steadily over the past few years, from about 8% in the
14 second half of 2010 to about 48% in 2011, 62% in 2012, and nearly 70% in the first half of 2014.
15 Outside of the Marcellus region, a lower percentage of wastewater from hydraulic fracturing
16 operations is reused. According to published literature, in Texas in 2011, 0% to 5% of wastewater
17 was reused in most basins, with the exception of the Anadarko Basin (20%) (Nicot and Scanlon,
18 2012): see Table 8-5. Maetal. (2014) note that only a small amount of reuse is occurring in the
19 Barnett Shale. Reuse has not yet been pursued aggressively in New Mexico or in the Bakken (North
20 Dakota) (Argonne National Laboratory. 2014: LeBas etal.. 2013). Other sources, however, indicate
21 growing interest in reuse, as evidenced in specialized conferences (e.g., "Produced Water Reuse
22 Initiative 2014" on produced water reuse in Rocky Mountain oil and shale gas plays), and available
23 state-developed information on reuse (e.g., fact sheet by the Colorado Oil and Gas Conservation
24 Commission) (Colorado Division of Water Resources: Colorado Water Conservation Board:
25 Colorado Oil and Gas Conservation Commission. 2014). The fact sheet discusses piping and trucking
26 wastewater to CWTs in the Piceance Basin to treat for reuse.
8.4.4. Evaporation
27 In drier climates of the western United States, natural evaporation may be an option for treatment
28 of hydraulic fracturing wastewater (see Figure 8-6). Production data from the California
29 Department of Conservation's Division of Oil, Gas, and Geothermal Resources (DOGGR) (California
30 Department of Conservation. 2015). for example, lists "evaporation-percolation" as the
31 management method for 23% to 30% of the wastewater from Kern County over the last few years.
32 However, data on volumes of wastewater managed are not readily available for all states where this
33 practice is employed.
34 Evaporation is a simple water management strategy that consists of transporting wastewater to a
35 pond or pit with a large surface area and allowing passive evaporation of the water from the surface
36 (Clark and Veil. 2009). The rate of evaporation depends on the quality of the wastewater as well as
37 the size, depth, and location of the pond. Evaporation also depends on local humidity, temperature,
38 and wind (NETL. 2014). The residual brine or solid can be disposed of in an underground injection
39 well or landfill (see Section 8.4.3.2 for more details). In colder, dry climates, a freeze-thaw
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1 evaporation method has been used to purify water from oil and gas wastewater [Boysenetal.,
2 19991.
Figure 8-6. Lined evaporation pit in the Battle Creek Field (Montana).
Source: DOE (2006). Permission from ALL Consulting.
3 Alternatively, operators may transport wastewater by truck to an off-site commercial facility.
4 Commercial evaporation facilities exist in Colorado, Utah, New Mexico, and Wyoming [NETL. 2014:
5 DOE, 2004]. Nowak and Bradish [2010] described the design, construction, and operation of two
6 large commercial evaporation facilities in Southern Cross, Wyoming and Danish Flats, Utah. Each
7 facility includes 14,000-gal (53,000 L] three-stage concrete receiving tanks, a sludge pond, and a
8 series of five-acre (20,234 m2] evaporation ponds connected by gravity or force-main underground
9 piping. The Wyoming facility, which opened in 2008, consists of two ponds with a total capacity of
10 approximately 84 million gal (2 million bbl or 320 million L). The Utah facility, open since 2009,
11 consists of 13 ponds with a total capacity of 218.4 million gal (5.2 million bbl or 826.7 million L].
12 Each facility receives 420,000 to 1.47 million gal (10,000 to 35,000 bbl or 1.6 million to 5.56 million
13 L] per day of wastewater from oil and gas production companies in the area. Evaporation pits are
14 subject to state regulatory agency approval and must meet state standards for water quality and
15 quantity (Boysenetal.. 2002]. Impacts on drinking water resources from evaporation pits might
16 arise if a pit is breached due to extreme weather or other factors affecting infrastructure and if
17 leaking wastewater reaches a surface water body; such events as related specifically to evaporation
18 pits appear not to have not been evaluated in the literature, and their prevalence is unknown.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.4.5. Publicly Owned Treatment Works
1 Prior to the development of unconventional resources, POTWs were used to treat wastewater and
2 other wastes from conventional oil and gas operations in some eastern states. Although this is not a
3 common treatment method for oil and gas wastes in the United States, the small number of
4 injection wells for waste disposal in Pennsylvania drove the need for disposal alternatives [Wilson
5 and Vanbriesen, 2012]. When development of the Marcellus Shale began, POTWs continued to be
6 used to treat wastewater, including wastes originating from new unconventional oil and gas wells
7 [Kappel etal.. 2013: Soeder and Kappel. 2009). However, unconventional wastewater from the
8 Marcellus region is difficult to treat at POTWs due to elevated concentrations of halides, heavy
9 metals, organic compounds, radionuclides, and salts [Lutz etal., 2013: Schmidt, 2013]. Most of
10 these constituents have the potential to pass through the unit treatment processes commonly used
11 in POTWs and can be discharged into receiving waters [Cusick. 2013: Kappel etal.. 2013). In
12 addition, research has found that sudden, extreme salt fluctuations can disturb POTW biological
13 treatment processes (Linaricetal., 2013: Lefebvre and Moletta, 2006]. In order to meetNPDES
14 requirements, POTWs used to blend the hydraulic fracturing wastewater with incoming municipal
15 wastewater. For example, Ferrar etal. [2013] note that, per PA DEP requirements, one facility could
16 only accept up to 1% of their influent volume from unconventional oil and gas wastewater per day.
17 The annual reported volume of oil and gas produced wastewater treated at POTWs in the Marcellus
18 Shale region peaked in 2008 and has since declined to virtually zero (see Figure 8-7]. This decline
19 has been attributed to stricter discharge limits for TDS for POTWs in Pennsylvania and widespread
20 voluntary compliance on behalf of oil and gas operators with the May 2011 request from PA DEP to
21 cease sending Marcellus Shale wastewater to 15 treatment plants (including both POTWs and
22 CWTs] by May 19, 2011 (Rahm etal.. 2013]. To comply with the request, the oil and gas industry in
23 Pennsylvania accelerated the transition of wastewater deliveries from POTWs to CWTs for better
24 removal of metals and suspended solids (Schmidt. 2013]. However, treated effluent from CWTs
25 may be delivered to POTWs for additional treatment assuming treatment processes at POTWs are
26 not adversely affected and the POTWs can continue to meet NPDES discharge limits (Hammer and
27 VanBriesen. 2012]. General Pretreatment Regulations and State and local regulations typically
28 govern the pre-treated water volumes and qualities that can be accepted by the POTW.
29 Although operators stopped sending Marcellus Shale wastewater to POTWs in May of 2011,
30 conventionally produced wastes have continued to be processed at POTWs in Pennsylvania,
31 although at small volumes (29 Mgal and 20 Mgal for the years 2010 and 2011, respectively] (Wilson
32 and Vanbriesen. 2012].
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
140
120
100
80
60
AC
2G
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
• Marcellus (Mgal) • Conventional (Mgal)
Figure 8-7. Oil and gas wastewater volumes discharged to POTWs from 2001-2011 in the
Marcellus Shale.
Source: Lutz et al. (2013).
1 At least one study has evaluated POTW effluent chemistry before and after the cessation of
2 treatment of hydraulic fracturing wastewater. Ferrar etal. [2013] collected effluent samples from
3 two POTWs and one CWT facility in Pennsylvania before and after the 2011 PA DEP request.
4 Results from POTW effluent samples collected while the facilities were still treating Marcellus Shale
5 wastewater showed that concentrations of several analytes (barium, manganese, strontium, TDS,
6 and chloride) were greater than various drinking water and surface water criteria (i.e., EPA MCLs
7 and secondary MCLs for drinking water, surface water quality standards for aquatic life, and/or
8 surface water standards for human consumption of aquatic organisms). Results for effluent samples
9 collected after the POTWs stopped receiving Marcellus wastewater showed a statistically
10 significant decrease in the concentrations of several of these constituents. In particular, one of the
11 two POTWs showed a decrease in average barium concentration from 5.99 mg/L to 0.141 mg/L, a
12 decrease in the average strontium concentration from 48.3 mg/L to 0.236 mg/L, and a decrease in
13 the average bromide concentration from 20.9 mg/L to <0.016 mg/L. Influent concentrations at the
14 other POTW were lower (0.55 mg/L for barium, 1.63 mg/L for strontium, and 0.60 for bromide),
15 but significant decreases in these constituents were also seen in the effluents (0.036 mg/L barium,
16 0.228 mg/L strontium, and 0.119 for bromide); this POTW had continued to accept conventional oil
17 and gas wastewater. The authors conclude that the decreases in the concentrations of the various
18 constituents indicate that the elevated concentrations in the first samplings can be attributed to the
19 contribution of wastewater from unconventional natural gas development.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.4.6. Other Management Practices and Issues
1 Additional strategies for wastewater management in some states include discharging to surface
2 waters and land application. Wastewater from CBM fracturing and production, in particular,
3 generally has lower IDS concentrations than wastewater from other types of unconventional plays
4 and lends itself more readily to beneficial use. Below is a discussion of these other management
5 practices.
8.4.6.1. Land Application, Including Road Spreading
6 Land application has been done using brines from conventional oil and gas production. Road
7 spreading can be done for dust control or de-icing. Although recent data are not available, an
8 American Petroleum Institute (API) survey estimated that approximately 75.6 million gal (1.8
9 million bbl or 286 million L) of wastewater was used for road spreading in 1995 (API. 2000). The
10 API estimate does not specifically identify hydraulic fracturing wastewater. There is no current
11 nationwide estimate of the extent of road spreading using hydraulic fracturing wastewater.
12 Road spreading with hydraulic fracturing wastewater is regulated primarily at the state level
13 (Hammer and VanBriesen. 2012] and is prohibited in some states. For example, with annual
14 approval of a plan to minimize the potential for pollution, PA DEP allows spreading of brines from
15 conventional wells for dust control or road stabilization. Hydraulic fracturing flowback, however,
16 cannot be used for dust control and road stabilization (PADEP. 2011b). In West Virginia, use of gas
17 well brines for roadway de-icing is allowed per a 2011 memorandum of agreement between the
18 West Virginia Division of Highways and the West Virginia Department of Environmental Protection,
19 but the use of "hydraulic fracturing return fluids" is not permitted (Tiemann et al., 2014: West
20 Virginia DEP. 20111.
21 Concerns about road application center on contaminants such as barium, strontium, and radium. A
22 report from PA DEP analyzed several commercial rock salt samples and compared results with
23 contaminants found in Marcellus Shale flowback samples; the results noted elevated barium,
24 strontium, and radionuclide levels in Marcellus Shale brines compared with commercial rock salt
25 (Titler and Curry. 2011). Another study found increases in metals (radium, strontium, calcium, and
26 sodium) in soils ranging from 1.2 to 6.2 times the original concentration (for radium and sodium,
27 respectively), attributed to road spreading of wastewater from conventional oil and gas wells for
28 de-icing purposes (Skalaketal., 2014).
29 Potential impacts on drinking water resources from road spreading, have been noted by Tiemann et
30 al. (2014) and Hammer and VanBriesen (2012). These include potential effects of runoff on surface
31 water, or migration of brines to groundwater. Snowmelt may carry salts or other chemicals from
32 the application site, with the possibility of transport increasing if application rates are high or rain
33 occurs soon after application (Hammer and VanBriesen. 2012). Research on the impacts of
34 conventional road salt application has documented long-term salinization of both surface water and
35 ground water in the northern United States; by the 1990s, 24% of public supply wells in the Chicago
36 area had chloride concentrations exceeding 100 mg/L (Kelly, 2008: Kaushal etal., 2005). When
37 conventional oil field brine was used in a controlled road spreading experiment, elevated chloride
38 concentrations were detected in shallow ground water (531 ppm in winter and 1,360 ppm in
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1 summer [Bair and Digel, 1990]. The amount of salt contributed to drinking water resources due to
2 road application of hydraulic fracturing waste waters has not been quantified.
3 In managing solid wastes from oil and gas production, a study on land application of oilfield scales
4 and sludges suggested that radium in samples became more mobile after incubation with soil under
5 moist conditions, due to microbial processes and interactions with the soil and water [Matthews et
6 al., 2006]. Overall, potential effects from land application on drinking water resources are not well
7 understood.
8 Additionally, drill cuttings must be managed; in some places they are left in the reserve pit (pit for
9 waste storage], allowed to dry and, buried on-site [Kappeletal.. 2013]. More, commonly, however,
10 drill cuttings are disposed of in landfills [Chiado. 2014]: about half of Marcellus drill cuttings are
11 disposed of in Pennsylvania, while the rest are trucked to Ohio or West Virginia [Maloney and
12 Yoxtheimer. 2012].
8.4.6.2. Management of Coalbed Methane Wastewater
13 Wastewater from CBM wells can be managed like other hydraulic fracturing wastewater discussed
14 above. However, the wastewater from CBM wells can also be of higher average quality (e.g., lower
15 TDS content] than wastewater from other hydraulically fractured wells, which makes it more
16 suitable for certain management practices and uses. A number of management strategies have been
17 proposed or implemented, with varying degrees of treatment required depending on the quality of
18 the wastewater and the requirements of the intended use (Hulme. 2005: DOE. 2003. 2002].
19 Although specific volumes managed through the various practices below are not well documented,
20 qualitative information and considerations for feasibility are available and presented below.
21 CBM wastewater quality, which can range from an average of nearly 1,000 mg/L TDS in the Powder
22 River Basin to an average of about 4,700 mg/L in the San Juan Basin (see Appendix Table E-3],
23 plays a large role in how the wastewater is managed. In basins with higher TDS such as the San
24 Juan, Uinta, and Piceance, nearly all the wastewater is disposed of in injection wells. Wastewater
25 may also be injected for aquifer storage and recovery, with the intention of later recovering the
26 water for some other use fDOE. 20031
27 Discharge to rivers and streams for wildlife, livestock, and agricultural use, a management option
28 governed by the CWA, may be permitted in some cases. To be discharged, the wastewater must
29 meet technology-based limitations established by the permit authority and any applicable water
30 quality water quality standards. Direct discharge to streams (with or without treatment] is possible
31 where wastewater is of higher quality. This is a more common method of wastewater management
32 in basins such as the Raton Basin in Colorado and the Tongue River drainage of the Powder River
33 Basin in Montana fNRC. 20101
34 Agricultural uses include livestock watering, crop irrigation, and commercial fisheries. Livestock
3 5 watering with CBM wastewater is a common practice, and irrigation is an area of active research
36 (e.g.. Engle etal.. 2011: NRC. 2010]. Irrigation with treated CBM wastewater would be most suitable
37 on coarse-textured soils, for cultivation of salt-tolerant crops (DOE, 2003]. NRC (2010] remarks
38 that "use of CBM produced water for irrigation appears practical and sustainable," provided that
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 appropriate measures are taken such as selective application, dilution or blending, appropriate
2 timing, and rehabilitation of soils. Approximately 13% of CBM wastewater in the Powder River
3 Basin in Wyoming, and 26% to 30% in Montana, is used for irrigation [NRG. 2010).
4 As noted above, a degree of treatment is needed for some uses. Plumlee etal. [2014] examined the
5 feasibility, treatment requirements, and cost of several hypothetical uses for CBM wastewater. In
6 several cases, costs for these uses were projected to be comparable to or less than estimated
7 disposal costs. In one case study CBM wastewater for stream augmentation or crop irrigation was
8 estimated to cost between $0.26 and $0.27 a barrel and disposal costs ranged from $0.01 per barrel
9 (pipeline collection system with impoundment) to $2.00 per barrel (hauling for disposal or
10 treatment).
11 The applicability of particular uses may be limited by ecological and regulatory considerations, as
12 well as the irregular nature of CBM wastewater production (voluminous at first, and then declining
13 and halting after a period of years). Legal issues, including overlapping jurisdictions at the state
14 level and, in western states, senior water rights claims in over-appropriated basins, may also
15 determine use of CBM wastewater (Wolfe and Graham. 2002).
8.4.6.3. Other Documented Uses of Hydraulic Fracturing Wastewater
16 Uses of wastewater from shales or other hydraulically fractured formations face many of the same
17 possibilities and limitations as those associated with wastewater from CBM operations. The biggest
18 difference is in the quality of the water. Wastewaters vary widely in water quality, with TDS values
19 from shale sand tight sand formations ranging from less than 1,000 mg/L TDS to hundreds of
20 thousands of mg/L TDS (DOE. 2006). Wastewaters on the lower end of the TDS spectrum could be
21 reused in many of the same ways as CBM Wastewaters, depending on the concentrations of
22 potentially harmful constituents and applicable federal, state, and local regulations. High TDS
23 wastewaters have more limited uses, and pre-treatment may be necessary (Shaffer etal., 2013:
24 Guerraetal.. 2011: DOE. 2006).
2 5 Documented potential uses for wastewater in the western United States include livestock watering,
26 irrigation, supplementing stream flow, fire protection, road spreading, and industrial uses, with
27 each having their own water quality requirements and applicability (Guerra etal.. 2011). Guerra et
28 al. summarized the least conservative TDS standards for five possible uses in the western United
29 States that include 500 mg/L for drinking water (the secondary MCL), 625 mg/L for groundwater
30 recharge, 1,000 mg/L for surface water discharge, 1,920 mg/L for irrigation, and 10,000 mg/L for
31 livestock watering. The authors estimated that wastewater from 88% of unconventional wells in
32 the western United States could be used for livestock watering without treatment for TDS removal
33 based on a maximum TDS concentration of 10,000 mg/L. Wastewater from 10% of unconventional
34 wells were estimated to meet the criterion of 1,000 mg/L TDS for surface water discharge (Guerra
35 etal.. 2011).
36 A2006 Department of Energy (DOE) study points out that the quality necessary for use in
37 agriculture depends on the plant or animal species involved. Other important factors include the
38 sodium adsorption ratio and concentrations of TDS, calcium, magnesium, and other constituents
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1 [DOE, 2006]. The authors note that in the Bighorn Basin in Wyoming, low salinity wastewater is
2 used for agriculture and livestock watering after minimal treatment to remove oil and grease [DOE,
3 20061
8.5. Summary and Analysis of Wastewater Treatment
4 A variety of individual treatment techniques and combinations of techniques may be employed for
5 removal of hydraulic fracturing wastewater constituents of concern. These include methods
6 commonly employed in municipal wastewater treatment as well as more advanced processes such
7 as desalination. Treatment technologies are selected based on the water quality of the wastewater
8 to be treated and the effluent concentration required for the intended management method(s) (i.e.,
9 reuse, discharge to POTW, and discharge to surface water body). For example, if reuse is planned,
10 the level of treatment will depend on the water quality needed to formulate the new fracturing
11 fluid.
12 This section discusses treatment technologies that are most effective for removing specific
13 hydraulic fracturing wastewater constituents. It provides information on the unit processes
14 appropriate for treating different types of constituents as well as challenges associated with their
15 use. Considerations when designing a treatment system are also discussed for both centralized and
16 on-site (i.e., mobile) facilities.
8.5.1. Overview of Treatment Processes for Hydraulic Fracturing Wastewater
17 This section provides a brief overview of the treatment technologies used to treat hydraulic
18 fracturing wastewater; Appendix F provides more in-depth descriptions of these technologies.
19 The most basic treatment need for oil and gas wastewaters, including those from hydraulic
20 fracturing operations is separation to remove suspended solids and oil and grease, done using basic
21 separation technologies (e.g., hydrocyclones, dissolved air or induced gas flotation, media filtration,
22 or biological aerated filters). Other treatment processes that may be used include media filtration
23 after chemical precipitation for hardness and metals (Boschee. 2014). adsorption technologies,
24 including ion exchange (organics, heavy metals, and some anions) (Igunnu and Chen, 2014], a
25 variety of membrane processes (microfiltration, ultrafiltration, nanofiltration, RO), and distillation
26 technologies. In particular, advanced processes such as RO or distillation methods (e.g., mechanical
27 vapor recompression (MVR)) are needed for significant reduction in TDS (Drewes etal.. 2009: LEau
28 LLC. 2008: Hamieh and Beckman. 2006). An emerging technology is electrocoagulation, which has
29 been used in mobile treatment systems to treat hydraulic fracturing wastewaters (Halliburton,
30 2014: Igunnu and Chen. 2014). Removal efficiencies for hydraulic fracturing wastewater
31 constituents by treatment technology are provided in Appendix F.
8.5.2. Treatment of Hydraulic Fracturing Waste Constituents of Concern
32 The constituents prevalent in hydraulic fracturing wastewater include suspended solids, TDS,
33 anions (e.g., chloride, bromide, and sulfate), metals, radionuclides, and organic compounds (see
34 Section 8.3 and Chapter 7). If the end use of the wastewater necessitates treatment, a variety of
35 technologies can be employed. This section discusses effective unit processes for removing these
36 constituents and provides examples of treatment processes being used in the field as well as
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 emerging technologies. Table 8-6 provides an overview of influent and effluent results at various
2 CWTs for the constituents of concern listed in this section and the specific technology(ies) used to
3 remove them.
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Table 8-6. Studies of removal efficiencies and influent/effluent data for various processes and facilities.
Constituents
of concern
TSS
IDS
Location and results
Pinedale Anticline Water
Reclamation Facility,
Wyoming
(Shafer, 2011)
Results not reported.
>99%
Inf. = 8,000 to
15,000 mg/L
Eff. = 41 mg/L
RO
Maggie Spain Water-
Recycling Facility, Barnett
Shale, Texas
(Haves et al., 2014)
90%
Inf. = 1,272 mg/L
Eff. = 9 mg/L
Chemical oxidation,
coagulation, and
clarification
99.7%
Inf. = 49,550 mg/L
Eff. = 171 mg/L
MVR(3 units in parallel)
Judsonia, Sunnydale,
Arkansas
(U.S. EPA, 2015f)
No influent data.
Eff.: <4 mg/L
Meets NPDES Permit
Settling, biological
treatment, and induced
gas flotation
Results not reported.
MVR
9-month study treating
Marcellus Shale waste
using thermal distillation
(Boschee. 2014: Bruff and
Jikich, 2011)
>90%
Inf.: 35 to 114 mg/L
Eff. :<3 to 3 mg/L
100 micron mesh bag filter
98%
Inf.: 22,350 to 37,600 mg/L
Eff.: 9 to 400 mg/L
Thermal distillation
San Ardo Water
Reclamation Facility, San
Ardo, California
(Conventional oil and gas)
(Dahm and Chapman. 2014;
Webb et al., 2009)
Results not reported.
97%
Inf. = 7,000 mg/L
Eff. = 180 mg/L
Ion exchange softening and
double-pass RO
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Constituents
of concern
Anions
Location and results
Pinedale Anticline Water
Reclamation Facility,
Wyoming
(Shafer. 2011)
Chloride: >99%
Inf. = 3,600 to 6,750 mg/L
Eff. = 18 mg/L
Sulfate: 99%
Inf. = 10 to 100 mg/L
Eff. = non-detect
RO
Maggie Spain Water-
Recycling Facility, Barnett
Shale, Texas
(Haves et al.. 2014)
Sulfate: 98%
Inf. = 309 mg/L
Eff. = 6 mg/L
Chemical oxidation,
coagulation, clarification,
and MVR
Judsonia, Sunnydale,
Arkansas
(U.S. EPA, 2015f)
Sulfate:
No influent data.
Eff.: 12 mg/L
Meets NPDES Permit
MVR
9-month study treating
Marcellus Shale waste
using thermal distillation
(Boschee, 2014: Bruff and
Jikich, 2011)
Bromide: >99%
Inf.: 101 to 162.5 mg/L
Eff.: <0.1 to 1.6 mg/L
Chloride: 98%
Inf.: 9,760 to 16,240 mg/L
Eff.: 2.9 to 184.2 mg/L
Sulfate: 93%
Inf.: 20.4 to <100 mg/L
Eff.: <1 to 2.2 mg/L
Fluoride: 96%
lnf.:<2to<20mg/L
Eff. :<0.2 to 0.42 mg/L
Thermal distillation
San Ardo Water
Reclamation Facility, San
Ardo, California
(Conventional oil and gas)
(Dahm and Chapman. 2014:
Webb et al., 2009)
Chloride: >99%
Inf. = 3,400 mg/L
Eff. = 11 mg/L
Double-pass RO
Sulfate: 6%
Inf. = 133 mg/L
Eff. = 125 mg/L
Sulfuric acid is added after
RO to neutralize the pH so
no sulfate removal is
expected.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Constituents
of concern
Metals
Location and results
Pinedale Anticline Water
Reclamation Facility,
Wyoming
(Shafer. 2011)
Boron: 99%
Inf. = 15 to 30 mg/L
Eff. = non-detect
Ion exchange
Maggie Spain Water-
Recycling Facility, Barnett
Shale, Texas
(Haves et al.. 2014)
Iron: >99%
Inf. = 28 mg/L
Eff. =0.1 mg/L
For iron, 90% attributed to
chemical oxidation,
coagulation, and
clarification
Boron: 98%
Inf. = 17 mg/L
Eff. = 0.4 mg/L
Barium: >99%
Inf. = 15 mg/L
Eff. =0.1 mg/L
Calcium: >99%
Inf. = 2,916 mg/L
Eff. = 3.2 mg/L
Judsonia, Sunnydale,
Arkansas
(U.S. EPA, 2015f)
Cobalt:
No influent data.
Eff. :<0.007 mg/L
Tin:
No influent data.
Eff. :<0.1 mg/L
Arsenic:
No influent data.
Eff. :<0.001 mg/L
Cadmium:
No influent data.
Eff. :<0.0001 mg/L
Chromium:
No influent data.
Eff. :<0.007 mg/L
Copper:
No influent data.
Eff. :<0029 mg/L
9-month study treating
Marcellus Shale waste
using thermal distillation
(Boschee, 2014: Bruff and
Jikich, 2011)
Copper: >99%
Inf. = <0.2 to <1.0 mg/L
Eff. = <0.02 to <0.08 mg/L
Zinc: inf below detect
Inf. = <0.2 to <1.0 mg/L
Eff. = <0.02 to 0.05 mg/L
Barium: >99%
Inf. = 260.5 to 405.5 mg/L
Eff. =<0.1 to 4.54 mg/L
Strontium: 98%
Inf. = 233 to 379 mg/L
Eff. = 0.026 to 3.93 mg/L
Iron:
Inf. = 13.9 to 22.9 mg/L
Eff. = <0.02 to 0.06 mg/L
Manganese: 98%
Inf. = 2 to 2.9 mg/L
Eff. = <0.02 to 0.04 mg/L
San Ardo Water
Reclamation Facility, San
Ardo, California
(Conventional oil and gas)
(Dahm and Chapman. 2014:
Webb et al., 2009)
Sodium: 98%
Inf. = 2,300 mg/L
Eff. = 50 mg/L
Boron: >99%
Inf. = 26 mg/L
Eff. =0.1 mg/L
RO with elevated influent
pH
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Constituents
of concern
Metals,
cont.
Location and results
Pinedale Anticline Water
Reclamation Facility,
Wyoming
(Shafer. 2011)
Maggie Spain Water-
Recycling Facility, Barnett
Shale, Texas
(Haves et al.. 2014)
Magnesium: >99%
Inf. = 316 mg/L
Eff. = 0.4 mg/L
Sodium: >99%
Inf. = 10,741 mg/L
Eff. = 14.3 mg/L
Strontium: >99%
Inf. = 505 mg/L
Eff. = 0.5 mg/L
MVR
Judsonia, Sunnydale,
Arkansas
(U.S. EPA, 2015f)
Lead:
No influent data.
Eff.: <0.001 mg/L
Mercury:
No influent data.
Eff.: <0.005 mg/L
Nickel:
No influent data.
Eff.: 0.002 mg/L
Silver:
No influent data.
Eff.: <0.0002 mg/L
Zinc:
No influent data.
Eff.: 0.02 mg/L
Cyanide:
No influent data.
Eff.: <0.01 mg/L
Meets NPDES permit
except for TMDLs for
hexavalent chromium
and mercury
9-month study treating
Marcellus Shale waste
using thermal distillation
(Boschee, 2014: Bruff and
Jikich, 2011)
Boron: 97%
Inf. =<1 to 3. 12 mg/L
Eff. = 0.02 to 0.06 mg/L
Calcium: 98%
Inf. = 1,175 to 1,933 mg/L
Eff. = 0.36 to 22.2 mg/L
Lithium: 99%
Inf. = 9.1 to 14.3 mg/L
Eff. = non-detecttoO.13
ms/L
1 ' '&/ •-
Magnesium: 98%
Inf. = 109.8 to 176.8 mg/L
Eff. =<0.1 to 2.04 mg/L
Sodium: 98%
Inf. = 4,712 to 7,781 mg/L
Eff. = 0.37 to 87.9 mg/L
Arsenic: 82%
Inf. = <0.01 to 0.028 mg/L
Eff. = <0.005 mg/L
Titanium: 86%
Inf. = <0.01 to 0.037 mg/L
Eff. = <0.005 mg/L
San Ardo Water
Reclamation Facility, San
Ardo, California
(Conventional oil and gas)
(Dahm and Chapman. 2014:
Webb et al., 2009)
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Location and results
Constituents
of concern
Pinedale Anticline Water
Reclamation Facility,
Wyoming
(Shafer. 2011)
Maggie Spain Water-
Recycling Facility, Barnett
Shale, Texas
(Haves et al.. 2014)
Judsonia, Sunnydale,
Arkansas
(U.S. EPA. 2015f)
9-month study treating
Marcellus Shale waste
using thermal distillation
(Boschee, 2014: Bruff and
Jikich. 2011)
San Ardo Water
Reclamation Facility, San
Ardo, California
(Conventional oil and gas)
(Dahm and Chapman. 2014:
Webb et al.. 2009)
Metals,
cont.
Settling, biological
treatment, induced gas
flotation, and MVR
Thermal distillation
Radio-
nuclides
Results not reported.
Results not reported.
Not regulated under
permit - believed to be
absent.
Radium-226: 97% - 99%
Inf. = 130 to 162 pCi/L
Eff. = 0.224 to 2.87 pCi/L
Radium-228: 97% - 99%
Inf. = 45 to 85.5 pCi/L
Eff. = 0.259 to 1.32 pCi/L
Gross Alpha: 97% - >99%
Inf. = 161to664pCi/L
Eff. = 0.841 to 6.49 pCi/L
Gross Beta: 98% - >99%
Inf. = 79.7 to 847 pCi/L
Eff. = 0.259 to 1.57 pCi/L
Thorium 232: 71%-90%
Inf. =0.055 to 0.114 pCi/L
Eff. = 0.011 to 0.016 pCi/L
Thermal distillation
Results not reported.
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Constituents
of concern
Organics
Location and results
Pinedale Anticline Water
Reclamation Facility,
Wyoming
(Shafer. 2011)
O&G: 99%
Inf. = 50 to 2,400 mg/L
Eff. = non-detect
BTEX: 99%
Inf. = 28 to 80 mg/L
Eff. = non-detect
Gasoline range organics:
RO: 99%
Inf. = 88 to 420 mg/L
Eff. = non-detect
Diesel range organics: 99%
Inf. = 77 to 1,100 mg/L
Eff. = non-detect
Methanol: 99%
Inf. = 40 to 1,500 mg/L
Eff. = non-detect
Oil-water separator,
anaerobic and aerobic
biological treatment,
coagulation, flocculation,
flotation, sand filtration,
membrane bioreactor,
and ultrafiltration
Maggie Spain Water-
Recycling Facility, Barnett
Shale, Texas
(Haves et al.. 2014)
TPH: >80%
Inf. = 388 mg/L
Eff. = 4.6 mg/L
BTEX: 94%
Inf. = 3.3 mg/L
Eff. = 0.2 mg/L
TOC: 48%
Inf. = 42 mg/L
Eff. = 22 mg/L
MVR
Judsonia, Sunnydale,
Arkansas
(U.S. EPA, 2015f)
Biochemical oxygen
demand:
No influent data.
Eff.: <2 mg/L
O&G:
No influent data.
Eff.: <5 mg/L
Benzo (k) fluoranthene:
No influent data.
Eff.: <0.005 mg/L
Bis (2-Ethylhexyl)
Phthalate:
No influent data.
Eff.: <0.001 mg/L
Butyl benzyl phthalate:
No influent data.
Eff.: <0.001 mg/L
Meets NPDES permit
Settling, biological
treatment, induced gas
flotation, and MVR
9-month study treating
Marcellus Shale waste
using thermal distillation
(Boschee, 2014: Bruff and
Jikich, 2011)
Acetone: 93%
Inf. = 8.71 to 13.8 mg/L
Eff. = 0.524 to 0.949 mg/L
Toluene: >80%
Inf. = 0.0083 to 0.0015
mg/L
Eff. = non-detect to 0.0013
___ /i
mg/L
Methane: >99%
Inf. =0.748 to 5.49 mg/L
Eff. = non-detect to 0.0013
___ /i
mg/L
DRO: 0 to 82%
Inf. =4 to 7.1 mg/L
Eff. = 0.99 to 4.9 mg/L
O&G: No removal
Thermal distillation
San Ardo Water
Reclamation Facility, San
Ardo, California
(Conventional oil and gas)
(Dahm and Chapman. 2014:
Webb et al., 2009)
Results not reported.
June 2015
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.5.2.1. Total Suspended Solids
1 The reduction of TSS is typically required for reuse. Hydraulic fracturing waste waters containing
2 suspended solids can plug the well and damage equipment if reused for other fracking operations
3 [Tiemann et al.. 2014: Hammer and VanBriesen. 2012). For treated water that is discharged, the
4 EPA has a secondary treatment standard for POTWs that limits TSS in the effluent to 30 mg/L (30-
5 day average). In addition, most advanced treatment technologies require the removal of TSS prior
6 to treatment to avoid operational problems such as membrane fouling/scaling and to extend the life
7 of the treatment unit TSS can be removed by several processes, such as coagulation, flocculation,
8 sedimentation, and filtration (including micro filtration and media and bag and/or cartridge
9 filtration), and with hydrocyclones, dissolved air flotation, freeze-thaw evaporation,
10 electrocoagulation, and biological aerated filters (Boschee, 2014: Igunnu and Chen, 2014: Drewes et
11 al.. 2009: Fakhru'1-Razi etal.. 2009) (see Appendix F).
12 Technologies that remove TSS have been employed in the Marcellus Shale (sedimentation and
13 filtration) (Mantell, 2013a): Utica Shale (chemical precipitation and filtration) (Mantell, 2013a):
14 Barnett Shale (chemical precipitation and inclined plate clarifier, >90% removal) (Hayes etal.,
15 2014): and Utah (electrocoagulation, 90% removal) (Halliburton. 2014). Details of examples of
16 operating treatment facilities are provided in Table 8-6.
8.5.2.2. Total Dissolved Solids
17 The TDS concentration of hydraulic fracturing wastewater is a key treatment consideration, with
18 the TDS removal needed dependent upon the intended use of the treatment effluent POTW
19 treatment and basic treatment processes at a CWT (i.e., chemical precipitation, sedimentation, and
20 filtration) are not reliable methods for removing TDS. Reduction requires more advanced treatment
21 processes such as RO, nanofiltration, thermal distillation (including MVR), evaporation, and/or
22 crystallization (Olssonetal.. 2013: Boschee. 2012: Drewes etal.. 2009). RO and thermal distillation
23 processes can treat waste streams with TDS concentrations up to 45,000 mg/L and more than
24 100,000 mg/L, respectively (Tiemann etal.. 2014). As noted in section 8.5.1, pretreatment (e.g.,
25 chemical precipitation, flotation, etc.) is typically needed to remove constituents that may cause
26 fouling or scaling or to remove specific constituents not removed by a particular advanced process.
27 Extremely high TDS waters may require a series of advanced treatment processes to remove TDS to
28 desired levels. However, the cost of treating high-TDS waters may preclude facilities from choosing
29 treatment if other options such as deep well injection are available and more cost-effective
30 (Tiemann et al., 2014). Emerging technologies such as membrane distillation and forward osmosis
31 are also showing promise for TDS removal and require less energy compared to other desalination
32 processes (Shaffer etal.. 2013).
33 Examples of facilities with advanced technologies and their effectiveness in reducing TDS
34 concentrations in hydraulic fracturing wastewaters from conventional and unconventional
35 resources are summarized in Table 8-6.
8.5.2.3. Anions
36 Although chemical precipitation processes can reduce concentrations of multivalent anions such as
37 sulfate, monovalent anions (e.g., bromide and chloride) are not removed by basic treatment
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 processes and require more advanced treatment such as RO, nanofiltration, thermal distillation
2 (including MVR), evaporation, and/or crystallization [Hammer and VanBriesen. 2012].
3 Ion exchange and adsorption are effective treatment processes for removing fluoride but not
4 typically the anions of concern in hydraulic fracturing wastewaters (bromide, chloride, sulfate)
5 (Drewes et al.. 2009]. Emerging technologies applicable to TDS will typically remove anions.
6 However, issues discussed above, such as the potential for scaling, still apply.
8.5.2.4. Metals and Metalloids
7 Chemical precipitation, including lime softening and chemical oxidation, is effective at removing
8 metals (e.g., sodium sulfate reacts with metals to form solid precipitates such as barium sulfate]
9 (Drewes etal.. 2009: Fakhru'1-Razi et al.. 2009]. However, as mentioned in Section 8.5.2.3, chemical
10 precipitation does not adequately remove monovalent ions (e.g., sodium, potassium], and the
11 produced solid residuals from this process typically require further treatment, such as de-watering
12 (Duraisamy etal., 2013: Hammer and VanBriesen, 2012]. Media filtration can remove metals if
13 coagulation/oxidation is implemented prior to filtration (Duraisamy etal., 2013]. Advanced
14 treatment processes such as distillation (with pH adjustment to prevent scaling], evaporation, RO,
15 and nanofiltration can remove dissolved metals and metalloids (Hayes etal.. 2014: Igunnu and
16 Chen, 2014: Bruffandlikich, 2011: Drewes etal., 2009]. However, if metal oxides are presenter
17 formed during treatment, they must be removed prior to RO and nanofiltration processes to
18 prevent membrane fouling (Drewes et al., 2009]. Also, boron is not easily removed by RO, achieving
19 less than 50% rejection (the percentage of a constituent captured and thus removed by the
20 membrane] at neutral pH (rejection is greater at higher pH values] (Drewes etal.. 2009]. Ion
21 exchange can be used to remove other metals such as calcium, magnesium, barium, strontium, and
22 certain oxidized heavy metals such as chromate and selenate (Drewes et al., 2009]. Adsorption can
23 remove metals but is typically used as a polishing step to prolong the replacement/regeneration of
24 the adsorptive media (Igunnu and Chen. 2014].
25 The literature provides examples of facilities able to reduce metal and metalloid concentrations in
2 6 conventional and unconventional hydraulic fracturing wastewaters, some of which are provided in
27 Table 8-6. The facilities in Table 8-6 have achieved removals of 98%-99% for a number of metals.
28 Other work demonstrating effective removal includes a 99% reduction in barium using chemical
29 precipitation (Marcellus Shale region] (Warner etal.. 2013a] and over 90% boron removal with RO
30 (atpH of 10.8] at two California facilities (Webb etal.. 2009: Kennedy/Tenks Consultants. 2002].
31 However, influent concentration must be considered together with removal efficiency to determine
32 whether effluent quality meets the requirements dictated by end use or by regulations. In the case
33 of the facility described by Kennedy/Tenks Consultants (2002] the boron effluent concentration of
34 1.9 mg/L (average influent concentration of 16.5 mg/L] was not low enough to meet California's
35 action level of 1 mg/L.
36 Newer treatment methods for metals removal include electrocoagulation (Halliburton. 2014:
37 Gomes etal., 2009] and electrodialysis (Banasiak and Schafer, 2009]. Testing of electrocoagulation
38 has been performed in the Green River Basin (Halliburton, 2014] and the Eagle Ford Shale (Gomes
39 etal.. 2009]. While showing promising results in some trials, results of these early studies have
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 illustrated challenges, with removal efficiencies affected by factors such as pH and salt content
2 Membrane distillation has also shown promise in removing heavy metals and boron in wastewaters
3 fCamachoetal.. 20131
8.5.2.5. Radionudides
4 Several processes (e.g., RO, nanofiltration, and thermal distillation) are effective for removing
5 radionuclides [Drewes etal.. 2009). Ion exchange can be used to treat for specific radionuclides
6 such as radium [Drewes etal., 2009]. Chemical precipitation of radium with barium sulfate has also
7 been shown to be a very effective method for removing radium [Zhang et al.. 2014b).
8 Data on radionuclide removals achieved in active treatment plants are scarce. The literature does
9 provide some data from the Marcellus Shale region on use of distillation and chemical precipitation
10 (co-precipitation of radium with barium sulfate). The nine-month pilot-scale study conducted by
11 Bruff and Jikich (2011) showed that distillation treatment could achieve high removal efficiencies
12 for radionuclides (see Table 8-6), and Warner etal. (2013b) reported that a CWT achieved over
13 99% removal of radium via co-precipitation of radium with barium sulfate. However, in both
14 studies, radionuclides were detected in effluent samples, and the CWT was discharging to a surface
15 water body during this time (Warner etal.. 2013b: Bruff and Tikich. 2011): see Section 8.6.2.
16 Effluent from distillation treatment was found to contain up to 6.49 pCi/L for gross alpha (from 249
17 pCi/L prior to distillation) (Bruff and Tikich. 2011). Between 2010 and 2012, samples of wastewater
18 effluent from a western PA CWT contained a mean radium level of 4 pCi/L (Warner et al., 2013a).
8.5.2.6. Organics
19 Because hydraulic fracturing wastewaters can contain various types of organic compounds that
2 0 each have different properties, specific treatment processes or series of processes are used to
21 target the various classes of organic contaminants. Effectiveness of treatment depends on the
22 specific organic compound and the technology employed (see Appendix F). It should be noted that
23 in many studies, rather than testing for several organic constituents, researchers often measure
24 organics in terms of biochemical oxygen demand and/or chemical oxygen demand, which are an
25 indirect measure of the amount of organic compounds in the water. Organic compounds may also
26 be measured and/or reported in groupings such as total petroleum hydrocarbons (TPH) (which
27 include gasoline range organics (GROs) and diesel range organics (DROs)), oil and grease, VOCs
28 (which include BTEX), and SVOCs.
29 Based on examples found in literature, facilities have demonstrated the capability to treat for
30 organic compounds in hydraulic fracturing wastewaters using a single process or a series of
31 processes (Hayes etal.. 2014: Bruff and Jikich. 2011: Shafer. 2011] (see Table 8-6). The processes
32 can include anaerobic and aerobic biological treatment, coagulation, flocculation, flotation,
33 filtration, bioremediation, ultrafiltration, MVR, and dewvaporation. Forward osmosis is an
34 emerging technology that may be promising for organics removal in hydraulic fracturing
35 wastewaters because it is capable of rejecting the same organic contaminants as commercially-
36 available pressure-driven processes (Drewes etal.. 2009).
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.5.2.7. Estimated Treatment Removal Efficiencies
1 There are relatively few studies that have evaluated the ability of individual treatment processes to
2 remove constituents from hydraulic fracturing wastewater and present the resulting water quality.
3 Furthermore, although a specific technology may demonstrate a high removal percentage for a
4 particular constituent, if the influent concentration of that constituent is extremely high, the
5 constituent concentration in the treated water may still exceed permit limits and/or disposal
6 requirements. Appendix Table F-4 presents the results of simple calculations pairing average
7 hydraulic fracturing wastewater concentrations from Chapter 7 with treatment process removal
8 efficiencies reported in the literature in Table F-2.
9 As an example, radium in wastewater from the Marcellus Shale and Upper Devonian sandstones can
10 be in the thousands of pCi/L. With a 95% removal rate, chemical precipitation may result in effluent
11 that still exceeds 100 pCi/L. Distillation and reverse osmosis might produce effluent with
12 concentrations in the tens of pCi/L. A radium concentration of 120 pCi/L, however, could be
13 reduced to less than 5 pCi/L by RO or distillation. Wastewater with barium concentrations in the
14 range of 140 - 160 mg/L (e.g., the Cotton Valley and Mesaverde tight sands) might be reduced to
15 concentrations under 5 mg/L by distillation and roughly 11-13 mg/L by RO. Barium concentrations
16 in the thousands of mg/L would be substantially reduced by any of several processes but might still
17 be relatively high and could exceed 100 m g/L. Table F-4 also illustrates the potential for achieving
18 low concentrations of organic compounds in wastewater treated with freeze-thaw evaporation or
19 advanced oxidation and precipitation.
20 This analysis is intended to highlight the potential impacts of influent concentration on treatment
21 outcome and to illustrate the relative capabilities of various treatment processes for an example set
22 of constituents. Removal efficiencies would differ and likely be greater with a full set of
23 pretreatment and treatment processes that would be seen in a CWT (see Table 8-6).
8.5.3. Design of Treatment Trains for CWTs
24 Based on the chemical composition of the hydraulic fracturing wastewater and the desired effluent
25 water quality, a series of treatment technologies will most likely be necessary. The possible
26 combinations of unit processes to formulate treatment trains are extensive. One report identified
27 41 different treatment unit processes that have been used in the treatment of oil and gas
28 wastewater and 19 unique treatment trains (combinations of unit processes) (Drewes et al.. 2009).
29 Fakhru'1-Razi et al. (2009) also provide examples of process flow diagrams that have been used in
30 pilot-scale and commercial applications for treating oil and gas wastewater. Figure 8-8 shows the
31 treatment train for the Pinedale Anticline Facility, which includes pretreatment for dispersed oil,
32 VOCs, and heavy metals and advanced treatment for removal of TDS, dissolved organics, and boron.
33 This CWT can either discharge to surface water or provide the treated wastewater to operators for
34 reuse.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Produced Water
Ui
Oil/
Water
Separator
Anaerobic
Basin
Aeration
Basin
Clarifier
Sand
Filter
Bioreactor
Membrane
Bioreactor
Reverse
Osmosis
Additional
Treatment
and Disposal
Boron Ion
Exchange
Frac Water
to Pipeline
Distribution
Clean Water
Discharged to
Environment
Figure 8-8. Full discharge water process used in the Pinedale Anticline field.
Source: Boschee (2012).
1 Table 8-7 provides information on some CWTs in locations across the country and the processes
2 they employ. The table also notes for each facility whether data are readily available on effluent
3 quality. Comprehensive and systematic data on influent and effluent quality from a range of CWTs
4 that treat to a variety of water quality levels is difficult to procure, rendering it challenging to
5 understand removal efficiencies and resulting effluent quality, especially when a facility offers a
6 range of water quality products (e.g., for reuse vs. discharge). For those facilities with NPDES
7 permits, discharge monitoring report (DMR) data may be available for some constituents, although
8 if the facility does not discharge regularly, these data will be sporadic.
9 CWTs such as the Judsonia Central Water Treatment Facility in Arkansas, the Casella-Altela
10 Regional Environmental Services, and Clarion Altela Environmental Services (see Table 8-7)
11 facilities have NPDES permits and use MVR or thermal distillation for TDS removal. As of March
12 2015, the Pinedale Anticline Facility and the Judsonia Facility appear to be the only CWTs in Table
13 8-7 discharging to a surface water body.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Table 8-7. Examples of centralized waste treatment facilities.
Facility
Pinedale Anticline
Water Reclamation
Facility3
SEECO-Judsonia
Water Reuse
Recycling Facility
State
WY
AR
Description of Unit
Processes
Oil/water separation,
biological treatment,
aeration,
clarification, sand
filtration, bioreactor,
membrane
bioreactor, RO, and
ion exchange
Settling, biological
treatment, induced
gas flotation, and
MVR
Does CWT have
a NPDES permit
for discharge?
No - However,
facility is
permitted to
discharge under
40CFR435
Subpart E
(WY0054224).
Facility is
permitted to
discharge up to
25% of its
effluent stream
Yes-AR0052051
Does CWT
provide
effluent for
reuse?
Yes
Yes
Does CWT have
advanced process
for TDS removal?
Yes, RO (Boschee,
2014, 2012)
Yes, MVR
What is the status of the
facility as of January
2015?
The treatment plant
produces treated water
for reuse and for
discharge to surface
water.
The website indicates
the facility is in
operation and is
recycling to support
drilling operations and is
discharging to the New
Fork River
(http://hswater. squares
pace.com/pinedale-
anticline/).
The treatment plant
provides treated water
for reuse and for
discharge to surface
water. Based on DMR
data from late 2014-
early 2015, the system is
discharging treated
water to a surface water
body, though
intermittently.
Are effluent
quality data
available through
literature search?
Yes -DMR data
available on
Wyoming DEQ
website. Some
information can
also be obtained
from Shafer
(2011).
DMR data
available
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Facility
Eureka Resources -
Williamsport 2nd
Street Facility
Standing Stone
Facility, Bradford
County
State
PA
PA
Description of Unit
Processes
Settling, oil/water
separation, chemical
precipitation,
clarification, MVR.
Can treat with or
without IDS removal.
Settling, oil/water
separation, chemical
precipitation,
clarification, MVR,
crystallization
Does CWT have
a NPDES permit
for discharge?
No - However,
future plans to
install RO for
direct discharge
capability
Yes-PA0232351
Does CWT
provide
effluent for
reuse?
Yes
Yes
Does CWT have
advanced process
for TDS removal?
Yes, MVR
Yes, MVR,
crystallizer
What is the status of the
facility as of January
2015?
Per Erteletal. (2013),
the facility provides
treatment wastewater
for reuse and indirect
discharge.
The facility treats
entirely or almost
entirely hydraulic
fracturing wastewater.
The facility can provide
treated wastewater for
reuse and also has
received an NPDES
permit for direct
discharge.
The facility treats
hydraulic fracturing
wastewater.
Are effluent
quality data
available through
literature search?
No
No
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Facility
Wellington Water
Works
Casella Altela
Regional
Environmental
Services (CARES)
McKean Facility
State
CO
McKean
County,
PA
Description of Unit
Processes
Dissolved air
flotation, pre-
filtration,
microfiltration with
ceramic membranes,
activated carbon
adsorption. Water is
pumped to an aquifer
storage and recovery
well. Water is then
extracted and
treated with RO
(Alzahrani et al..
2013).
Pretreatment system
(not defined in
literature) and
thermal distillation
Does CWT have
a NPDES permit
for discharge?
Permit number
issued by CO
(61879)
Yes - PA0102288
Does CWT
provide
effluent for
reuse?
Yes
Yes
Does CWT have
advanced process
for TDS removal?
Yes, RO but only
after the water is
sent to an aquifer
storage and
recovery well
Yes -thermal
distillation
What is the status of the
facility as of January
2015?
PerStewart(2013b), the
facility is providing
treated wastewater for
reuse, for agricultural
use, to a shallow well to
augment the municipal
drinking water supply,
and for discharge to the
Colorado River.
The treatment plant is
capable of reuse and
recycle for fracturing
operations and surface
water discharge of
excess water. However,
the facility's website
indicates it is only
treating water for
reuse/recycle as of early
2015
( http ://ca resf orwater. co
m/location/cares-
mckean).
Are effluent
quality data
available through
literature search?
No
No -just NPDES
discharge
requirements
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Facility
Clarion Altela
Environmental
Services (CAES)
Facility
Terraqua Resource
Management (aka.
Water Tower Square
Gas Well Wastewater
Processing Facility)
Maggie Spain Water-
Recycling Facility
State
Clarion
County,
PA
Lycoming
County,
PA
Decatur,
TX
Description of Unit
Processes
Pretreatment system
(not defined in
literature) and
thermal distillation
Equalization tanks,
oil-water separation
via chemical addition
(sulfuricacid,
emulsion breaker),
pH adjustment,
coagulation,
flocculation, inclined
plate clarifier, sand
filtration
Settling, flash mixer
with lime and
polymer addition,
inclined plate
clarifier, surge tank,
MVR
Does CWT have
a NPDES permit
for discharge?
Yes - PA0103632
Yes - PA0233650
Permit pending
approval for
discharge to
stream (as of
4/17/2009)
No
Does CWT
provide
effluent for
reuse?
Yes
Yes
Yes
Does CWT have
advanced process
for TDS removal?
Yes- thermal
distillation
No - However,
TARM recognizes
that they can't
discharge, until
they install TDS
treatment
Yes - MVR
What is the status of the
facility as of January
2015?
The treatment plant
capable of reuse and
recycle for fracturing
operations and surface
water discharge of
excess water. However,
the facility's website
indicates it is only
treating water for
reuse/recycle as of early
2015
(http://caeswater.eom/t
echnology/).
According to its website
(last updated 2012), the
facility reuses/recycles
treated water for
fracturing operations
(http://www.tarmsolutio
ns.com/solutions/).
A 17-month pilot study
using a commercial-scale
mobile treatment facility
was concluded in 2011.
The status is unclear as
of early 2015.
Are effluent
quality data
available through
literature search?
No -just NPDES
discharge
requirements
No
Yes -Some
information can
be obtained from
Hayes et al.
(2014).
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Facility
Fountain Quail/NAC
Services - Kenedy
Purestream -
Gonzales facility
LINN Energy Fyre
Ranch -Granite Wash
State
Kenedy,
TX
Gonzales,
TX
Wheeler
County,
TX
Description of Unit
Processes
Oil-water separator,
coagulation,
flocculation,
sedimentation,
filtration, MVR.
Induced gas flotation
and MVR
Induced gas flotation
and MVR
Does CWT have
a NPDES permit
for discharge?
No
No
No
Does CWT
provide
effluent for
reuse?
Yes
Yes
Yes
Does CWT have
advanced process
for TDS removal?
Yes -MVR
Yes - MVR
Yes - MVR
What is the status of the
facility as of January
2015?
According to its website,
the facility
reuses/recycles treated
water for fracturing
operations
(http://www.aqua-
pure.com/operations/sh
ale/ford/ford. html).
Per Dahm and Chapman
(2014) commercial
operations deployed
March 2014 for
reuse/recycle for
fracturing operations.
AVARA system installed
for reuse/recycle in June
2014.
http://purestream.eom/i
ndex.php/water-
management/vapor-
recompression/photos-
and-videos
Are effluent
quality data
available through
literature search?
No
No
No
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Facility
Fluid Recovery
Service Josephine
Facility"
Fluid Recovery
Service Franklin
Facility
State
PA
PA
Description of Unit
Processes
Oil-water separator,
aeration, chemical
precipitation with
sodium sulfate, lime,
and a polymer,
inclined plate clarifier
Oil-water separator,
aeration, chemical
precipitation with
sodium sulfate, lime,
and a polymer,
inclined plate clarifier
Does CWT have
a NPDES permit
for discharge?
Expired -
PA0095273
Expired -
PA0101508
Does CWT
provide
effluent for
reuse?
No
No
Does CWT have
advanced process
for TDS removal?
No
No
What is the status of the
facility as of January
2015?
The facility claims to
have stopped accepting
Marcellus wastewater
September 30, 2011
(Ferraretal.,2013). It
treats conventional oil
and gas wastewater.
The facility will be
upgrading to include
evaporative technology
that will enable it to
attain monthly average
TDS levels of 500 mg/L
or less.
This facility is not
accepting wastewater
from hydraulic fracturing
operations as of January
2015.
The facility will be
upgrading to include
evaporative technology
that will enable it to
attain monthly average
TDS levels of 500 mg/L
or less.
Are effluent
quality data
available through
literature search?
Yes -Some
effluent results
obtained from
Ferrar et al.
(2013) and
Warner et al.
(2013a). Also
minimal DMR
data from the
EPA.
Minimal DMR
data from the
EPA.
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Chapter 8 - Wastewater Treatment and Waste Disposal
Facility
Hart Resources-
Creekside Facility15
State
PA
Description of Unit
Processes
Oil-water separator,
aeration, chemical
precipitation with
sodium sulfate, lime,
and a polymer,
inclined plate clarifier
Does CWT have
a NPDES permit
for discharge?
Expired -
PA0095443
Does CWT
provide
effluent for
reuse?
No
Does CWT have
advanced process
for TDS removal?
No
What is the status of the
facility as of January
2015?
This facility is not
accepting wastewater
from hydraulic fracturing
operations as of January
2015.
The facility will be
upgrading to include
evaporative technology
that will enable it to
attain monthly average
TDS levels of 500 mg/L
or less.
Are effluent
quality data
available through
literature search?
Minimal DMR
data from the
EPA.
a For Pinedale Anticline Water Reclamation Facility, surface water discharges are permitted under 40 CFR 435 Subpart E (beneficial use subcategory agricultural and wildlife
water) not 40 CFR 437 (the discharge permit for CWTs). For the purposes of this assessment, this facility is included with CWTs.
As of May 15, 2013, these facilities are under an administrative order (AO). According to the AO, these facilities must comply with a monthly effluent limit for IDS not to
exceed 500 mg/L. This will allow them to treat high-saline wastewaters typical of unconventional oil and gas operations. To meet the requirements of the AO, they have
applied to PADEP for a NPDES permit and are planning to install treatment for TDS.
June 2015
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.6. Potential Impacts on Drinking Water Resources
1 Several articles have noted potential effects of hydraulic fracturing wastewater on water resources
2 fVengoshetal..2Q14: OlmsteadetaL 2013: Rahmetal.. 2013: States etal.. 2013: VidicetaL 2013:
3 Rozell and Reaven. 2012: Entrekinetal.. 2011). with one study using probability modeling
4 indicating that water pollution risk associated with gas extraction in the Marcellus Shale is highest
5 for the wastewater disposal aspects of the operation [Rozell and Reaven, 2012]. Whether drinking
6 water resources are affected by hydraulic fracturing wastewater depends at least in part upon the
7 characteristics of the wastewater, the form of discharge or other management practice, and the
8 processes used if the wastewater is treated. Other site-specific factors (e.g., size of receiving water
9 and volume of wastewater) determine the magnitude and nature of potential effects, but a thorough
10 exploration of local factors is beyond the scope of this assessment The majority of hydraulic
11 fracturing wastewater is either injected into a disposal well or, in the case of the Marcellus region,
12 reused for other hydraulic fracturing jobs. Potential impacts on drinking water resources may occur
13 on a local level through several routes: treated wastewater may be discharged directly from
14 centralized waste treatment facilities (CWTs) or indirectly from publicly owned treatment works
15 (POTWs) that receive CWT effluent; sediments in water bodies receiving effluent may accumulate
16 contaminants; spills or leaks may be associated with on-site storage or transportation (see Chapter
17 7); and in previous years, hydraulic fracturing wastewater treated at POTWs was discharged to
18 surface waters.
19 It has been suggested that the most significant effects of hydraulic fracturing on surface water
2 0 quality are related to discharges of partially treated wastewater, although these effects vary
21 according to region (Kuwayamaetal.. 2015]. A recent study (Bowenetal.. 2015] concluded that
22 there is currently no clear evidence of national-level trends in surface water quality (as measured
23 by specific conductivity and chloride] in areas where unconventional oil and gas production is
24 taking place. These authors note that available national level databases have limitations for
25 assessing this question.
26 Pits and impoundments associated with waste management may have impacts on drinking water
27 resources and are discussed in Chapter 7. In addition, unauthorized discharge of wastewater is a
28 potential mechanism for impacts on drinking water resources. Descriptions of several incidents and
29 resulting legal actions have been publicly reported. However, such events are not generally
30 described in the scientific literature, and the prevalence of this type of activity is unclear.
31 Important considerations regarding the potential impact of hydraulic fracturing wastewater on a
32 receiving waterbody include whether constituents in the wastewater are known to have health
33 effects, if they are regulated drinking water contaminants, or if they may give rise to regulated
34 compounds. For some classes of constituents, such as disinfection by-product (DBF] precursors,
35 considerable research exists. For others, information is limited regarding their concentrations in
36 effluents and whether they are likely to affect drinking water at intakes. The following subsections
37 identify several classes of constituents known to occur in hydraulic fracturing wastewater, discuss
38 whether potential impacts are likely, and provide specific examples of information gaps.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.6.1. Bromide and Chloride
1 Bromide and chloride are two constituents commonly found in high-total dissolved solids (IDS)
2 hydraulic fracturing wastewater. As noted in section 8.3.1.1, chloride is a regulated contaminant
3 with a secondary MCL standard of 250 mg/L. Bromide is not regulated but is of concern due to its
4 role in the formation of DBFs [Parker etal.. 2014: Krasner. 2009] (see Appendix F for information
5 on DBF formation). High-TDS wastewaters from the Marcellus Shale can be of concern because the
6 limited availability of underground injection for disposal can result in a higher rate of discharge of
7 treated wastewater to surface waters compared to other parts of the country. In response to
8 concerns in part over bromide in discharges, operators in Pennsylvania have discontinued the
9 practice of sending wastewater from hydraulic fracturing operations to POTWs [States etal., 2013].
10 Also, CWTs have been shifting towards treatment of those wastewaters for reuse rather than
11 discharging to surface water bodies [Hammer and VanBriesen. 2012].
12 States etal. [2013] found a strong correlation between bromide concentrations in source water
13 from the Allegheny River in Pennsylvania and the percentage of brominated trihalomethanes in
14 finished drinking water. The authors noted that source water containing 50 |ig/L bromide resulted
15 in treated water with approximately 62% of its finished water total trihalomethanes consisting of
16 bromoform, dibromochloromethane, and bromodichloromethane. Source water containing 150
17 Mg/L bromide resulted in finished water TTHMs composed of approximately 83% brominated
18 species. Allegheny River bromide concentrations measured during the study ranged from less than
19 25 |ig/L to 299 |ig/L, with the highest bromide concentrations measured under low-flow
20 conditions. Industrial wastewater sites accounted for approximately 50% of the increase in
21 bromide load as water moved downriver.
22 In addition, a related constituent, iodide can be a constituent in hydraulic fracturing wastewater
23 (see Chapter 7). Although its effects have not been as well documented as those associated with
24 bromide (Xuetal.. 2008], iodide raises some of the same concerns (such as DBF formation] as
25 bromide does (Parker etal.. 2014: Krasner. 2009]. lodinated DBFs are not regulated by the EPA as
26 of early 2015.
27 As discussed in Section 8.5, removal of dissolved solids, including chloride and bromide, requires
28 advanced treatment processes such as reverse osmosis (RO], distillation, evaporation, or
29 crystallization. Unless the treatment plant receiving the high-TDS wastewater employs processes
30 specifically designed to remove these constituents, effluent discharge may contain high levels of
31 bromide and chloride. Drinking water treatment plants with intakes downstream of these
32 discharges may receive water with correspondingly higher levels of bromide and chloride and may
33 have difficulty complying with Safe Drinking Water Act (SDWA] regulations related to DBFs.
8.6.1.1. Effects on Receiving Streams
34 Studies show that discharges from oil and gas wastewater treatment facilities can elevate TDS,
35 bromide, and chloride levels in receiving waters (States etal.. 2013: Wilson and Van Briesen. 2013].
36 Wilson and Van Briesen (2013] measured bromide, chloride, and other constituents at water
37 intakes downstream of wastewater discharges for three years in the Monongahela River in western
38 Pennsylvania. By evaluating water chemistry data in the context of flow measurements, the authors
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 attributed an overall decrease in bromide concentrations from 2010 to 2012 to a decrease in
2 bromide loading; they note that this is likely to be associated with a decrease in management of
3 fossil fuel wastewater at treatment plants that discharge to surface water.
4 Although treatment plant effluents will be diluted upon reaching the receiving water, the dilution
5 may not be adequate to avoid water quality problems if there are existing pollutant loads in the
6 waterbody from contributors such as acid mine drainage or power plant effluents [Ferrar etal.,
7 2013). Warner etal. (2013a] evaluated effluent from the Josephine Brine Treatment Facility (which
8 treated both conventional and unconventional oil and gas wastewater at the time of the study) and
9 concluded that even a 500 to 3,000-fold dilution of the wastewater would not reduce bromide
10 levels to background. In addition, downstream levels of chloride in the receiving stream were
11 elevated, with a downstream value of 88 mg/L as compared to an upstream value of 18 mg/L.
12 A study by Hladiketal. [2014] focused on sampling at sites downstream and near the outfalls of
13 plants that treated oil and gas wastewater in Pennsylvania. The authors documented brominated
14 and iodinated DBFs (e.g., dibromochloronitromethane (DBNM); dibromoiodomethane) at the
15 outfalls of CWTs and POTWs and noted that this DBF signature was different than for those plants
16 that did not accept oil and gas wastewater. For example, concentrations of
17 dibromochloronitromethane ranged from 0.26 to 8.7 |ig/L, and dibromoiodomethane was
18 measured at 0.98 and 1.3 |ig/L; neither compound was detected at an upstream site or at the outfall
19 of the POTW not accepting oil and gas wastewater. These brominated and iodinated compounds are
20 considered more toxic than other types of DBFs (Richardson etal.. 2007). Hladik et al. note that
21 these elevated DBF levels could contribute to DBFs at downstream drinking water intakes and can
22 also be an indicator of the potential for more highly brominated and iodinated DPBs forming in
23 drinking treatment plants downstream of these discharges (Hladiketal., 2014]. The sites studied
24 by Hladiketal. (2014) received wastewater from both conventional and unconventional oil and gas
25 development
26 Research suggests that a relatively small portion of hydraulic fracturing wastewater effluent can
27 notably affect DBF formation. In laboratory studies, Parker etal. (2014) diluted hydraulic fracturing
28 wastewater from the Marcellus and Fayetteville shales with Allegheny and Ohio River waters and
29 then disinfected the mixtures. In chlorinated samples containing as little as 0.01% hydraulic
30 fracturing wastewater, the THM composition shifted significantly away from chloroform species to
31 a greater representation of brominated and iodinated species.
3 2 Elevated concentrations of bromide in effluents can place a burden on downstream drinking water
33 treatment systems. States etal. (2013] studied influent and finished water at the Pittsburgh Water
34 and Sewer Authority (PWSA) drinking water system, concluding that elevated bromide in the
35 source water led to elevated total trihalomethanes (TTHM) formation in the treated drinking water.
36 The authors also noted a substantial increase in the percentage of brominated TTHMs (States etal..
37 2013], as discussed above. The utility modified their treatment process and proposed
38 improvements to their storage facilities to address the elevated TTHM levels in the distribution
39 system (Chester Engineers, 2012].
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.6.1.2. Modeling
1 The EPA's contaminant modeling shows that that the strategies most likely to reduce bromide
2 impacts on downstream users include reducing effluent concentrations (e.g., discharging flowback
3 versus produced water), discharging during higher stream flow periods, and using a pulsing or
4 intermittent discharge. Weaver et al. [In Press] developed a computer model to estimate river and
5 stream bromide concentrations after treated water discharges. The model utilizes existing data for
6 bromide concentrations in produced water, flowback, and mixtures, combined with existing stream
7 flow data from USGS stations in Pennsylvania. The model parameters include steady state versus
8 transient inputs to receiving waters, high and low streamflow months, varying effluent
9 concentration and types (produced, flowback, and mixed). For steady-state scenarios in the model,
10 bromide concentrations are lowest under high flow conditions with lower concentrations of
11 effluent (flowback and mixed water).
12 A source apportionment study conducted by the EPA considered the relative contributions of
13 bromide, chloride, nitrate, and sulfate from CWTs primarily treating hydraulic fracturing
14 waste water to the Allegheny River Basin and to water at two downstream public water system
15 intakes on the Allegheny River (U.S. EPA. 2015p). The Allegheny River and its tributaries receive
16 runoff and discharges containing an array of contaminants, including these anions. Contaminant
17 sources include discharges from CWTs for oil and gas wastewater, runoff from acid mine drainage
18 and mining operations, discharges from coal-fired electric power stations, industrial wastewater
19 treatment plant effluents, and POTW discharges. The Allegheny River is also the water supply for
20 thirteen public water systems that serve over 500,000 people in western Pennsylvania.
21 In Pennsylvania, wastewater produced from hydraulic fracturing of the Marcellus formation has
22 been mostly diverted from CWTs and POTWs that discharge to public waters in the state (Hammer
23 and VanBriesen, 2012). Wastewater produced from hydraulic fracturing of non-Marcellus
24 formations, however, continues to be sent to surface-discharging facilities on the Allegheny River.
2 5 The source apportionment study considered contributions of bromide, chloride, nitrate and sulfate
26 to public water supplies from CWTs and other upriver sources by: developing chemical source
27 profiles, or fingerprints, for discharges upstream of the public water system intakes; characterizing
28 water quality in the river upstream and downstream of the CWTs, electric generating stations, and
29 industrial facilities; characterizing the water quality at the public water system intakes; and
30 analyzing the sampling data collected with the EPA Positive Matrix Factorization (PMF) receptor
31 model in order to quantify relative contributions of contaminant sources to the anions found at the
3 2 public water system intakes. The study focused on low-flow conditions.
33 CWTs and coal-fired power plants with flue gas desulfurization were found to contribute bromide
34 to the two public water supply intakes. Although acid mine drainage also contributed bromide, its
35 contribution was minor (9% at one intake) compared to the contributions from the CWTs (89%
36 and 3 7% at the two intakes) and coal-fired power plants (50-59% atone intake). The CWTs, coal-
37 fired power plants, and acid mine drainage combined accounted for 88-89% of the bromide at one
38 intake and 96% of the bromide at the other intake.
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
8.6.1.3. Summary
1 Most drinking water treatment plants are not designed to address high concentrations of IDS
2 (including bromide and iodide), limiting their options for restricting the formation of brominated
3 and iodinated DBFs. Tighter restrictions on IDS in effluent from POTWs and CWTs have led to a
4 reduction in in-stream bromide concentrations. Advanced treatment processes at CWTs such as
5 reverse osmosis, distillation, evaporation, or crystallization can reduce chloride, bromide, and
6 iodide in surface waters. Strategies such as reducing effluent concentrations, discharging during
7 higher stream flow periods, and utilizing a pulsing or intermittent discharge could also reduce the
8 potential impact of elevated TDS on drinking water treatment plants.
8.6.2. Radionuclides
9 Potential impacts on drinking water resources from technologically enhanced naturally occurring
10 radioactive material (TENORMs) associated with hydraulic fracturing waste water may arise from a
11 number of sources, including: treated wastewater that does not have adequately reduced
12 radionuelide concentrations, accumulation of radionuelides in surface water sediments
13 downstream of wastewater treatment plant discharge points, migration from soils that have
14 accumulated radionuclides from previous activities such as pits or land application, and inadequate
15 management of treatment plant solids that have accumulated radionuclides (such as filter cake).
16 In Pennsylvania between 2007 and 2010, TENORM-bearing produced wastewaters were sentto
17 POTWs, which are generally not required to monitor for radioactivity (Resnikoff etal., 2010).
18 Although the practice of management of Marcellus waters via POTWs has declined, there is still
19 potential for input of radionuclides to surface waters via discharge of CWT effluents either directly
20 to surface waters or indirectly through discharge to POTWs.
21 Data regarding TENORM content in oil and gas wastes that are treated and discharged to surface
22 waters are limited. However, a recent study by the Pennsylvania Department of Environmental
23 Protection (PA DEP) (PADEP. 2015b) provides information that helps fill this data gap. The study
24 began in 2013 and examined radionuclide (radium-226, radium-228, K-40, gross alpha, gross beta)
25 levels at 29 wastewater plants in Pennsylvania that cover a range of both sources and treatment
26 plant types, including POTWs, CWTs that treat oil and gas wastewaters and can discharge to surface
27 water or a POTW, and zero liquid discharge facilities treating oil and gas wastewater. Four of the 10
28 discharging CWTs sampled during the study discharged to surface water under a National Pollution
29 Discharge Elimination System (NDPES) permit, and the others discharged to POTWs. Six of the
30 POTWs in the study received effluent from a CWT along with municipal wastewater. The CWTs in
31 the study are not described as receiving exclusively Marcellus wastewater, but the study itself was
32 motivated by concerns over an increase in radionuclides in oil and gas wastes observed during the
33 expansion of Marcellus Shale production.
34 The POTWs receiving influent from CWTs treating oil and gas wastewater (along with municipal
35 wastewater influent) had average effluent radium-226 concentrations of 103 pCi/L (unfiltered) and
36 129 pCi/L (filtered) (filtration is used to remove very fine particulates from the water). Those
37 POTWs not receiving influent from CWTs treating oil and gas wastewater effluent had higher
38 average radium-226 values in unfiltered samples (145 pCi/L) and lower values for filtered samples
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1 (47 pCi/L). For perspective, the maximum contaminant level (MCL) for radium-226 plus radium-
2 228 is 5 pCi/L. For reference, radium-226 in river water generally ranges from 0.014 pCi/L to 0.54
3 pCi/L (0.5 to 20 mBq/L) flAEA. 20141 The results of the POTW sampling are inconclusive as to
4 whether the effluents from POTWs receiving CWT-treated oil and gas wastewater are routinely
5 higher than the effluents from those without this type of influent
6 For the CWTs in the PA DEP study, average radium-226 content in the effluents was an order of
7 magnitude higher than in effluents from the POTWs (1,840 pCi/L unfiltered, 2,100 pCi/L, filtered).
8 The effluent averages were similar to averages for the influent concentrations, although median
9 concentrations in the effluents were much lower than in the influents. Effluent from zero-discharge
10 facilities averaged 2,610 pCi/L radium-226 and 295 pCi/L radium-228, although these effluents
11 would most likely be reused as fracturing fluid (PADEP, 2015b]. The authors do note a potential for
12 environmental effects from spills of influent or effluent from zero-discharge facilities.
13 Warner etal. (2013a] noted that if the activities of radium-226 and radium-228 inMarcellus brine
14 influent at the CWT they studied are similar to those reported by other researchers (Rowan etal..
15 2011). then the CWT achieved a 1,000-fold reduction in radium content via a process of radium
16 coprecipitation with barium sulfate. The detection of radium in effluents from this CWT (mean
17 values of 4 pCi/L of radium-226 and 2 pCi/L of radium-288) even with what may be high treatment
18 removal efficiency underscores the fact that effluent concentrations depend not only upon the
19 treatment processes used but also the influent concentration.
2 0 An additional concern related to evaluation of radionuclide concentrations in wastewater is that the
21 high TDS content of hydraulic fracturing wastewater can result in poor recovery of chemical
2 2 constituents when using wet chemical techniques, leading to underestimations of constituent
23 concentrations. In particular, recovery for radium may be as low as <1% (Nelson etal., 2014].
24 Underestimation of radium content may lead to failure in identifying an impact or potential impact
25 on drinking water resources.
26 In addition to concerns over of the potential for TENORM in discharges to surface waters, there are
2 7 may be a legacy of accumulation of radionuclides in surface water sediments. Studies of effluent,
2 8 stream water, and stream sediment associated with a CWT in western Pennsylvania that has
29 treated both conventional and unconventional oil and gas wastewaters indicate that radium-226
30 levels in stream sediment samples at the point of discharge are approximately 200 times greater
31 than upstream and background sediments. This indicates the potential for accumulation of
32 contaminants in localized areas of wastewater discharge facilities (Warner etal.. 2013a]. Although
33 the CWT in question also accepted conventional oil and gas wastewater, Warner etal. (2013a]
34 observed thatthe radium-228/radium-226 ratio in the river sediments near the discharge (0.22-
35 0.27) is consistent with ratios in Marcellus wastewater. The authors interpret this as an indication
36 that the radium accumulated in the sediments originated from the discharge of treated
37 unconventional oil and gas wastewater. Another study, however, did not find elevated levels of
38 alkali earth metals (including radium) in sediments just downstream of the discharge points of five
39 POTWs that had previously treated Marcellus wastewater (Skalaketal., 2014). Accumulation of
40 contaminants in sediment may be dependent on treatment processes and their removal rates for
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1 various constituents as well as stream chemistry and hydrologic characteristics. Contamination
2 with radium-226 would be potentially be long lived; the half-life of radium-226 is approximately
3 1,600 years, while the half-life of radium-228 is 5.76 years.
4 The recent PA DEP study [PADEP. 2015b] found thatthe radium-226 content in sediments near the
5 discharge points for POTWs receiving treated oil and gas effluent from CWTs (along with their
6 municipal wastewater influent) exceeds typical background soil levels of approximately 1 to 2
7 pCi/g of radium-226 and radium-228. The authors conclude that wastewater effluent is the most
8 likely source for the radium in these samples. Results indicate an average of 9.00 pCi/g radium-226
9 and 3.52 pCi/g radium-228 in sediments near outfalls of POTWs. Sediments at 4 CWTs receiving oil
10 and gas wastewater and that discharge to surface water have much higher average concentrations
11 of 84.2 pCi/g for radium-226 and 19.8 pCi/g for radium-228. However, the concentrations of
12 radium in the sediments does not correlate with concentrations of radium in the effluents
13 suggesting that sorption over time affects the concentration of radium in the sediments [PADEP,
14 2015b].
15 The association of radium with sediments near discharge points is attributed to adsorption of
16 radium to the sediments, a process governed by factors such as the salinity of the water and
17 sediment characteristics. In particular, radium has a high affinity for iron and manganese
18 (hydr)oxides in sediment. Increased salinity promotes desorption of radium from sediments, while
19 lower salinity promotes adsorption, with radium adsorbing particularly strongly to sediments high
20 in iron and manganese (hydro)oxides [Porcellietal.. 2014: Gonneea et al.. 2008). Warner et al.
21 [2013a] speculate that the discharge of saline CWT effluent into less saline stream water facilitates
22 sorption of radium onto streambed sediments. The long-term fate of radium sorbed to sediments
23 depends upon changes in water salinity and the sediment properties, including any redox processes
24 that may affect iron and manganese minerals in the sediments.
25 Other solids may contain radionuclides; filter cake samples from treatment at POTWs were found
26 by PADEP [2015b] to have radium contents greater than typical soil concentrations, and they
27 exhibited a large variation. Filter cake from CWTs had radium concentrations higher than in POTW
28 filter cake. The authors conclude that although the risk to workers and the public from handling
29 and temporary storage of these materials is minimal, there may be environmental risks from spills
30 or long term disposal. There could be impacts on surface waters through spills or effects on ground
31 waters from landfill leachate.
3 2 Radionuclide accumulation in CWTs or POTWs may continue to affect the plant even after
33 discontinuing treatment of high radionuclide wastewater. Radium can adsorb onto scales in pipes
34 and tanks and will also co-precipitate calcium, barium, and strontium in sulfate minerals [USGS,
35 2014e]. Pipe scale in oil and gas production facilities can have radium concentrations as high as
36 154,000 pCi/g, although concentrations of less than 13,500 pCi/g are more common [Schubert et
37 al.. 2014]. A similar issue, the potential for accumulation and possible release of radionuclides and
38 other trace inorganic constituents in water distribution systems has gained attention, with the
39 potential for drinking water concentrations to exceed drinking water standards [Water Research
40 Foundation, 2010]. Scale eventually removed from pipes or other equipment may end up in
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1 landfills and then leach into groundwater or run off to a surface water body [USGS, 2013c].
2 Although barium sulfate phases are relatively insoluble, one study demonstrates that barium
3 sulfate scales that were buried in soil could be reduced by microbially mediated processes, allowing
4 release of co-precipitated elements such as radium due to leaching by rainwater [Swannetal.,
5 2004]. Monitoring would be needed in order to ascertain the potential for accumulation and release
6 of radionuclides from systems that have treated or continue to treat hydraulic fracturing
7 wastewaters with elevated TENORM concentrations.
8 Accumulation of radionuclides (potassium, thorium, bismuth, radium, and lead) has been evaluated
9 in two pits in Texas that have stored fluids associated with hydraulic fracturing [Rich and Crosby,
10 2013]. Gamma radiation in these pits has been found to vary from 8 to 23 pCi/g, with beta radiation
11 varying from 6 to 1329 pCi/g [Rich and Crosby, 2013]. Although the study sample size was small,
12 the results suggest that radionuclides associated with sediments from some reserve pits could have
13 potential impacts on surface waters or ground waters. This could happen through migration of
14 affected sediments or soils to surface waters or through leaching to ground water.
15 Salt and radionuclide accumulation can occur near road spreading sites; one study in Pennsylvania
16 found a 20% increase in radium concentrations in soils near roads where wastewaters from
17 conventional operations had been spread for de-icing [Skalak et al.. 2014]. Accumulation of
18 radionuclides in soils near roads presents a vehicle for potential impacts on drinking water
19 resources. The extent to which hydraulic fracturing wastewater contributes to this depends upon
20 state-level regulations regarding whether hydraulic fracturing wastewater can be used for road
21 spreading.
22 Effluents and receiving waters can be monitored for radionuclides. Research suggests that radium-
23 226 and radium-228 are the predominant radionuclides in Marcellus Shale wastewater, and they
24 account for most of the gross alpha and gross beta activity in the waters studied [Rowanetal.,
25 2011]. Gross alpha and gross beta measurement may therefore serve as an effective screening
26 mechanism for overall radionuclide concentrations in hydraulic fracturing wastewater. This in turn
27 can help in evaluating management strategies. Portable gamma spectrometers allow rapid
28 screening of wastewater effluents. Sediments may also be measured for radionuclide
29 concentrations at discharge points.
8.6.3. Metals
3 0 Given the presence in hydraulic fracturing wastewaters of some heavy metals, as well as barium
31 and strontium concentrations that can reach hundreds or even thousands of mg/L (see Table 7-10],
32 surface waters maybe impacted if discharges from CTWs or POTWs indirectly receiving oil and gas
33 wastewater via CWTs are not managed appropriately. Spills may also affect surface waters.
34 Common treatment processes, such as coagulation, are effective at removing many metals (see
35 Section 8.5.2.4]. A request by the EPA for effluent sampling from seven facilities in Pennsylvania
36 treating oil and gas wastewaters revealed low to modest concentrations of copper (0-50 ug/L], zinc
37 (14-256 u.g/L], and nickel (8-22 u,g/L] (U.S. EPA. 2015d. e]. However, metals such as barium and
38 strontium have been found to range from low to elevated in some CWT effluents. For the year 2011,
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1 for example, effluent from a Pennsylvania CWT had average barium levels ranging from 9 to 98
2 mg/L [PADEP. 2015a]. That facility was operating with a barium removal stage and was treating
3 both conventional and hydraulic fracturing wastewater, although effluent concentrations dropped
4 after May, 2011. The facility is scheduled to upgrade its TDS removal capabilities.
5 Data collected by the EPA between October 2011 and February 2013 at seven Pennsylvania
6 facilities indicate effluent barium concentrations ranging from 0.35 to 25 mg/L (median of 3.5 mg/L
7 and average of 6.7 mg/L). Strontium concentrations ranged from 0.36 to 546 mg/L (median of 297
8 mg/L and mean of 236 mg/L (U.S. EPA. 2015e). A December 2010 effluent sampling effort in at a
9 discharging CWT in Pennsylvania reported average barium and strontium concentrations of 27
10 mg/L and nearly 3,000 mg/L, respectively (eight samples from one plant) (Volz etal., 2011). The
11 facility treats conventional oil and gas waste waters, and it also received Marcellus wastewater until
12 September, 2011.
13 Limited data are available on metal concentrations in wastewater and treated effluents that are
14 directly discharged; additional information would be needed to assess whether there will be
15 downstream effects on drinking water utilities. NPDES discharge permits, which restrict TDS
16 discharge concentrations, will likely reduce metal effluent concentrations due to the additional
17 treatment necessary to minimize TDS.
8.6.4. Volatile Organic Compounds
18 Benzene is a common constituent in hydraulic fracturing wastewater, and it is of concern due to
19 recognized human health effects. A wide range of concentrations of BTEX compounds occurs in
20 wastewater from the Barnett and Marcellus shales. Natural gas formations generally produce more
21 BTEX than oil formations (Veil etal.. 2004). Generally, lower concentrations of BTEX occur in
22 wastewater from coalbed methane (CBM) production (see Appendix Table E-9). Processes such as
23 aeration or dissolved air flotation can remove volatile organic compounds (VOCs) during treatment,
24 but if treatment is not adequate, the VOCs may reach water resources. The average concentration of
25 benzene in a December 2010 sampling effort was 12 |ig/L in the discharge of a Pennsylvania CWT
26 (Volz etal.. 2011). The facility was receiving wastewater from both conventional and
27 unconventional operations at that time. Ferrar etal. (2013) measured mean concentrations of
28 benzene, toluene, ethylbenzene, and xylene in effluents from the same facility, and mean
29 concentrations among the four compounds ranged from about 2 to 46 [ig/L. Concentrations were
30 lower for samples taken after May 19, 2011 than before, and the effect was considered statistically
31 significant. The treatment processes at this facility do not include aeration.
3 2 Leakage from pits or spills creates another potential route of entry to drinking water resources.
33 VOCs have been measured in groundwater near the Duncan Oil Field in New Mexico, downgradient
34 of an unlined pit storing oil and gas wastewater (Sumi, 2004: Eiceman, 1986). VOCs and oil were
35 also found in groundwater about 213 feet (65m) downgradient from an unlined pit in Oklahoma
36 (Kharakaetal.. 2002).
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8.6.5. Semi-Volatile Organic Compounds
1 Little is known about the fate of the SVOC, 2-butoxyethanol (2-BE) (an antifoaming and anti-
2 corrosion agent used in slick-water) [Volzetal.. 2011] or its potential impact on surface waters,
3 drinking water resources, or drinking water systems. This compound is very soluble in water and is
4 subject to bio degradation, with a half-life estimation of 1-4 weeks in the environment [Wess etal.,
5 1998]. The EPA has not classified 2-BE (or other glycol ethers] for carcinogenicity. 2-BE was
6 detected in the discharge of a Pennsylvania CWT at concentrations of 59 mg/L (Volz etal.. 2011].
7 Ferrar etal. (2013] detected 2-BE in the effluents from a CWT in western Pennsylvania at average
8 concentrations of 34 - 45 mg/L; the latter value was measured when the CWT was receiving only
9 conventional oil and gas wastewater. Data are lacking on 2-BE concentrations in surface waters that
10 receive treated effluents from hydraulic fracturing wastewater treatment systems.
11 Polycyclic aromatic hydrocarbons are another common group of semi-volatile organic compounds
12 (SVOCs] in oil and gas wastewater. They have been detected in soils 164 feet (50 m] downgradient
13 of an unlined pit in New Mexico (Sumi. 2004: Eiceman. 1986]. PAHs were also found in birds in
14 wetlands fed by oil and gas wastewater discharges in Wyoming (Ramirez. 2002].
8.6.6. Oil and Grease
15 Oil and gas wastewater often contains oil and grease from the formation or from oil-based drilling
16 fluids. Typically, oil and grease are separated from the wastewater before discharge either by a heat
17 treatment or by allowing gravity separation followed by skimming. If these processes are
18 inefficient, oil and grease may be integrated with the discharge to surface waters. For example, in
19 some cases, oil and grease are allowed to separate in pits, and water is then withdrawn from the
20 lower part of the pit with a standpipe. If the oil layer is allowed to drop to the level of the standpipe
21 or if the water is agitated, oil and grease may be discharged along with the water. Oil and grease are
22 also often dispersed in wastewater in the form of small droplets that are 4 to 6 microns in diameter.
23 These droplets can be difficult to remove using typical oil/water separators (Veil etal.. 2004]. In a
24 study by the U.S. Fish and Wildlife Service regarding permitted oil and gas discharges between
25 1996 and 1999 from Wyoming oil fields, 15% of the 62 discharges to Wyoming wetlands reviewed
26 showed visible oil sheens in the receiving water and 10 of the sites sampled exceeded discharge
27 limits of 10 mg/L of oil and grease (Ramirez, 2002].
8.7. Synthesis
2 8 Hydraulic fracturing operations produce fluids during the flowback and production phases
29 (collectively called wastewater] of a production well, along with liquid and solid treatment
3 0 residuals from treatment processes. A variety of management strategies may be considered, with
31 cost frequently a driving factor. Available information suggests that Class IID wells regulated under
32 the Underground Injection Control (UIC] Program are the most frequently used wastewater
3 3 management practice, but reuse, discharge after treatment, and various other uses are also
34 employed.
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8.7.1. Summary of Findings
1 Hundreds of billions of gallons of waste water are generated annually in the United States by the oil
2 and gas industry, although national level estimates are difficult to reliably obtain. It is also difficult
3 to produce a nationwide estimate of the amount of wastewater that is attributable specifically to
4 hydraulic fracturing because some states do not specifically identify wastewater from hydraulic
5 fracturing operations in their available wastewater data.
6 The total amount of wastewater produced in an area corresponds generally to oil and gas
7 production and, therefore, may increase if hydrocarbon production increases in a region.
8 Geographically, a large portion of oil and gas wastewater in the United States is reported to be
9 generated in the western part of the country, including contributions from both conventional and
10 unconventional resources. For some states, estimates of hydraulic fracturing wastewater volumes
11 can be made using publicly available production or waste data. Annual estimates compiled in this
12 way range from hundreds of millions to billions of gallons of wastewater generated per state per
13 year. Direct comparisons among these state data are problematic, however, because of a great deal
14 of variability in state data collection, including differences in the years for which data are available,
15 and challenges in definitively identifying wells that have been hydraulically fractured (to
16 distinguish hydraulic fracturing wastewater from that generated from wells that are not
17 hydraulically fractured). Within a given state, however, estimated volumes in areas where
18 hydraulic fracturing is practiced extensively have generally increased over the last several years,
19 along with numbers of wells contributing to total wastewater volumes. For example, the data made
2 0 available by PA DEP illustrate that the total volume of wastewater generated correlates generally
21 with a significant increase in volume of hydrocarbon production and with the number of
22 production wells. As hydraulic fracturing activities increase and the number of wells increases, the
2 3 amount of hydraulic fracturing wastewater generated is likely to increase.
8.7.1.1. Wastewater Management Practices
24 Hydraulic fracturing wastewater is managed in a variety of ways, including disposal through Class
25 IID wells; minimal treatment and reuse in subsequent fracturing operations; more complete
26 treatment followed by discharge, disposal, or reuse; evaporation; and other uses such as irrigation
2 7 (when the wastewater quality is adequate). Unauthorized discharges of hydraulic fracturing
2 8 waste waters have been documented; such discharges could potentially impact drinking water
29 resources, but estimates of the frequency of occurrence cannot be developed with the available
30 data.
31 As of 2015, available information suggests that wastewater management practices involve
32 extensive use of Class II wells to manage wastewater from most of the major unconventional plays
33 in the United States, with the notable exception of the Marcellus Shale region in Pennsylvania. More
34 than 98% of wastewater in the oil and gas industry is estimated to be injected into Class II wells
35 annually (including wells for enhanced oil recovery and disposal) (Clark and Veil. 2009). Based on
36 data compiled from 2012 and 2014, there are about 25,000 Class IID wells in the United States (U.S.
37 EPA. 2015q). In particular, large numbers of active injection wells are found in Texas (7,876 or
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1 29%), Kansas (5,516 or 20%), Oklahoma (4,622 or 17%), Louisiana (2,448 or 9%), and Illinois
2 (1,054 or 4%).
3 Use of Class IID wells is likely driven by the availability of Class IID wells within reasonable
4 transportation distance and the cost of transporting (and injecting) the wastewaters. In the oil and
5 gas industry, Class IID wells have generally been the most economically favorable wastewater
6 management practice (U.S. GAP, 2012). In Pennsylvania, there are only nine Class IID wells as of
7 February 2015, and a significant growth of gas production using hydraulic fracturing in the
8 Marcellus is generating increasing amounts of wastewater. Treatment and reuse are becoming
9 increasingly popular in the Marcellus Shale region and are in more widespread use in comparison
10 to other oil and gas producing parts of the country.
11 Reuse of hydraulic fracturing wastewater to formulate fracturing fluid in subsequent hydraulic
12 fracturing jobs varies considerably on a national level, and reliable estimates are not available for
13 all areas. As of 2014-2015, the greatest amount of reuse occurs in Pennsylvania, where the scarcity
14 of Class IID wells to receive Marcellus wastewater drives this practice. Recent estimates of
15 wastewater reuse in Pennsylvania range as high as 90% or more. Waste disposal data from the PA
16 PEP (2015a) indicate that much of the reuse happens on-site. Operators also report some reuse of
17 wastewater in other regions such as the Haynesville Shale, the Fayetteville Shale, the Barnett Shale,
18 and the Eagle Ford Shale, although at much lower volume percentages (about 5 - 20%) compared
19 with practices in the Marcellus Shale region. Increased reuse and recycling of hydraulic fracturing
20 wastewaters has the added benefit of providing an additional water supply for hydraulic fracturing
21 fluid formulation in areas where water scarcity is a concern. If, however, hydraulic fracturing
22 activity slows, demand for wastewater for reuse will also decrease, and other forms of wastewater
23 management will be needed.
24 The decision to reuse/recycle depends upon several factors, including the volume and rate of
25 production of the wastewater and whether these are suitable for water needs for ongoing
26 fracturing activities in the area. The composition of the water, in particular the TSS and TDS
2 7 content, and whether the water quality can be accommodated in the fracturing practices in an area
2 8 can also influence reuse, including decisions about what type of pretreatment or treatment may be
29 needed to make reuse or recycling feasible.
30 Treatment facilities (either centralized waste treatment facilities (CWTs) or systems designed for
31 on-site use) can be permitted to treat oil and gas wastewaters. Treatment can be followed by
32 discharge to a surface water body or to a POTW, or the treated effluent may be used for reuse. Most
33 CWTs treating hydraulic fracturing wastewater are located in Pennsylvania (39 facilities), and a
34 number of CWTs (11) are located in Ohio. More are under construction or pending approval. Most
35 are "zero-discharge" and do not have the treatment capacity to reduce TDS; their effluent is reused
36 for hydraulic fracturing. Specialized on-site, mobile, or semi-mobile treatment facilities can be used
37 by operators to handle wastewater without the expense of long-distance transportation and can be
3 8 customized to produce an effluent that meets the water quality needs of the intended disposal or
39 reuse plans.
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1 Treatment of hydraulic fracturing wastewaters by publicly owned treatment works (POTWs) was
2 previously practiced in Pennsylvania. POTWs are not designed for the high TDS content of
3 Marcellus wastewaters, and stricter discharge limits for TDS in Pennsylvania, as well as a positive
4 response to a request from Pennsylvania DEP that operators stop sending Marcellus wastewater to
5 POTWs and some CWTs, led to the practice being discontinued in 2011. (Some POTWs in
6 Pennsylvania still accept oil and gas wastewaters from conventional operations, including
7 conventional wells that have undergone hydraulic fracturing.)
8 Management plans will necessarily need to change with time as hydraulic fracturing activities in a
9 region change. The volumes of wastewater also change during the life of a well. The chemical
10 composition of the wastewater changes during the transition from the flowback period and into the
11 production phase. In addition, the demand for reused water to support ongoing fracturing activities
12 will change. Taken in aggregate, these factors may influence costs and choices associated with
13 hydraulic fracturing wastewater management, especially if Class IID wells are limited in a particular
14 area for any reason.
8.7.1.2. Treatment and Discharge
15 One of the most frequently cited concerns regarding hydraulic fracturing wastewater, especially
16 from shale plays and tight sand plays, is the high TDS content, which poses challenges for
17 treatment, discharge, and reuse. Conventional treatment processes such as sedimentation, filtration
18 methods, flotation, chemical precipitation and ion exchange can remove constituents such as oil and
19 grease, major cations, metals, and TSS. Because these processes do not remove monovalent ions
20 (e.g., chloride, bromide, sodium), reducing TDS in these high-salinity wastewaters requires more
21 advanced processes such as reverse osmosis (RO), electrodialysis, and distillation methods.
22 Distillation methods appear to be the approach of choice for newer CWT facilities that are designed
23 to lower TDS. RO, while highly effective, does have limits to TDS concentrations (less than
24 approximately 40,000 mg/L) that it can treat (Shaffer etal.. 2013: Younos and Tulou. 2005).
25 Hydraulic fracturing wastewater discharged from treatment facilities without advanced TDS
26 removal processes has been shown to cause elevated TDS, bromide, and chloride levels in receiving
27 waters in Pennsylvania. Existing literature indicates that bromide and chloride are important
28 wastewater constituents with regard to potential burdens on downstream drinking water
29 treatment facilities. Bromide in particular is of concern due to the formation of disinfection by-
30 products (DBFs) during disinfection. Some types of DBFs are regulated under SDWA's Stage 1 and
31 Stage 2 DBF Rules, but a subset of DBFs, including a number of chlorinated, brominated,
32 nitrogenous, and iodinated DBFs, are not regulated. Brominated DBFs (and iodinated DBFs) are
33 more toxic than other species of DBFs. Modeling suggests that very small percentages of hydraulic
34 fracturing wastewater in a river used as a source for drinking water treatment plants may cause a
35 notable increase in DBF formation.
36 Radionuclides (in particular radium-226 and radium-228) in some hydraulic fracturing
37 wastewaters pose concerns for the quality of discharges if they are not adequately treated. Possible
38 elevated radionuclide content in treatment residuals is also a consideration. In Marcellus Shale gas
39 production wastewater, radium-226, radium-228, gross alpha, and gross beta are most cited as the
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1 radioactive constituents of concern, and concentrations can range up to thousands of pCi/L. Fewer
2 data exist on uranium content in wastewaters, and data are also limited on radionuclide
3 concentrations in wastewaters from other unconventional plays. A confounding issue in evaluating
4 radium concentrations is underestimation when using traditional wet chemical methods with high-
5 IDS waters. A variety of treatment processes can be used for removal of radium, ranging from
6 conventional methods such as chemical precipitation and filtration to more advanced and costly
7 techniques, such as reverse osmosis or distillation (including mechanical vapor recompression).
8 Whether the effluent from such treatment contains elevated radium, however, will depend upon
9 influent concentrations as well as treatment removal efficiency.
10 Other potential effects on drinking water resources may result from discharges or spills of
11 hydraulic fracturing wastewaters containing elevated concentrations of barium and other metals.
12 Again, the management strategy and treatment choices will affect the likelihood of such impacts.
8.7.2. Factors Affecting the Frequency or Severity of Impacts
13 On a regional scale, potential effects on drinking water resources from hydraulic fracturing
14 waste water will depend upon the mix of wastewater management strategies used, and potential
15 impacts may change through time if the quantity of hydraulic fracturing wastewater changes and
16 strategies to manage the wastewater change. For example, if use of Class IID wells becomes
17 restricted in parts of the country where they are currently commonly used, the emphasis may shift,
18 at least locally, from use of Class IID wells and towards the use of treatment and either discharge or
19 reuse. Although reuse delays the discharge of wastewater by directing it to ongoing fracturing
20 activities, reuse may ultimately concentrate constituents such as radionuelides (depending upon
21 the ratio of recycled to new water). If a stream of wastewater or portion of wastewater has been
22 used for more than one hydraulic fracturing event and is eventually intended for disposal, the
23 method of disposal will need to be appropriate for the quality of the wastewater.
24 Potential effects on drinking water resources from hydraulic fracturing wastewaters that undergo
25 treatment depend upon the quality and quantity of discharges to receiving waters (discharge could
26 occur directly after treatment at a CWT or indirectly after discharge to a POTW). Hydraulic
27 fracturing wastewater management can consider appropriate levels of treatment and blending so
28 that the resulting IDS content in a receiving water will not result in formation of DBFs during
29 subsequent drinking water treatment and will not impair biological treatment processes.
30 The volumes of discharges relative to the receiving water body size are important local factors to
31 consider in evaluating whether elevated concentrations can be anticipated at downstream drinking
32 water intakes. Small drinking water systems drawing water from smaller streams in affected areas
33 would likely face greater challenges in dealing with high bromide and chloride levels in source
34 waters. Furthermore, other potential impacts on surface water and shallow ground water may exist
35 due to spills of either untreated wastewater or effluent from zero-discharge CWTs, and there will be
36 site-specific factors such as distance to a water body or depth to the water table to consider (see
37 Chapter 5).
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1 Results from existing literature and recent PA DEP data suggest that cumulative impacts from
2 radionuclides may occur in sediments at or near discharge points from facilities that treat and
3 discharge oil and gas wastewater (or have done so in the past). There may be consequences for
4 downstream drinking water systems if the sediments are disturbed or entrained due to dredging or
5 flood events. Similarly, some organic constituents may not be removed during treatment, and
6 potential effects on receiving waters and sediments will depend upon the properties of the specific
7 constituents, their concentrations, and the treatment used.
8 The possibility of radionuclides affecting receiving waters and sediments will depend upon the
9 technologically enhanced naturally occurring radioactive material (TENORM) content of the
10 wastewater and the treatment processes used. Although radionuclide contamination at drinking
11 water intakes due to treated hydraulic fracturing fluid has not been detected, a recent PA DEP study
12 [PADEP. 2015b) has revealed radium in effluents from both CWTs handling oil and gas wastewater
13 and POTWs receiving effluent from such facilities. The concentrations in the CWT effluents were
14 considerably higher than in the POTW effluents. The site selection criteria for this study included
15 some Pennsylvania wastewater facilities whose influents include wastewater from unconventional
16 operations or where radioactivity was measured in the influent, sludges, or effluents (CWTs may
17 also receive conventional wastewater). In regions where unconventional plays are known to be
18 enriched in radionuclides, analysis of TENORMs in untreated hydraulic fracturing waste waters,
19 selection of appropriate treatment processes, and monitoring of TENORMs in treatment effluent
20 and receiving waters could help address potential impacts on drinking water resources. Gross alpha
21 and gross beta measurements or gamma spectroscopic analyses could be used as initial screening
22 methods for radionuclides. Enrichment of TENORMs in waste products from treatment processes
23 also requires appropriate management to reduce potential impacts.
24 Other management strategies such as irrigation, road spreading, and evaporation are less
25 frequently employed for hydraulic fracturing wastewaters. Irrigation or land application may have
26 potential effects on surface waters depending upon the constituents in the wastewater (e.g., salts
2 7 and radionuclides), the distance from the site of application to a receiving water, and whether
2 8 storm water management measures exist that mitigate runoff. Distance to the water table,
29 precipitation, and the hydrogeologic properties of the soil and sediment will influence whether
3 0 migration of these constituents results in contamination of shallow ground water.
8.7.3. Uncertainties
31 A full understanding of the practices being used for management of hydraulic fracturing
3 2 wastewaters is limited by a lack of available data in a number of areas. It is difficult to assemble a
33 complete, national- or regional-level picture of wastewater generation and management practices
34 because the tracking and availability of data vary from state to state. Although some states provide
35 well-organized and relatively thorough data, not all states make such information available, and it
3 6 can be difficult to identify wastewater volumes specifically associated with hydraulic fracturing
37 activity (as compared to all oil and gas production activities). Such data would be needed to place
3 8 hydraulic fracturing wastewater in the broader context of all oil and gas wastewaters. Data are also
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 generally difficult to locate for production volumes, chemical composition, masses, and
2 management and disposal strategies for residuals.
3 Among management practices, up-to-date information on the volumes of hydraulic fracturing
4 wastewaters disposed of via underground injection in different states are not uniformly available.
5 Without this information, it is difficult to assess whether disposal well capacity will become an
6 issue in areas where hydraulic fracturing activity is expected to increase.
7 Assessment of the potential effects of hydraulic fracturing on drinking water resources is also
8 limited by relatively few data on effluent quality from CWTs that receive oil and gas wastewaters
9 (including those associated with hydraulic fracturing) and POTWs that receive CWT effluents. If a
10 CWT can discharge to surface water (e.g., the CWT has a NPDES permit), some monitoring data may
11 be available that will provide information on effluent quality, but the list of monitored constituents
12 may be limited.
13 In evaluating the treatment effectiveness of full scale facilities, relatively few data exist on the
14 quality of both influents and effluents from treatment facilities, although some manufacturers of
15 patented CWT systems publicize information on treatment effectiveness. A better understanding of
16 the pollutant removal capabilities of facilities would be helped by influent and effluent sampling,
17 timed so that effluent samples are representative of influent samples to the degree possible. There
18 are limited analyses of influent and effluent samples for a wide range of constituents associated
19 with hydraulic fracturing fluids and wastewaters (e.g., major cations and anions, radionuclides,
20 metals, VOCs, SVOCs, diesel range organics (DROs), and total petroleum hydrocarbons (TPH)).
21 Analyses are needed in which the methods are appropriate for the TDS content of the sample.
22 Radium in particular needs to be analyzed using a method suitable for high-salt samples, otherwise
23 concentrations may be underestimated. Continued work towards ensuring that analytical methods
24 exist for the highly complex matrixes often encountered with oil and gas wastewater would provide
25 better certainty in the results of chemical analyses.
26 Monitoring of surface waters, even screening with a simple TDS proxy such as conductivity, would
27 be needed to help assess how often hydraulic fracturing activities (including spills or discharges of
28 wastewater) affect receiving waters; such data are lacking except for some studies in the Marcellus
29 Shale region. Existing data are also limited regarding legacy effects, such as accumulation of
30 contaminants in sediments at discharge points, soil accumulation due to application of de-icing
31 brines or salts from wastewater treatment, and handling of waste water treatment residuals.
8.7.4. Conclusions
32 Oil and gas operations in the United States generate billions of gallons of wastewater daily; this
3 3 includes wastewater associated with hydraulic fracturing activities, although what portion of this
34 oil and gas wastewater is attributable to hydraulic fracturing operations is difficult to estimate due
35 to lack of consistent data regarding wastewater volumes. Available information indicates that the
36 majority of this water is injected into Class IID wells regulated under the Underground Injection
37 Control (UIC) program, although in some areas of the country, wastewater is reused (either with
3 8 our without treatment) for new hydraulic fracturing jobs. In the Marcellus Shale region in
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 Pennsylvania, the majority of wastewater is currently reused. Wastewater may also be treated in a
2 CWT and discharged to a surface water body or to a POTW, or in certain settings, used for various
3 other uses (e.g., irrigation) if water quality allows. Impacts on drinking water resources may result
4 from inadequate treatment prior to discharge or spills. Particular constituents of concern in
5 wastewater from hydraulic fracturing, especially in the Marcellus Shale region, include bromide and
6 radionuclides. There is limited information regarding the influents and effluents from facilities that
7 treat wastewater from hydraulic fracturing operations.
8 Text Box 8-2. Research Questions Revisited.
9 What are the common treatment and disposal methods for hydraulic fracturing wastewater, and
10 where are these methods practiced?
11 • The majority of hydraulic fracturing wastewater in the United States is disposed of via underground
12 injection wells. As of 2014-2015, most states where hydraulic fracturing occurs have an adequate
13 number of Class IID injection wells regulated under the Underground Injection Control (UIC) program.
14 The Marcellus Shale region, especially the northeastern region, is an exception. Wastewater treatment for
15 reuse is increasing in the Marcellus shale region and may continue to increase in western shale plays as
16 the practice becomes encouraged and economically favorable.
17 How effective are conventional POTWs and commercial treatment systems in removing organic and
18 inorganic contaminants of concern in hydraulic fracturing wastewater?
19 • Publicly owned treatment works (POTWs) using basic treatment processes cannot effectively reduce
20 elevated total dissolved solids (TDS) concentrations in hydraulic fracturing wastewater. Centralized
21 waste treatment facilities (CWTs) with advanced treatment processes can remove TDS constituents with
22 removal efficiencies ranging from 97% to over 99% as demonstrated at facilities that use treatment
23 processes such as mechanical vapor recompression, distillation, and reverse osmosis (see Table 8-6).
24 Advanced treatment processes have been shown to remove certain contaminants found in hydraulic
25 fracturing wastewater (see Table 8-6). Indirect discharge, where wastewater is pretreated by a CWT and
26 sent to a POTW, may be an effective option for hydraulic fracturing wastewater treatment (with
27 restrictions on contaminant concentrations in the pretreated wastewater that is sent to a POTW). This
28 option would require careful planning to ensure that the pretreated wastewater blended with POTW
29 influent is of appropriate quality and quantity to prevent deleterious effects on biological processes in the
30 POTW or the pass-through of contaminants.
31 • Facilities that treat wastewater for reuse and employ only basic treatment are unable to remove all
32 contaminants in hydraulic fracturing wastewater. Depending on the water quality requirements for a
33 particular site, these lower quality treated waters may be of adequate quality for reuse on subsequent
34 hydraulic fracturing operations (and will be less costly). Some organic compounds (BTEX, some alcohols,
35 2-butoxyethanol) may not be removed by the processes employed in CWTs if they don't include specific
36 processes that target these compounds (e.g., distillation, advanced oxidation, adsorption).
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Hydraulic Fracturing Drinking Water Assessment Chapter 8 - Wastewater Treatment and Waste Disposal
1 What are the potential impacts on drinking water treatment facilities from surface water disposal of
2 treated hydraulic fracturing wastewater?
3 • Inadequate bromide and iodide removal from treated hydraulic fracturing wastewater has the greatest
4 potential to affect surface water quality and place a burden on downstream drinking water treatment
5 facilities that use chlorine-based disinfection due to the formation of DBFs. Radionuclides, metals, and
6 trace organic compounds in effluents from CWTs may also be of concern if present in treated wastewater
7 or if they accumulate in sediments downstream of discharge points. These constituents have reached
8 drinking water resources via some discharges, although sampling data for effluents and receiving waters
9 are limited. As of 2014-2015, there is no evidence that these contaminants have affected drinking water
10 facilities, but data are lacking for concentrations of these constituents at drinking water intakes in
11 regions with hydraulic fracturing.
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
Chapter 9
Identification and Hazard Evaluation of Chemicals
across the Hydraulic Fracturing Water Cycle
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
9. Identification and Hazard Evaluation of Chemicals
across the Hydraulic Fracturing Water Cycle
9.1. Introduction
1 Chapters 4 through 8 of this assessment each present a stage of the hydraulic fracturing water cycle
2 and the mechanisms by which activities in those stages produce potential impacts on drinking
3 water resources. In contrast, this chapter presents and integrates what is known about chemicals
4 across stages of the hydraulic fracturing water cycle (i.e., used in hydraulic fracturing fluids and
5 detected in hydraulic fracturing wastewater). The discussion is focused on available information
6 about (1] chronic toxicity values—specifically, the available noncancer oral reference values (RfVs)
7 and cancer oral slope factors (OSFs)—of chemicals that could occur in drinking water resources;
8 and (2) properties of chemicals that could affect their occurrence in drinking water resources (see
9 Chapters 5 and 7).l-2 To the extent that information was available to do so, knowledge of
10 toxicological and chemical properties was combined to illustrate an approach that may provide
11 preliminary insights about the relative hazard potential that chemicals could pose to drinking water
12 resources.
13 Risk assessment and risk management decisions will be informed by the scientific information on
14 the toxicity of chemicals in hydraulic fracturing fluid and wastewater, which recent authors note is
15 incomplete (Goldstein etal.. 2014). The U.S. House of Representatives' Committee on Energy and
16 Commerce Minority Staff released a report in 2Oil noting that more than 650 products (i.e.,
17 chemical mixtures) used in hydraulic fracturing contain 29 chemicals that are either known or
18 possible human carcinogens or are currently regulated under the Safe Drinking Water Act (House
19 of Representatives. 2011). However, that report did not characterize the potential toxicity of many
20 of the other compounds known to occur in hydraulic fracturing fluids or wastewater. More recently,
21 Kahrilas etal. (2015] reviewed the toxicity and physicochemical properties of biocides used in
22 hydraulic fracturing. Stringfellow et al. (2014] examined the toxicity and physicochemical
23 properties of several classes of chemicals that are reportedly used in hydraulic fracturing; however,
24 this study only reported acute toxicity (from lethal doses], which may differ from the effects of low-
25 dose, chronic exposure to these chemicals. Wattenberg et al. (In Press] assessed the acute and
26 chronic toxicity data that was available for 168 chemicals from the FracFocus database that had at
27 least 25 reports of use in North Dakota. The authors found that 113 of these chemicals had some
28 health hazard data available, but determined that there were significant data gaps, particularly with
29 regards to what is known about the potential chronic toxicity of these chemicals. Overall, available
1 A reference value (RfV) is an estimate of an exposure for a given duration to the human population (including
susceptible subgroups) that is likely to be without an appreciable risk of adverse health effects over a lifetime. RfV is a
generic term not specific to a given route of exposure. In the context of this chapter, the term RfV refers to reference
values for noncancer effects occurring via the oral route of exposure and for chronic durations, except where noted.
Source: IRIS Glossary (U.S. EPA.2011d).
2 An oral slope factor (OSF) is an upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a
lifetime oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per
mg/kg day, is generally reserved for use in the low dose region of the dose response relationship, that is, for exposures
corresponding to risks less than 1 in 100.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 information indicates that there may be hundreds of chemicals associated with the hydraulic
2 fracturing water cycle for which toxicological data is limited or unavailable.
3 Furthermore, the potential public health impact of hydraulic fracturing processes is not well
4 understood [Finkeletal.. 2013: Colbornetal.. 2011]. Potential public health implications are
5 highlighted in the recent studies by McKenzie etal. [2014] and Kassotis etal. [2014], but as of early
6 2015, there is a lack of published, peer-reviewed epidemiological or toxicological studies that have
7 examined health effects resulting from water contamination due to hydraulic fracturing. However,
8 numerous authors have noted that with the recent increase in hydraulic fracturing operations there
9 may be an increasing potential for significant public health and environmental impacts via ground
10 and surface water contamination [Goldstein etal., 2014: Finkeletal., 2013: Korfmacher etal., 2013:
11 Weinhold. 2012].
12 This chapter provides a compilation of the chemicals used or released during the fracturing
13 process, and information about their potential health effects. The data are presented in this chapter
14 as follows.
15 Section 9.2 discusses how ten information sources, including the EPA's analysis of the FracFocus
16 database [U.S. EPA. 2015a], were used to create a list of chemicals used in or detected in various
17 stages of the hydraulic fracturing water cycle. This chemical list was initially presented in the EPA's
18 2012 interim progress report [U.S. EPA, 2012f], and has been updated in this assessment with
19 additional chemicals from FracFocus. The consolidated chemical list includes chemicals that are
20 reportedly added to hydraulic fracturing fluids in the chemical mixing stage, as well as fracturing
21 fluid chemicals, formation chemicals, or their reaction products that may be carried in flowback or
22 produced water. Although over half of the chemicals cited on this list are listed in the EPA
23 FracFocus database, this chapter is not meant to be interpreted as a hazard evaluation of the
24 chemicals listed in the EPA FracFocus database alone.
25 Section 9.3 provides an overview of the methods that were used for gathering information on
26 toxicity and physicochemical properties for all chemicals that were identified in Section 9.2, and
2 7 outlines the number of chemicals that had available data on these properties. For toxicological data,
28 the primary focus is on peer-reviewed, selected chronic oral RfVs and OSFs. This section also
29 discusses additional potential sources of toxicity information: estimates of toxicity predicted using
30 Quantitative Structure Activity Relationship [QSAR] modeling, or toxicological information
31 available on the EPA's Aggregated Computational Toxicology Resource [ACToR] database. This
32 chapter is focused on potential human health hazards of chemicals for the oral route of exposure
33 (drinking water]; therefore, the toxicological properties and physicochemical ranking metrics
34 described herein (see below] do not necessarily apply to other routes of exposure, such as
35 inhalation or dermal exposure. In addition, this analysis is focused on individual chemicals rather
36 than mixtures of chemicals used as additives. Furthermore, the propensity for a chemical to pose a
37 physical hazard (e.g. the flammability and explosive ness of stray gas methane] are not considered
38 here.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 Many chemicals reported in hydraulic fracturing were identified as being of interest in previous
2 chapters of this report This includes the most frequently used chemicals in hydraulic fracturing
3 fluid (Chapter 5), the most and least mobile chemicals in hydraulic fracturing fluid (Chapter 5), and
4 inorganic chemicals and pesticides that may be detected in flowback and produced water (Chapter
5 7). The available selected chronic oral RfVs and OSFs for these chemicals are summarized in Section
6 9.4.
7 Section 9.5 describes the hazard identification and hazard evaluation of chemicals for which data
8 was available on toxicity, occurrence, and physicochemical properties. ^2 For hazard identification,
9 the selected chronic oral RfVs and OSFs and health effects for these chemicals are presented and
10 summarized. To illustrate one approach to integrate toxicity, occurrence and physicochemical
11 properties data to generate a hazard potential score, a multicriteria decision analysis (MCDA)
12 framework was developed. In this context, occurrence and physicochemical property data were
13 used as metrics to estimate the likelihood that a chemical could impact drinking water resources.
14 Chemicals considered in these hazard evaluations include a subset of chemicals from the FracFocus
15 database, as well as a subset of chemicals that have been detected in flowback and produced water.
16 In general, characterizing chemicals and their properties on a national scale is challenging and that
17 the use and occurrence of chemicals is likely to differ between geological basins and possibly on a
18 well-to-we 11 basis (see Chapters 5 and 7). Therefore, for the protection of public health at the
19 community level, chemical hazard evaluations may be most useful to conduct on a regional or site-
20 specific scale. This level of analysis is outside the scope of this report; however, the methods of
21 hazard evaluation presented here can also be applied on a regional or site-specific scale in order to
2 2 identify chemicals that may present the greatest potential human health hazard.
9.2. Identification of Chemicals Associated with the Hydraulic Fracturing Water
Cycle
23 As the initial step towards developing a hazard evaluation, the EPA compiled a list of chemicals that
24 are used in or released by hydraulic fracturing operations across the country (U.S. EPA, 2012f). Ten
25 sources of information (described in Appendix A) were used to develop this list This consolidated
26 list was used to compile two sublists: (1) a list of chemicals known to be used in hydraulic
27 fracturing fluids, and (2) a list of chemicals that are reported to have been detected in hydraulic
28 fracturing flowback and produced water. It is likely that, as industry practices change, chemicals
29 may be used or detected that are not included on these lists. In addition, those chemicals that are
30 considered proprietary and identified as confidential business information (CBI) by well operators
31 are not listed or considered.
1 Hazard identification is a process for determining if a chemical or a microbe can cause adverse health effects in humans
and what those effects might be. See Terms of Environment at:
http://iaspub.epa.gov/sor internet/registry/termreg/searchandretrieve/termsandacronyms/search.do.
2 Hazard evaluation is a component of risk assessment that involves gathering and evaluating data on the types of health
injuries or diseases (e.g., cancer) that may be produced by a chemical and on the conditions of exposure under which such
health effects are produced. See Terms of Environment at:
httD://iasDub.epa.gov/sor internet/registry/termreg/searchandretrieve/termsandacronvms/search.do.
This document is a draft for review purposes only and does not constitute Agency policy.
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1 In total, the EPA identified 1,173 chemicals as being used in hydraulic fracturing fluid and/or
2 detected in flowback and produced water. The complete list of chemicals and associated data is
3 available in Appendices A and B.:
9.2.1. Chemicals Used in Hydraulic Fracturing Fluids
4 Of the 1,173 total chemicals, the EPA identified 1,076 chemicals as being used in hydraulic
5 fracturing fluids. Of these, 692 chemicals were listed in the FracFocus database, and therefore had
6 information available in order to calculate their nationwide frequency of use [U.S. EPA, 2015a].2
7 Frequency of use for individual chemicals ranged from low (481 chemicals on the list were used in
8 less than 1% of wells nationwide) to very high (methanol was used in 73% of wells nationwide).
9 Furthermore, only 32 chemicals (excluding water, quartz, and sodium chloride) were reported in at
10 least 10% of the disclosures nationwide (see Section 5.4 and Table 5-2). As noted previously, the
11 FracFocus database does not list or consider those chemicals identified as CBI. The EPA determined
12 that approximately 70% of the disclosures in the FracFocus database contain at least one CBI
13 chemical, and for those disclosures, the average number of CBI chemicals per disclosure was five
14 (see Section 5.4, Text Box 5-3). Additionally, as noted previously, approximately 35% of FracFocus
15 ingredient records were not able to be assigned standardized chemical names. These ingredient
16 records were excluded from the EPA's analysis (see Section 5.10).
9.2.2. Chemicals Detected in Flowback and Produced Water
17 Of the 1,173 total chemicals, 134 were identified as having been detected in flowback or produced
18 water. Included among these chemicals are naturally occurring organic compounds, metals,
19 radionuclides, and pesticides. As reported in Chapter 7, concentration data in flowback or produced
20 water are available for 75 of these 134 chemicals (see Appendix E), including inorganic
21 contributors to salinity (Tables E-4 and E-5), metals (Tables E-6 and E-7), radioactive constituents
22 (Table E-8), and organic constituents (Tables E-9, E-10, and E-ll). For these chemicals with
23 concentration data, the measured concentrations spanned several orders of magnitude. For
24 instance, for organic chemicals in produced water from the Marcellus shale formation (Table E-10),
25 average or median measured concentrations ranged from 2.7 |ig/L for N-nitrosodiphenylamine to
26 400 |ig/L for carbon disulfide. According to the sources listed in Appendix A, 37 of the total 134
27 chemicals in flowback and produced water were also identified as being used in hydraulic
28 fracturing fluid.
9.3. Toxicological and Physicochemical Properties of Hydraulic Fracturing
Chemicals
29 Toxicological and physicochemical data were collected as available for each of the chemicals
30 identified in Appendix A. The criteria used to identify and select toxicity values, RfVs and OSFs
31 (Section 9.3.1), and the method used to generate physicochemical property data (Section 9.3.2) are
32 discussed below. A summary of the available data for these chemicals follows in Section 9.3.3. Other
1 The list of 1,173 chemicals was finalized as of this 2015 draft assessment. There may be chemicals present in flowback
and produced water that are not included on this list.
2 The FracFocus frequency of use data presented in this chapter is based on 35,957 well disclosures.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 possible sources of toxicological information, including QSAR-approaches and the EPA's ACToR
2 database, are discussed in Section 9.3.4.
9.3.1. Selection of Toxicity Values: Reference Values (RfVs) and Oral Slope Factors (OSFs)
3 Toxicity information spans a wide range with respect to extent, quality and reliability. Toxicological
4 data may include assessments from various sources including state, national, international, private
5 and academic organizations as well as toxicity information which has not been formalized into an
6 assessment and may be found in the scientific literature and databases including results from
7 guideline tests, high throughput screening assays, alternative assays, and QSAR models. The
8 sources of toxicity values - specifically, chronic oral RfVs and OSFs - selected for the purposes of
9 this chapter are based on criteria developed specifically for this report For many of the chemicals
10 used in hydraulic fracturing or found in flowback or produced water there may be relevant
11 information, including cancer and noncancer-related information, from one or more sources that
12 were not evaluated in this chapter.
13 The sources of RfVs and OSFs selected for the purposes of this chapter met the followingkey
14 criteria: 1) the body or organization generating or producing the peer-reviewed RfVs, peer-
15 reviewed OSFs, or peer-reviewed qualitative assessment must be a governmental or
16 intergovernmental body; 2) the data source must include peer-reviewed RfVs, peer-reviewed OSFs,
17 or peer reviewed qualitative assessments; 3) the RfVs, OSFs, or qualitative assessments must be
18 based on peer-reviewed scientific data; 4) the RfVs, OSFs, or qualitative assessments must be
19 focused on protection of the general public; and 5) the body generating the RfVs, OSFs, or
2 0 qualitative assessments must be free of conflicts of interest with respect to the chemicals for which
21 it derives reference values or qualitative assessments. More detail on these criteria for selection
2 2 and inclusion of data sources, as well as the full list of data sources that were considered for this
23 study, are available in Appendix G.
24 RfVs and OSFs available from the EPA IRIS, the EPA PPRTV program, ATSDR, and the EPA HHBP
25 program all met the criteria for selection and inclusion as a data source (see Table 9-1). An attempt
26 was made to identify and acquire RfVs and OSFs from all 50 states, but only the peer-reviewed state
27 RfVs and OSFs from California met the stringent selection criteria and were included because of the
28 state's extensive peer review process.1 One international source for RfVs, the World Health
29 Organization's (WHO) International Programme on Chemical Safety (IPCS) Concise International
30 Chemical Assessment Documents (CICAD), also met the selection criteria. The International Agency
31 for Research on Cancer (IARC) and U.S. National Toxicology Program (NTP) Report on Carcinogens
32 also met the criteria and were used as additional sources for qualitative cancer classifications.
Table 9-1. Sources of selected toxicityRfVs and OSFs.
Source
Website
1 State RfVs and OSFs are also publicly available from Alabama, Texas, Hawaii, and Florida, but they did not meet the
criteria for consideration as sources for RfVs and OSFs in this report. See Appendix G for details.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
Source
EPA Integrated Risk Information System (IRIS)
Human Health Benchmarks for Pesticides (HHBP)
EPA Provisional Peer-Reviewed Toxicity Value
(PPRTV) database
Agency for Toxic Substances and Disease Registry
(ATSDR) Minimum Risk Levels
State of California Toxicity Criteria Database
International Programme on Chemical Safety (I PCS)
Concise International Chemical Assessment
Documents (CICAD)
Website
http://cfpub.epa.gov/ncea/iris/index.cfm7fuseaction
=iris.showSubstanceList
http://iaspub.epa.gov/apex/pesti cides/f?p=HHBP:h
ome
http://hhpprtv.ornl.gov/index.html
http://www.atsdr.cdc.gov/toxprofiles/index.aspttbo
okmarkOS
http://www.oehha.org/tcdb/index.asp
http://www.who.int/ipcs/publications/cicad/en/
1 EPA generally applies federal RfVs and OSFs for use in human health risk assessments. Therefore,
2 for the purpose of hazard evaluation and making comparisons between chemicals in this chapter,
3 only federal chronic oral RfVs and OSFs from the EPA IRIS, the EPA PPRTV program, ATSDR, and
4 the EPA HHBP program were used. Furthermore, when a chemical had an RfV and/or OSF from
5 more than one federal source, a modification of the EPA Office of Solid Waste and Emergency
6 Response (OSWER) Directive 9285.7-53 tiered hierarchy of toxicity values was applied to
7 determine which value to use. A single RfV and/or OSF was selected from the sources in this order:
8 IRIS, HHBP, PPRTV, and ATSDR.1 The RfVs considered from these sources included noncancer
9 reference doses (RfDs) from the IRIS, PPRTV, and HHBP programs, and oral minimum risk levels
10 (MRLs) from ATSDR.2'3
11 Because there are relatively few OSFs available compared to RfVs, OSFs were excluded from
12 discussion in this chapter; however, all available OSFs are reported in Appendix G. The EPA
13 drinking water maximum contaminant levels (MCLs) were also excluded from this analysis because
14 they are treatment-based. MCLs are set as close to maximum containment level goal (MCLG) values
15 as feasible. However, MCL and MCLGs values are still reported in Appendix G for the sake of
16 completeness.
1 The OSWER hierarchy indicates that sources should be used in this order: IRIS, PPRTV, and then other values. In this
report, this hierarchy was followed, but HHBP values were used in lieu of an IRIS value for a few chemicals. See Appendix
G for details.
2ARfD is an estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human
population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a
lifetime. For the complete definition see Appendix G.
3 An MRL is an estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to
pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure
(inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as predictors
of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer.
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
9.3.2. Physicochemical Properties
1 As presented in Chapter 5, EPI Suite™ software was used to generate data on the physicochemical
2 properties of chemicals on the consolidated list EPI Suite™ provides an estimation of
3 physicochemical properties based upon chemical structure, and will additionally provide
4 empirically measured values for these properties when they are available for a given chemical. For
5 more details on the software and on the use of physicochemical properties for fate and transport
6 estimation, see Chapter 5.
9.3.3. Summary of Selected Toxicological and Physicochemical Property Data for Hydraulic
Fracturing Chemicals
7 Figure 9-1 summarizes the availability of selected RfVs and OSFs and physicochemical data for the
8 1,173 hydraulic fracturing chemicals identified by the EPA.
( If 1
Hydraulic
Occurrence
Fracturing
Chemical List
v y V y
/^ >
Toxicological &
Physiochemical
Data
v y
1,173 Chemicals Associated with Hydraulic Fracturing:
Summary of Available Data:
/- A
Used in
Hydraulic Fracturing
Fluid:
1,076 chemicals
V J
f ~\
Frequency of Use
(FracFocus):
692 chemicals
V J
(^ A
Detected in
Flowback
or Produced Water:
134 chemicals
V. J
f ~\
Measured Concentration
in Flowback or Produced
Water (Appendix E):
75 chemicals
V J
( Chronic Oral RfV or OSF:
RfV or OSF (all sources): 147 chemicals
Federal RfV or OSF : 126 chemicals
Federal RfV : 119 chemicals
I Federal OSF: 29 chemicals
f N
Physico-
chemical Data
(EPI Suite):
515 chemicals
V J
Summary of Data Gaps:
/" A
Hydraulic Fracturing Fluid:
Chemical list excludes
confidential business
information
V J
f A
Flowback/Produced
Water:
Few studies are available
V J
f ~\
Lacking Frequency of Use Data:
384 chemicals used in hydraulic fracturing fluids
V J
C ~\
Lacking Chronic
Oral RfV or OSF
(all sources):
1,026 chemicals
V J
f ~\
Lacking Physiochemical
Properties Data
(EPI Suite):
658 chemicals
V }
Figure 9-1. Overall representation of the selected RfVs and OSFs, occurrence data, and
physicochemical data available for the 1,173 hydraulic fracturing chemicals
identified by the EPA.
9 Of the 1,173 chemicals identified by the EPA, only 147 (13%) have federal, or state, or international
10 chronic oral RfVs and/or OSFs from sources listed in Table 9-1. Therefore, chronic RfVs and/or
11 OSFs from the selected sources are lacking for 87% of chemicals that the EPA has identified as
12 associated with hydraulic fracturing. All available chronic RfVs and OSFs from the sources listed in
13 Table 9-1 are tabulated in Appendix G. Chronic RfVs and OSFs for chemicals used in hydraulic
14 fracturing fluids are listed in Tables G-la through G-lc, and chronic RfVs and OSFs for chemicals
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 reported in hydraulic fracturing flowback and produced water are listed in Tables G-2a through G-
2 2c.
3 From the U.S. federal sources that were considered here, the availability of chronic RfVs and OSFs
4 can be summarized as follows. Of the 1,173 chemicals on the consolidated list, a total of
5 126 chemicals have federal chronic RfVs and/or OSFs. Of these 126 chemicals, 119 have federal
6 chronic RfVs, and 29 have federal OSFs (see Figure 9-1). 22 chemicals have both a federal chronic
7 RfV and a federal OSF, while 7 have a federal OSF only.
8 Overall, when chemicals in hydraulic fracturing fluid and chemicals in flowback are considered
9 separately, the availability of chronic RfVs and OSFs can be summarized as follows:
10 • For the 1,076 chemicals used in hydraulic fracturing fluid, chronic RfVs from all of the
11 selected federal, state, and international sources were available for 90 chemicals (8.4%).
12 From the federal sources alone, chronic RfVs were available for 73 (6.8%), and OSFs were
13 available for 15 (1.4%).
14 • For the 134 chemicals reported in flowback and produced water, chronic RfVs from all of
15 the selected federal, state, and international sources were available for 83 chemicals (62%).
16 From the federal sources alone, chronic RfVs were available for 70 chemicals (52%), and
17 OSFs were available for 20 (15%).
18 The IRIS database was the most abundant source of the federal chronic RfVs and OSFs. IRIS had
19 available RfDs for 77 of the total 1,173 chemicals, and OSFs for 27 chemicals. Of the other federal
20 data sources, the PPRTV database had RfDs for 33 chemicals, and OSFs for 2 chemicals; the HHBP
21 database had RfDs for 11 chemicals, butdid nothave available OSFs for any of the chemicals; and
22 the ATSDR database had chronic oral MRLs for 27 chemicals.
23 In addition to these chronic values, many of the chemicals also have less-than-chronic federal oral
24 RfVs. Subchronic or acute federal RfVs were identified for 91 chemicals on the consolidated list,
25 including 55 chemicals used in hydraulic fracturing fluid (Table G-ld), and 56 chemicals reported in
26 flowback or produced water (Table G-2d). There were 8 chemicals that had less-than-chronic RfVs
27 but lacked a chronic RfV. All of these less-than-chronic RfVs were found on the PPRTV or ATSDR
28 databases; the IRIS database did not have less-than-chronic RfVs for any of these chemicals. These
29 values are not discussed in this report, but are provided in Appendix G as supporting information.
30 From the total list of 1,173 chemicals associated with hydraulic fracturing, EPI Suite™ was able to
31 generate data on physicochemical properties for 515 (44%) of the chemicals (see Appendix A). The
32 remaining 658 chemicals lacked the structural information necessary to generate an estimate.
9.3.4. Additional Sources of Toxicity Information
33 Because the majority of chemicals identified in this report do not have RfVs and/or OSFs from the
34 selected sources, it is likely that risk assessors at the local and regional level may turn to alternative
35 sources of toxicity information. This section discusses other publicly accessible sources of
36 toxicological data that are lower on the continuum of quality and reliability in comparison to the
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 selected RfVs and OSFs described above. Because the quality of these data is unknown for most
2 chemicals, values from these data sources are not included in the hazard evaluation in this report.
9.3.4.1. Estimated Toxicity Using Quantitative Structure Activity Relationships (QSAR)
3 One potential source of toxicological information is QSAR software, which is able to provide
4 estimates or predictions of toxicity based on chemical structure. QSAR models for toxicity have
5 been used and evaluated in a number of previous studies published in the peer reviewed literature
6 [Ruppetal.,2010: Venkatapathy et al.. 2004: Moudgal etal.. 2003]. A key advantage to QSAR
7 models is that they are able to rapidly and inexpensively estimate toxicity values for chemicals.
8 Compared to toxicological studies involving animals or in vitro methods, which have monetary,
9 time, and ethical considerations associated with them, the QSAR method requires only information
10 on chemical structure in order to generate a toxicity estimation. These values may be of lower
11 quality and less reliable than values generated using traditional toxicological methods. However,
12 because they increase the available pool of toxicity information, QSAR estimates may potentially be
13 a useful resource for risk assessors that are faced with evaluating potential exposures to data-poor
14 chemicals.
9.3.4.2. Chemical Data Available from ACToR
15 An additional tool for obtaining toxicological information is the ACToR database.1 ACToR is a large
16 data warehouse developed by the EPA to gather and house large and disparate amounts of public
17 data on chemicals including chemical identity, structure, physicochemical properties, in vitro assay
18 results, and in vitro toxicology data [Judsonetal.. 2009]. ACToR contains data on over 500,000
19 chemicals from over 2,500 sources, covering many domains including hazard, exposure, risk
20 assessment, risk management, and use. Data in ACToR is organized on several levels of "assays" and
21 "assay categories". The information available in ACToR ranges from the federal RfVs and OSFs
22 discussed in Section 9.3.1, which have undergone extensive peer review, to other toxicity values
23 and study and test results that have undergone little to no peer review.
24 The ACToR database was searched for information related to the total list of 1,173 chemicals
25 associated with hydraulic fracturing.2 For the purposes of this chapter, the database was first
2 6 searched for all of the assays and assay categories that had data on these chemicals. This initial
2 7 search was then filtered to only include the assay categories that are most relevant to toxicity via
28 the oral route of exposure (drinking water]. These assay categories were assigned into the
29 following nine data classes: carcinogenicity, dose response values, drinking water criteria,
30 genotoxicity/mutagenicity, hazard identification, LOAEL/NOAEL, RfD, slope factor, and water
31 quality criteria. The type of data and examples of the data sources included in these data classes can
32 be found in the ACToR database documentation.
33 When all assays and assay categories were considered, it was found that all but 2 8 of the total 1,173
34 chemicals had available data on ACToR. When only the relevant assays and assay categories were
35 considered, 642 (55%] of the chemicals were found to have data on ACToR. The fraction of
1 The ACToR database is available at: http://actor.epa.gov.
2 The ACToR database was queried for the total list of 1,173 chemicals on April 1,2015.
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 chemicals that had at least one data point in each of the nine ACToR data classes is shown in Figure
2 9-2. As can be seen in Figure 9-2, about half of the chemicals had some information on water quality
3 criteria, while fewer chemicals had information on the other classes of data.
Fraction of Chemicals with Data by Class
Water Quality Criteria
Slope Factor
RfD
LOAEL/NOAEL
Hazard ID
Genotoxicity/Mutagenicity
Drinking Water Criteria
Dose Response Values
Carcinogenicity
i
0.0
I
0.4
I
0.8
0.2 0.4 0.6
Figure 9-2. Fraction of chemicals with at least one data point in each ACToR data class.
4 Focusing on the 1,026 chemicals that lacked a chronic RfV and/or OSF from the selected sources
5 described in Section 9.3.1, 497 (48%) of these chemicals had available data on ACToR. Because
6 ACToR has a significant amount of data on potential chemical hazards, including for some data-poor
7 chemicals, ACToR might help to fill data gaps in the ongoing effort to understand potential hazards
8 of hydraulic fracturing chemicals. Since the quality of the non-peer reviewed values is not known,
9 these data are not considered in the hazard evaluation.
9.4. Hazard Identification of Reported Hydraulic Fracturing Chemicals
10 This section focuses on chemicals that were identified as being of particular interest in previous
11 chapters of this report, or which otherwise may be of particular interest to risk assessors. Federal
12 RfVs are identified for these chemicals as available.
This document is a draft for review purposes only and does not constitute Agency policy.
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
9.4.1. Selection of Additional Chemicals for Hazard Identification
1 Four subsets of chemicals were identified as being of interest in Chapter 5 (Chemical Mixing) and
2 Chapter 7 (Flowback and Produced water):
3 1. Chapter 5: The most frequently used chemicals in hydraulic fracturing fluid, defined as
4 chemicals being reported to the FracFocus database in at least 10% of well disclosures [U.S.
5 EPA. 2015a).
6 2. Chapter 5: The top 20 most and leastmobile chemicals from the EPA's analysis of the
7 FracFocus database [U.S. EPA, 2015a), as determined based on the octanol-water partition
8 coefficient (Kow) from EPI Suite™.
9 3. Chapter 7: Inorganic chemicals that may be returned to the surface in flowback and
10 produced water. This includes metals, inorganic ions, and naturally occurring radioactive
11 material (NORM).
12 4. Pesticides occurring in flowback and produced water.
13 The hazard identification for these four subsets of chemicals is presented below.
9.4.2. Hazard Identification Results
9.4.2.1. Most Frequently Used Chemicals in Hydraulic Fracturing Fluid (FracFocus)
14 Chapter 5 listed 35 chemicals that are reported to the FracFocus database in at least 10% of well
15 disclosures nationwide (U.S. EPA. 2015a) (Table 5-2). For 32 of these chemicals (water, quartz, and
16 sodium chloride were excluded from this analysis), only 7 chemicals (22%) have a federal chronic
17 RfV, as shown in Table 9-2. None of these 32 chemicals have available OSFs for cancer. For this
18 subset of chemicals, methanol was reported to be the most frequently used chemical in the
19 FracFocus analysis, followed by hydrotreated light petroleum distillates and hydrochloric acid, all
20 of which were reported in greater than 60% of disclosures. Ethylene glycol, isopropanol, and
21 peroxydisulfuric acid-diammonium salt are the only 3 additional chemicals to have been used in
22 greater than 40% of disclosures.
Table 9-2. List of the most frequently used chemicals in hydraulic fracturing fluids, with their
respective federal chronic RfVs where available.
Chemicals are ordered in the table, from high to low, based on their frequency of use from FracFocus.
Includes all chemicals reported to FracFocus in at least 10% of well disclosures, excluding water,
quartz, and sodium chloride.
Chemical
Methanol
Distillates, petroleum, hydrotreated light
Hydrochloric acid
CASRN
67-56-1
64742-47-8
7647-01-0
RfV
Chronic RfD
(mg/kg-day)
2
-
-
Source
IRIS
-
-
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
Chemical
Ethylene glycol
Isopropanol
Peroxydisulfuric acid, diammonium salt
Guar gum
Sodium hydroxide
Propargyl alcohol
Glutaraldehyde
Ethanol
Potassium hydroxide
Acetic acid
Citric acid
2-Butoxyethanol
Solvent naphtha, petroleum, heavy arom.
Naphthalene
2,2-Dibromo-3-nitrilopropionamide
Choline chloride
Phenolic resin
Methenamine
Carbonic acid, dipotassium salt
1,2,4-Trimethylbenzene
Quaternary ammonium compounds, benzyl-C12-
16-alkyldimethyl, chlorides
Poly(oxy-l,2-ethanediyl)-nonylphenyl-hydroxy
(mixture)
Formic acid
Sodium chlorite
Nonyl phenol ethoxylate
Tetrakis(hydroxymethyl)phosphoniumsulfate
Polyethylene glycol
Ammonium chloride
Sodium persulfate
CASRN
107-21-1
67-63-0
7727-54-0
9000-30-0
1310-73-2
107-19-7
111-30-8
64-17-5
1310-58-3
64-19-7
77-92-9
111-76-2
64742-94-5
91-20-3
10222-01-2
67-48-1
9003-35-4
100-97-0
584-08-7
95-63-6
68424-85-1
127087-87-0
64-18-6
7758-19-2
9016-45-9
55566-30-8
25322-68-3
12125-02-9
7775-27-1
RfV
Chronic RfD
(mg/kg-day)
2
-
-
-
-
0.002
-
-
-
-
-
0.1
-
0.02
-
-
-
-
-
-
-
-
0.9
0.03
-
-
-
-
-
Source
IRIS
-
-
-
IRIS
-
-
-
-
-
IRIS
-
IRIS
-
-
-
-
-
-
-
-
PPRTV
IRIS
-
-
-
-
-
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
9.4.2.2. Most and Least Mobile Chemicals Used in Hydraulic Fracturing Fluid (FracFocus)
1 Chapter 5 lists the 20 most mobile chemicals (Table 5-7) and 20 least mobile chemicals (Table 5-8)
2 from the EPA's analysis of the FracFocus database (U.S. EPA. 2015a). For these lists, mobility was
3 determined based on Kow. For the 20 most mobile chemicals, no federal chronic RfVs or OSFs were
4 available (see Table 9-3). Similarly, for the 20 least mobile chemicals, only one chemical—di(2-
5 ethylhexyl) phthalate—had a federal chronic RfV available (see Table 9-4).
Table 9-3. List of the 20 most mobile chemicals used in hydraulic fracturing fluid, with their
respective federal chronic RfVs where available.
Chemicals are ordered in the table by lowest estimated log Kow. None of these chemicals had federal
chronic RfVs available.
Chemical
1,2-Ethanediaminium, N,N'-bis[2-[bis(2-
hydroxyethyl)methylammonio] ethyl] -N,N'-
bis(2-hydroxyethyl)-N,N'-dimethyl-,
tetrachloride
Phosphonic acid, [[(phosphonomethyl)imino]
bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-
Phosphonic acid, [[(phosphonomethyl)imino]
bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-, sodium salt
Phosphonic acid, [[(phosphonomethyl)imino]
bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-, ammonium salt (l:x)
Phosphonic acid, (((2-[(2-
hydroxyethyl) (phosphono
methyl) a m i no) ethyl) imino] bis
(methylene))bis-, compel, with 2-aminoethanol
2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-
methylethanaminium chloride
N- (3 -Chloroallyl) hexaminium chloride
3,5,7-Triazatricyclo(3.3.1.1(superscript
3,7))decane, l-(3-chloro-2-propenyl)-,
chloride, (Z)-
(2,3-dihydroxypropyl)trimethylammonium
chloride
Phosphonic acid, [[(phosphonomethyl) imino]
bis[6,l-
hexanediylnitrilobis(methylene)]]tetrakis-
CASRN
138879-94-4
15827-60-8
22042-96-2
70714-66-8
129828-36-0
7006-59-9
4080-31-3
51229-78-8
34004-36-9
34690-00-1
Log Kow
(unitless)
-23.19
-9.72
-9.72
-9.72
-6.73
-6.7
-5.92
-5.92
-5.8
-5.79
RfV
Chronic RfD
(mg/kg-day)
-
-
-
-
-
-
-
-
-
-
Source
--
--
--
--
--
--
--
--
--
--
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
Chemical
[Nitrilotris(methylene)]tris-phosphonicacid
pentasodium salt
Aminotrimethylene phosphonic acid
Choline chloride
Choline bicarbonate
alpha-Lactose monohydrate
Lactose
Tetrakis(hydroxymethyl)phosphoniumsulfate
Disodium ethylenediaminediacetate
Nitrilotriacetamide
l,3,5-Triazine-l,3,5(2H,4H,6H)-triethanol
CASRN
2235-43-0
6419-19-8
67-48-1
78-73-9
5989-81-1
63-42-3
55566-30-8
38011-25-5
4862-18-4
4719-04-4
Log Kow
(unitless)
-5.45
-5.45
-5.16
-5.16
-5.12
-5.12
-5.03
-4.76
-4.75
-4.67
RfV
Chronic RfD
(mg/kg-day)
-
-
-
-
-
-
-
-
-
-
Source
--
--
--
--
--
--
--
--
--
--
Table 9-4. List of the 20 least mobile chemicals used in hydraulic fracturing fluid, with their
respective federal chronic RfVs where available.
Chemicals are ordered in the table by highest estimated log Kow.
Chemical
CASRN
Log Kow
(unitless)
RfV
Chronic RfD
(mg/kg-day)
Source
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Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
Chemical
Sorbitan, tri-(9Z)-9-octadecenoate
Fatty acids, C18-unsatd., dimers
Sorbitan sesquioleate
Tributyltetradecylphosphonium
chloride
Sodium bis(tridecyl)
sulfobutanedioate
1-Eicosene
D&C Red 28
C.I. Solvent Red 26
1-Octadecene
Alkenes, C>10 .alpha.-
Dioctyl phthalate
Benzene, C10-16-alkyl derivs.
Di(2-ethylhexyl) phthalate
1-Octadecanamine, N,N-dimethyl-
N,N-dimethyloctadecylamine
hydrochloride
Butyryl trihexyl citrate
1-Hexadecene
Benzo (g,h,i) perylene
Dodecylbenzene
Isopropanolamine dodecylbenzene
CASRN
26266-58-0
61788-89-4
8007-43-0
81741-28-8
2673-22-5
3452-07-1
18472-87-2
4477-79-6
112-88-9
64743-02-8
117-84-0
68648-87-3
117-81-7
124-28-7
1613-17-8
82469-79-2
629-73-2
191-24-2
123-01-3
42504-46-1
Log Kow
(unitless)
22.56
14.6
14.32
11.22
11.15
10.03
9.62
9.27
9.04
8.55
8.54
8.43
8.39
8.39
8.39
8.21
8.06
7.98
7.94
7.94
RfV
Chronic RfD
(mg/kg-day)
-
-
-
-
-
-
-
-
-
-
-
-
0.02
-
-
-
-
-
-
-
Source
-
-
-
-
-
-
-
-
-
-
-
-
IRIS
-
-
-
-
-
-
-
9.4.2.3. Flowback and Produced Water: Inorganics and NORM
1 In addition to a number of volatile and semi-volatile organic compounds presented below, Chapter
2 7 also discusses the appearance of inorganic constituents such as metals, inorganic ions, and
3 naturally occurring radioactive material (NORM) in flowback and produced water. A number of
4 metals detected in flowback and produced water that appear on the EPA's consolidated list and are
5 noted in Chapter 7 have federal RfVs and/or OSFs listed in Appendix G (Table G-2). These metals
6 and inorganic ions include: iron, boron, chromium, zinc, arsenic, manganese, cadmium, and
7 strontium. These metals have oral RfVs based on a number of health effects including:
8 neurotoxicity, developmental and liver toxicity, hyperpigmentation and keratosis of the skin, and
9 decrements in blood copper status and enzyme activity. Chromium (VI) is classified as a known
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 human carcinogen by IARC and NTP, while arsenic is classified as known human carcinogen by the
2 EPA, IARC, and NTP. Radionuclides, such as radium-226, radium-228, and uranium-238, which are
3 naturally occurring in the formation may also return to the surface within produced water. Each of
4 these radionuclides is classified as a known human carcinogen by the EPA and IARC.
9.4.2.4. Flowback and Produced Water: Pesticides
5 Lastly, it should be noted that a number of pesticides appear in the tables presented in Appendix G.
6 These chemicals were reported as having been detected in analyses of hydraulic fracturing
7 flowback and produced waters by several of the 10 sources cited in Appendix A; however, there is
8 much uncertainty about why they were detected. They could have migrated to the shale formation
9 or to the rock surrounding the shale formation, or they could have migrated into source waters
10 used by the hydraulic fracturing operation. It is also possible that these are laboratory
11 contaminants.
9.5. Hazard Identification and Hazard Evaluation of Selected Subsets of
Hydraulic Fracturing Chemicals
12 As described in Section 9.4, the majority of chemicals identified in the previous chapters of this
13 report do not have RfVs and/or OSFs from the sources meeting the criteria described in Section
14 9.3.1. This lack of data creates a challenge for hazard evaluation, because the potential human
15 health effects of these chemicals are difficult to determine. On the other hand, other chemicals
16 identified by the EPA have more data available, including chronic RfVs, data on occurrence, and
17 data on physicochemical properties. This section focuses on the hazard evaluation of these subsets
18 of chemicals that had data available.
19 When considering the hazard evaluation of chemicals in drinking water, it is important to
2 0 remember that toxicity is contingent upon exposure. All chemicals, including pure water, may be
21 toxic if they are ingested in large enough quantities. Therefore, in addition to data on health effects,
2 2 hazard evaluations must also consider data on potential chemical exposure. In the context of the
2 3 hazard evaluation presented in this section, chemical occurrence and physicochemical property
24 data were used as metrics to estimate the likelihood that the chemical could reach and impact
2 5 drinking water resources.
2 6 For the selected subsets of chemicals that had data available, this section discusses the known
27 toxicological properties based on selected RfVs (hazard identification), and then illustrates one
28 possible method for combining toxicity and exposure potential information for a more data-
29 informed hazard evaluation. Additionally, this section presents a summary of chemicals that have
30 occurrence data across multiple stages of the hydraulic fracturing water cycle.
9.5.1. Selection of Chemicals for Hazard Evaluation
31 From the overall list of 1,173 chemicals identified in this assessment, subsets of chemicals were
32 selected for hazard evaluation if they met the following criteria:
33 1. Had a federal chronic oral RfV;
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Hazard Evaluation of Chemicals across the Hydraul
1 2. Had available data on frequency of use (in hydraulic fracturing fluids) or measured
2 concentrations (in flowback and produced water); and
3 3. Had available data on physicochemical properties.
4 These criteria were selected for hazard evaluation for the following reasons:
5 1. Federal RfVs generally undergo more extensive independent peer review compared to
6 other sources of RfVs. Additionally, as described above, there are many more chemicals
7 with federal chronic RfVs than chemicals with federal OSFs. Therefore, although OSFs are
8 discussed in the hazard evaluation, chronic RfVs were selected for illustrative purposes of
9 making comparisons between chemicals.
10 2. Data on frequency of use (in hydraulic fracturing fluids) or measured concentration (in
11 flowback or produced water) provide a metric to help assess the likelihood of chemical
12 occurrence in the hydraulic fracturing water cycle. Chemicals that are used more
13 frequently in hydraulic fracturing fluid have a greater likelihood of accidental release or
14 dissemination due to the fact that they are present at a greater number of we 11s
15 nationwide. Likewise, chemicals that occur at higher concentrations in flowback or
16 produced water may result in greater exposures. Frequency of detection in flowback or
17 produced water would also be a useful metric for this evaluation, but this information was
18 not available for these chemicals.
19 3. Information on physicochemical properties enables the estimation of chemical persistence
20 and mobility in the environment This is discussed in more detail in Section 9.5.2 below.
21 For chemicals that are used in hydraulic fracturing fluids, the FracFocus database was the only
22 source with reliable information on the frequency of use (U.S. EPA. 2015a). For chemicals found in
23 flowback or produced water, data on measured concentration were only available for the 75
24 chemicals presented in Appendix E. Therefore, hazard evaluations were only conducted on
25 chemicals included in these two data sources. While the other data sources listed in Appendix A
26 provide useful information on the diversity of chemicals that may occur in the hydraulic fracturing
27 water cycle, hazard evaluation could not be conducted on these sources in the absence of data on
28 frequency of use or measured concentration.
29 Overall, 37 chemicals used in hydraulic fracturing fluid and 23 chemicals detected in flowback and
30 produced water met the selection criteria for hazard evaluation (see Figure 9-3).
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Hazard Evaluation of Chemicals
Across the Hydraulic Fracturing Water Cycle
1,076 chemicals used in hydraulic fracturing fluid:
134 chemicals detected in flowback and produced water:
73
chemicals with federal RfV
(oral, chronic duration
chemicals with
physicochemical
property data
chemicals with
Frequency of use data
(from FracFocus)
Chemicals selected for
hazard evaluation
70
chemicals with federal RfV
oral, chronic duration
chemicals with
physicochemica
property data
Figure 9-3. The two subsets of chemicals selected for hazard evaluation included 37 chemicals used in hydraulic fracturing fluid,
and 23 chemicals detected in flowback or produced water.
June 2015
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9.5.2. Multi Criteria Decision Analysis (MCDA) Framework for Hazard Evaluation: Integrating
Toxicity, Occurrence, and Physicochemical Data
1 Integration or combining of various types of data may provide insights on those chemicals that may
2 be of greater concern than other chemicals to drinking water resources. For the purpose of this
3 chapter, a structured but flexible Multi Criteria Decision Analysis (MCDA) approach was developed
4 to integrate factors related to hydraulic fracturing such as chemical toxicity, occurrence, and
5 physicochemical data. The approach described here is for illustrative purposes only, in order to
6 demonstrate how combining of information may be informative. Alternative frameworks may be
7 considered by risk assessors for similar analyses.
8 In this illustration, a MCDA framework was developed and applied to each list of chemicals
9 identified in Section 9.5.1 and depicted in Figure 9-3 (37 chemicals used in hydraulic fracturing
10 fluids, and 23 chemicals detected in flowback or produced water). The MCDA framework serves to
11 place the toxicity of these chemicals in the context of factors that may increase the likelihood of
12 impacting drinking water resources. In essence, this analysis serves to illustrate the circumstances
13 under which drinking water resources may be affected.
14 MCDA is a well-established analysis tool that is used to transparently integrate multiple lines of
15 evidence to support decision-making. For example, MCDA has been adapted as a method of
16 selecting an optimal cleanup plan for a contaminated site (Linkov et al.. 2 011), and as a method of
17 integrating chemical hazard data across multiple studies (Hristozovetal., 2014). The MCDA
18 framework employed here is based on the method by Mitchell etal. (2013b). who developed a
19 protocol for ranking chemical exposure potential by integrating data on physicochemical properties
20 and commercial use. This method is similar to approaches used by the petroleum industry to
21 quantitatively rank the potential hazards of hydraulic fracturing chemicals (see Section 5.9).
22 Moreover, the underlying philosophy of this approach is similar to that of the EPA's Design for the
23 Environment (DfE) Program. The DfE's Alternatives Assessment Criteria for Hazard Evaluation (U.S.
24 EPA. 2011a) was developed as a tool for evaluating and differentiating among chemical hazards
25 based on toxicity and physicochemical properties. Recently, this criteria and framework have been
26 applied in the Alternatives Assessment for the Flame Retardant Decabromodiphenyl Ether
27 (DecaBDE) and Flame Retardant Alternatives for Hexabromocyclododecane (HBCD) (U.S. EPA,
28 2014a. d). Aspects of MCDA methods and the DfE's Program for Alternatives Assessment are
29 evident in the National Research Council (NRC)'s "A Framework to Guide Selection of Chemical
30 Alternatives" document (NRC. 2014).
31 The methodology used to illustrate a hazard evaluation MCDA for hydraulic fracturing is outlined
32 below, and schematic of the model is shown in Figure 9-4. Under the MCDA framework, each
33 chemical was assigned three scores:
34 1. A toxicity score;
35 2. An occurrence score; and
36 3. A physicochemical properties score.
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Chapter 9 - Identification and Ht
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1 The three normalized scores were summed to develop a total composite hazard potential score for
2 each chemical. These scores serve as a relative ranking and a means of making comparisons across
3 chemicals. These scores are not intended to define whether or not a chemical will present a human
4 health hazard, or indicate that one chemical is safer than another. Rather, the scores serve as a
5 qualitative metric to identify chemicals that may be more likely to present an impact to drinking
6 water resources, given available data on chemical properties and occurrence.
Total Hazard Potential Score
Physicochemical
Properties
Mobility
Volatility
Persistence
Figure 9-4. Overview of the MCDA framework applied to the hazard evaluations.
9.5.2.1. Toxicity Score
7 The toxicity score was based upon the federal chronic RfV, which was determined from peer
8 reviewed sources as described in Section 9.3.1. Within each dataset (chemicals used in hydraulic
9 fracturing fluids, or chemicals detected in flowback and produced water), toxicity was ranked based
10 on quartiles, with each chemical assigned a toxicity score of 1 to 4 (see thresholds outlined in Table
11 9-5). Note that chemicals in the lowest quartile received the highest toxicity score as these
12 chemicals have lower RfVs than for other chemicals.
9.5.2.2. Occurrence Score
13 This score was based on the frequency or concentration at which chemicals were reported within
14 the hydraulic fracturing water cycle. For chemicals used in hydraulic fracturing fluids, the
15 occurrence score was based on the nationwide number of well disclosures for each chemical from
16 the FracFocus database. For chemicals that were detected in hydraulic fracturing flowback and
17 produced water, the occurrence score was based on the average or median measured concentration
18 reported in Appendix E. If the measured concentration of a chemical was reported by multiple
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
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1 studies in Appendix E, the highest of these reported average or median concentrations was used for
2 this calculation. Note that these two metrics of chemical occurrence—frequency of use, and
3 concentration—cannot be directly compared to one another. Therefore, FracFocus chemicals and
4 flowback and produced water chemicals were considered separately for this MCDA hazard
5 evaluation. Within each dataset (chemicals used in hydraulic fracturing fluids, or chemicals
6 detected in flowback and produced water), chemical occurrence was ranked based on quartiles,
7 with each chemical assigned an occurrence score of 1 to 4, as shown in Table 9-5.
9.5.2.3. Physicochemical Properties Score
8 This score was based upon inherent physicochemical properties which affect the likelihood that a
9 chemical will reach and impact drinking water resources. The thresholds chosen for ranking
10 physicochemical properties, shown in Table 9-5, are based on previously published thresholds used
11 in the DfE Alternatives Assessment Criteria for Hazard Evaluation [U.S. EPA. 2011a], the EPA Office
12 of Pollution Prevention and Toxics Pollution Prevention (P2) Framework [U.S. EPA. 2005], and
13 Mitchell et al. (2013b). When refining EPI Suite™ physicochemical properties data for input into
14 this MCDA, empirically measured values were always used when available. If multiple estimated
15 values were available, the most conservative value (i.e., the value resulting in the highest score
16 according to Table 9-5) was used.
17 The total physicochemical properties score for each chemical was based upon three subcriteria:
18 mobility in water, volatility, and persistence. Chemical mobility in water was assessed based upon
19 three physicochemical properties: the octanol-water partition coefficient (K0w), the organic carbon-
2 0 water partition coefficient (Koc], and aqueous solubility. Chemical volatility was assessed based on
21 the Henry's law constant, which describes partitioning of a chemical between water and air.
2 2 Chemical persistence was assessed based on estimated half-life in water, which describes how long
23 a chemical will persist in water before it is transformed or degraded. Details on the evaluation and
24 physicochemical score calculation are provided in the Chapter Annex, Section 9.8.1. For each
25 chemical, the mobility score, volatility score, and persistence score (each on a scale of 1 to 4) were
26 summed to calculate a total physicochemical score.
9.5.2.4. Final MCDA Score Calculations
27 Each raw score (toxicity, occurrence, or physicochemical properties), calculated as described above,
2 8 was standardized by scaling to the highest and lowest raw score within the set of chemicals. The
29 following equation was used:
•3U ^>x_final — (^x "" ^*minj / (^max "" ^*minj
31 in which Sx is the raw score for a particular chemical x, Smax is the highest observed raw score within
32 the set of chemicals, and Smin is the lowest observed raw score within the set of chemicals. Sx_fmai is
33 the standardized score for chemical x. Each standardized score (toxicity, occurrence, or
34 physicochemical properties) falls on a scale of 0 to 1. These standardized toxicity, occurrence, and
35 physicochemical properties scores were summed to calculate a total hazard potential score for each
36 chemical. The total hazard potential scores fell on a scale of 0 to 3, with higher scores indicating
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
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1 chemicals that are predicted to be more likely to affect drinking water resources. An example of
2 MCDA score calculation can be found in the Annex, Section 9.8.2.
3 In the MCDA approach illustrated in this chapter, each factor (toxicity, occurrence, physicochemical
4 properties) was given equal weight in the calculation of the final hazard potential score. This was
5 done in order to prevent subjectivity and avoid biasing the results based on any individual variable
6 that was considered in this analysis. This approach is adaptable, however. Risk assessors may
7 choose to apply alternative weights that place more or less emphasis on the various factors being
8 considered, in order to reflect expert judgement of a variable's relative importance. This MCDA
9 approach may also be adapted to include other variables of interest, such as carcinogenic potential,
10 which were not considered in the MCDA approach illustrated in this chapter.
Table 9-5. Thresholds used for developing the toxicity score, occurrence score, and
physicochemical properties score in this MCDA framework.
Score
1
2
3
4
Toxicity Score
Chronic RfV
(federal)
>3rd quartile
>2nd quartile to
<3rd quartile
>lst quartile to
<2nd quartile
lst quartile to
<2nd quartile
>lst quartile to
<2nd quartile
>2nd quartile to
<3rd quartile
>2nd quartile to
<3rd quartile
>3rd quartile
>3rd quartile
Physicochemical Properties Score
Mobility score:
Log Kow
LogK0c
Aqueous solubility
(mg/L)
>5
>4.4
<0.1
>3to5
>3. 4 to 4.4
>0.1to<100
>2to3
>2.4to3.4
> 100 to < 1000
<2
<2.4
>1000
Volatility score:
Henry's law
constant
>10"1
>10"3to<10"1
>10"5to<10"3
<10"5
Persistence score:
Half-life in water
(days)
<16
>16 to <60
>60 to <180
>180
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-22 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
9.5.3. Hazard Evaluation Results
1 Discussed below are the results of the hazard evaluations for each subset of chemicals identified in
2 Section 9.5.1. For each subset of chemicals selected for hazard evaluation, the information
3 presented includes: the available federal chronic oral RfV (hazard identification), followed by
4 highlights of MCDA analyses (hazard evaluation).
5 For this MCDA illustration, the calculated toxicity scores, occurrence scores, physicochemical
6 properties scores, and total hazard potential scores are provided for chemicals used in hydraulic
7 fracturing fluids and chemicals detected in flowback/produced water, respectively. These
8 individual scores make it possible to visualize the extent to which the total hazard potential ranking
9 of each chemical is driven by each of the variables considered in the MCDA.
9.5.3.1. Hazard Identification: Chemical Used in Hydraulic Fracturing Fluid
10 As discussed above, a total of 37 chemicals used in hydraulic fracturing fluids were identified for
11 hazard evaluation using the selection criteria described in Section 9.5.1. Some of the chemicals
12 represented include the BTEX chemicals (benzene, toluene, ethylbenzene, xylenes) as well as
13 naphthalene, acrylamide, phenol, 1,2-propylene glycol, ethylene glycol, 2-butoxyethanol, ethyl
14 acetate, and methanol.
15 These chemicals along with their primary noncancer toxicological properties, including the point-
16 of-departure (POD), total product of uncertainty factors applied, the federal chronic RfV, and the
17 health effect basis for the RfV, are shown in Table 9-6.1/2 As seen in Table 9-6, all of these chemicals
18 had RfDs available from IRIS, PPRTV, or HHBP. These chemicals induce a variety of adverse
19 outcomes including immune system effects, changes in body weight, changes in blood chemistry,
20 cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and developmental
21 toxicity. The RfD values within this suite of chemicals range from 0.001-20 mg/kg-day, with (E)-
22 crotonaldehyde having the lowest RfD (0.001 mg/kg-day) and 1,2-propylene glycol having the
23 highest (20 mg/kg-day).
24 Comparison of RfVs among a set of chemicals requires a more thorough examination. For instance,
25 to derive the final chronic RfD for a given chemical, a number of UFs may be applied to the POD.
26 Briefly, UFs are applied to account for 5 areas of uncertainty: 1) intraspecies variability; 2)
1 The point-of-departure (POD) is the dose-response point that marks the beginning of a low-dose extrapolation. This
point can be the lower bound on dose for an estimated incidence or a change in response level from a dose-response
model or a NOAEL or LOAEL for an observed incidence, or change in level of response. See http://www.epa.gov/iris/ for
more information.
2 An uncertainty factor is one of several (generally 10-fold) default factors used in operationally deriving the RfV from
experimental data. The factors are intended to account for (1) variation in susceptibility among the members of the
human population (i.e., inter-individual or intraspecies variability); (2) uncertainty in extrapolating animal data to
humans (i.e., interspecies uncertainty); (3) uncertainty in extrapolating from data obtained in a study with less-than-
lifetime exposure (i.e., extrapolating from subchronic to chronic exposure); (4) uncertainty in extrapolating from a LOAEL
rather than from a NOAEL; and (5) uncertainty associated with extrapolation when the database is incomplete. See the
IRIS Glossary at: http://www.epa.gov/iris/ for more information.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-23 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
1 interspecies uncertainty; 3) extrapolation from a subchronic study; 4) extrapolating from a NOAEL;
2 and 5) an incomplete database. A UF of 1, 3 (10°-5), or 10 can be applied for any of these areas of
3 uncertainty depending upon the amount and/or type data available. The maximum total UF that
4 can be applied is 3,000; RfDs are not derived for chemicals that invoke the application of a total UF
5 >3,000 or involves the application of the full 10-fold UF in four or more areas of uncertainty [U.S.
6 EPA. 2002a). Therefore, those chemicals with a lower total uncertainty factor generally have more
7 reliable and robust health effect information. For example, although (E)-crotonaldehyde has the
8 lowest RfD, chemicals such as acrylamide, benzene, and dichloromethane have RfDs within a factor
9 of 10 (0.002-0.006 mg/kg-day) but with much less uncertainty reflected in their values. All three
10 latter chemicals have large data sets with reproducible effects, and dose estimated based on
11 physiologically based pharmacokinetic models (for acrylamide and dichloromethane) or have
12 available human health effect data (for benzene). Thus, a chemical with a low RfD may reflect high
13 uncertainty in the value and not necessarily be the most toxic.
14 Although only federal RfVs are considered in this hazard evaluation, eight of these chemicals also
15 have federal OSFs. These include acrylamide, benzyl chloride, 1,4-dioxane, 1,3-dichloropropene,
16 benzene, epichlorohydrin, aniline, and dichloromethane. Of these chemicals, acrylamide is the most
17 potent carcinogen. Acrylamide has an OSF of 0.5 per mg/kg-day and is classified as a likely human
18 carcinogen in IRIS (U.S. EPA. 2010). Benzene is the only chemical listed as a known human
19 carcinogen and has a calculated OSF of 0.015 mg/kg-day (U.S. EPA, 2002b). The OSF values for each
20 of these chemicals can be found in Appendix G.
Table 9-6. Toxicological properties of the 37 chemicals used in hydraulic fracturing fluid that
were identified for hazard evaluation and MCDA analysis.
Chemicals are ranked, from low to high, based on their respective federal chronic RfVs.
Chemical
(E) -Crotonaldehyde
Benzyl chloride
Propargyl alcohol
Acrylamide
Benzene
Epichlorohydrin
CASRN
123-73-9
100-44-7
107-19-7
79-06-1
71-43-2
106-89-8
Point of
departure
(mg/kg-
day)
3.4
6.4
5
0.053
1.2
6.25
Total
uncertain
ty factor
3000
3000
3000
30
300
1000
RfV
Chronic
RfD
(mg/kg-
day)
0.001
0.002
0.002
0.002
0.004
0.006
Noncancer effect
Forestomach lesions
Cardiotoxicity
Renal and
hepatotoxicity
Degenerative nerve
changes
Decreased
lymphocyte count in
humans
Decreased fertility
Source
PPRTV
PPRTV
IRIS
IRIS
IRIS
PPRTV
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Chemical
Dichloromethane
Aniline
2-(Thiocyano
methylthio)benzo
thiazole
Furfural
Naphthalene
2 - (2 -Butoxyethoxy)
ethanol
1,4-Dioxane
Bisphenol A
1,3-
Dichloropropene
Toluene
Ethylenediamine
Ethylbenzene
2-Butoxyethanol
(EGBE)
Acetophenone
Didecyldimethyl
ammonium
chloride
CASRN
75-09-2
62-53-3
21564-17-
0
98-01-1
91-20-3
112-34-5
123-91-1
80-05-7
542-75-6
108-88-3
107-15-3
100-41-4
111-76-2
98-86-2
7173-51-5
Point of
departure
(mg/kg-
day)
0.19
7
3.8
30
71
81
9.6
50
3.4
238
9
97.1
1.4
423
10
Total
uncertain
ty factor
30
1000
300
3000
3000
3000
300
1000
100
3000
100
1000
10
3000
100
RfV
Chronic
RfD
(mg/kg-
day)
0.006
0.007
0.01
0.01
0.02
0.03
0.03
0.05
0.03
0.08
0.09
0.1
0.1
0.1
0.1
Noncancer effect
Hepatic effects
Splenic effects
Decreased body
weight gain;
decreased white blood
cells (WBC) and
plasma alanine
aminotransferase
(ALT)
Liver pathology
Decreased mean
terminal body weight
> 10%
Changes in red blood
cells (RBC)
Liver and kidney
toxicity
Reduced mean body
weight
Chronic irritation
Increased absolute
kidney weight
Liver and kidney
toxicity
Liver and kidney
toxicity;
histopathology
Hemosiderin
deposition in liver
(inhalation study)
General toxicity; NO
LOAEL identified
Clinical signs;
decreased total
cholesterol levels
Source
IRIS
PPRTV
HHBP
HHBP
IRIS
PPRTV
IRIS
IRIS
IRIS
IRIS
PPRTV
IRIS
IRIS
IRIS
HHBP
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-25 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Chemical
Cumene
N,N-Dimethylform
amide
1-Butanol
Xylenes
Formaldehyde
Phenol
2-Methyl-l-
propanol
(Isobutanol)
Acetone
Ethyl acetate
Formic acid
Dodecylbenzenesul
fonic acid
Ethylene glycol
Hexanedioic acid
Methanol
Benzole acid
1,2-Propylene
glycol
CASRN
98-82-8
68-12-2
71-36-3
1330-20-7
50-00-0
108-95-2
78-83-1
67-64-1
141-78-6
64-18-6
27176-87-
0
107-21-1
124-04-9
67-56-1
65-85-0
57-55-6
Point of
departure
(mg/kg-
day)
110
96
125
179
15
93
316
900
900
277
50
200
470
43.1 mg/La
4.4
5200
Total
uncertain
ty factor
1000
1000
1000
1000
100
300
1000
1000
1000
300
100
100
300
100
1
300
RfV
Chronic
RfD
(mg/kg-
day)
0.1
0.1
0.1
0.2
0.2
0.3
0.3
0.9
0.9
0.9
0.5
2
2
2
4
20
Noncancer effect
Increased average
kidney weight in
female rats
Increase in ALT and
liver weight
Hypoactivity and
ataxia
Decreased body
weight; increased
mortality
Decreased weight gain
Decreased maternal
weight gain;
developmental
toxicity
Hypoactivity and
ataxia
Nephropathy
Mortality and body
weight loss
Reproductive effects
Decreased pup
weight; kidney
pathology
Kidney toxicity;
chronic nephritis
Decreased body
weight
Extra cervical ribs;
developmental
toxicity
No adverse effects
observed in humans
Reduced red blood
cell counts and
hyperglycemia
Source
IRIS
PPRTV
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
PPRTV
HHBP
IRIS
PPRTV
IRIS
IRIS
PPRTV
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-26 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Chemical
CASRN
Point of
departure
(mg/kg-
day)
Total
uncertain
ty factor
RfV
Chronic
RfD
(mg/kg-
day)
Noncancer effect
Source
1 POD based on internal methanol blood concentration using a PBPK model.
9.5.3.2. MCDA Results: Chemical Used in Hydraulic Fracturing Fluid
1 The hazard potential scores of the selected 37 chemicals used in hydraulic fracturing fluid are
2 presented in Table 9-7.
Table 9-7. MCDA results for 37 chemicals used in hydraulic fracturing fluid.
Chemicals are ranked, from high to low, based on total hazard potential score. See section 9.5.2 for
details on the calculation.
Chemical
Propargyl alcohol
2-Butoxyethanol (EGBE)
N, N- Dimethylformamide
Acrylamide
Formaldehyde
Naphthalene
Benzyl chloride
1-Butanol
Epichlorohydrin
2 - (2 - B utoxyethoxy) ethanol
Methanol
Ethylene glycol
Formic acid
Didecyldimethylammoniu
m chloride
1,4-Dioxane
(E)-Crotonaldehyde
Aniline
Furfural
CASRN
107-19-7
111-76-2
68-12-2
79-06-1
50-00-0
91-20-3
100-44-7
71-36-3
106-89-8
112-34-5
67-56-1
107-21-1
64-18-6
7173-51-5
123-91-1
123-73-9
62-53-3
98-01-1
Physicochemical
properties score
1.00
1.00
1.00
1.00
1.00
0.67
0.67
1.00
0.67
1.00
1.00
1.00
1.00
0.33
1.00
0.67
1.00
1.00
Occurrence
score
1.00
1.00
1.00
0.67
1.00
1.00
0.67
0.67
0.67
0.67
1.00
1.00
1.00
1.00
0.33
0.33
0.00
0.00
Toxicity
score
1.00
0.67
0.67
1.00
0.33
0.67
1.00
0.67
1.00
0.67
0.00
0.00
0.00
0.67
0.67
1.00
1.00
1.00
Total hazard
potential score
3.00
2.67
2.67
2.67
2.33
2.33
2.33
2.33
2.33
2.33
2.00
2.00
2.00
2.00
2.00
2.00
2.00
2.00
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-27 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Chemical
1,2-Propylene glycol
Hexanedioic acid
Toluene
Phenol
2-Methyl-l-propanol
(Isobutanol)
Dichloromethane
Ethylenediamine
Bisphenol A
2 - (Thiocyanomethylthio)
benzothiazole
Benzene
Dodecylbenzenesulfonic
acid
Xylenes
Ethylbenzene
Benzoic acid
Acetophenone
1,3-Dichloropropene
Cumene
Ethyl acetate
Acetone
CASRN
57-55-6
124-04-9
108-88-3
108-95-2
78-83-1
75-09-2
107-15-3
80-05-7
21564-17-0
71-43-2
27176-87-0
1330-20-7
100-41-4
65-85-0
98-86-2
542-75-6
98-82-8
141-78-6
67-64-1
Physicochemical
properties score
1.00
1.00
0.33
1.00
1.00
0.67
1.00
1.00
0.67
0.67
0.33
0.33
0.33
1.00
0.67
0.67
0.00
0.67
0.67
Occurrence
score
0.67
0.67
0.67
0.33
0.33
0.00
0.00
0.00
0.00
0.00
1.00
0.67
0.33
0.33
0.00
0.00
0.33
0.33
0.33
Toxicity
score
0.00
0.00
0.67
0.33
0.33
1.00
0.67
0.67
1.00
1.00
0.00
0.33
0.67
0.00
0.67
0.67
0.67
0.00
0.00
Total hazard
potential score
1.67
1.67
1.67
1.67
1.67
1.67
1.67
1.67
1.67
1.67
1.33
1.33
1.33
1.33
1.33
1.33
1.00
1.00
1.00
1 Of the chemicals in hydraulic fracturing fluid that were considered in this hazard evaluation,
2 propargyl alcohol received the highest overall hazard potential score. Propargyl alcohol was used in
3 33% of wells in the FracFocus database, making it one of the most widely used chemicals that was
4 considered in this analysis, and it also had one of the lowest RfVs, with an RfD of 0.002 mg/kg-day.
5 It is also hydrophilic and has relatively low volatility, indicating that it is likely to be readily
6 transported in water. Given these properties, propargyl alcohol received the highest overall ranking
7 across all of the metrics that were considered in the hazard evaluation.
8 The other chemicals that fell in the upper quartile in terms of frequency of use received lower
9 hazard potential scores relative to propargyl alcohol, due to lower estimated toxicity and/or
10 physicochemical properties that are less conducive to transport in water. Naphthalene, used in 19%
11 of wells on the FracFocus database, has an RfD of 0.02 mg/kg-day, and is expected to have
12 somewhat lower transport in water relative to other chemicals because it is moderately
13 hydrophobic and moderately volatile. Methanol (RfD of 2 mg/kg-day), ethylene glycol (RfD of 2
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
1 mg/kg-day), 2-butoxyethanol (RfD of 0.1 mg/kg-day), formic acid (RfD of 0.9 mg/kg-day), N,N-
2 dimethylformamide (RfD of 0.1 mg/kg-day), and formaldehyde (RfD of 0.2 mg/kg-day)—which
3 were used in 73%, 47%, 23%, 11%, 9%, and 7% of wells in the FracFocus database, respectively—
4 are all expected to be highly mobile in water and have low volatility, but have higher RfVs
5 compared to many of the other chemicals in the assessment. Didecyldimethylammonium chloride
6 (RfD of 0.1 mg/kg-day), used in 8% of wells, is expected to have reduced mobility in water due to its
7 more hydrophobic properties.
8 In addition to propargyl alcohol, the other most toxic chemicals (occurring in the lowest quartile of
9 RfVs) received moderate to high hazard potential scores overall. Acrylamide (RfD of 0.002 mg/kg-
10 day) is used in only 1% of wells, but has physicochemical properties that are very conducive to
11 transport in water, and therefore received one of the highest overall hazard potential scores. Benzyl
12 chloride (RfD of 0.002 mg/kg-day) and epichlorohydrin (RfD of 0.006 mg/kg-day) are used in 6%
13 and 1% of wells, respectively, but scored slightly lower than acrylamide with regards to their
14 physicochemical properties. Other chemicals, including (E)-crotonaldehyde (RfD of 0.001 mg/kg-
15 day), benzene (RfD of 0.004 mg/kg-day), dichloromethane (RfD of 0.006 mg/kg-day), aniline (RfD
16 of 0.007 mg/kg-day), furfural (RfD of 0.01 mg/kg-day), and 2-(Thiocyanomethylthio)benzothiazole
17 (RfD of 0.01 mg/kg-day), received lower overall scores because they are used more infrequently
18 (each in less than 0.1% of wells in the FracFocus database).
9.5.3.3. Hazard Identification: Chemicals Detected in Flowback and Produced Water
19 As discussed above, a total of 23 chemicals detected in flowback and produced water were
20 identified for hazard evaluation using the selection criteria described in Section 9.5.1. Of these 23
21 chemicals, 10 chemicals overlap with the hazard evaluation of chemicals used in hydraulic
22 fracturing fluids. Because of this overlap, many of the effects noted in each hazard evaluation are
23 similar.
24 These chemicals, along with their POD, total products of uncertainty factors applied, federal chronic
25 RfVs, and the health effect bases for the RfVs, are shown in Table 9-8. As seen in Table 9-8, all of
26 these chemicals had RfDs available from IRIS, PPRTV, or HHBP. These chemicals induce a variety of
27 adverse outcomes, including immune system effects, changes in body weight, changes in blood
28 chemistry, pulmonary toxicity, neurotoxicity, liver and kidney toxicity, and reproductive and
29 developmental toxicity. The RfD values within this suite of chemicals range from 0.001-0.9 mg/kg-
30 day, with pyridine having the lowest RfD and acetone having the highest RfD. For this subset of
31 chemicals, 88% have an RfD within 2 orders of magnitude of each other and 78% have RfDs within
32 a factor of 10 (range of 0.01-0.1 mg/kg-day). Some of these chemicals include chloroform,
33 naphthalene, 1,4-dioxane, toluene, cumene, and ethylbenzene.
34 Although only federal RfVs are considered in this hazard evaluation, 2 of these chemicals—benzene
35 and 1-4-dioxane—also have federal OSFs . These chemicals are also included in the hazard
36 evaluation of chemicals used in hydraulic fracturing fluids, discussed above. 1,4-dioxane is a more
37 potent carcinogen compared to benzene. The OSF for 1,4-dioxane is 0.1 per mg/kg-day and is
38 classified as likely to be a human carcinogen by IRIS (U.S. EPA. 2013fj.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Table 9-8. Toxicological properties of the 23 chemicals detected in flowback and produced
water that were identified for hazard evaluation and MCDA analysis.
Chemicals are ranked, from low to high, based on their respective federal chronic RfVs. Chemicals in
italics are also included in the hazard evaluation of chemicals used in hydraulic fracturing fluids.
Chemical
Pyridine
2-
Methylnaphthalene
Benzene
Chloroform
Naphthalene
Di(Z-ethylhexyl)
phthalate
2,4-Dimethylphenol
Pyrene
1,4-Dioxane
Fluorene
Fluoranthene
2-Methylphenol
(o-Cresol)
Toluene
Carbon disulfide
CASRN
110-86-1
91-57-6
71-43-2
67-66-3
91-20-3
117-81-7
105-67-9
129-00-0
123-91-1
86-73-7
206-44-0
95-48-7
108-88-3
75-15-0
Point of
departure
(mg/kg-
day)
1
3.5
1.2
12.9
71
19
50
75
9.6
125
125
50
238
11
Total un-
certainty
factors
1000
1000
300
1000
3,000
1000
3000
3000
300
3000
3000
1000
3000
100
RfV
Chronic
RfD
(mg/kg-
day)
0.001
0.004
0.004
0.01
0.02
0.02
0.02
0.03
0.03
0.04
0.04
0.05
0.08
0.1
Non-cancer effect
Increased liver weight
Pulmonary alveolar
proteinosis
Decreased lymphocyte
count in humans
Fatty cyst formation in
the liver; elevated
SGPT(orALT)
Decreased mean
terminal body weight >
10%
Increased relative liver
weight
Clinical signs;
hematological changes
Kidney effects
Liver and kidney
toxicity
Decreased RBC, packed
cell volume and
hemoglobin
Nephropathy; increased
liver weights;
hematological
alterations
Decreased body weights
and neurotoxicity
Increased absolute
kidney weight
Fetal toxicity and
malformations
Source
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
IRIS
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Chemical
Cumene
Benzyl alcohol
Dibutyl phthalate
Ethylbenzene
Acetophenone
Diphenylamine
Xylenes
Phenol
Acetone
CASRN
98-82-8
100-51-6
84-74-2
100-41-4
98-86-2
122-39-4
1330-20-
7
108-95-2
67-64-1
Point of
departure
(mg/kg-
day)
110
143
125
97.1
423
10
179
93
900
Total un-
certainty
factors
1000
1000
1000
1000
3000
100
1000
300
1000
RfV
Chronic
RfD
(mg/kg-
day)
0.1
0.1
0.1
0.1
0.1
0.1
0.2
0.3
0.9
Non-cancer effect
increased average
kidney weight in female
rats
Effects on survival,
growth, and tissue
histopathology
Increased mortality
liver and kidney
toxicity; histopathology
General toxicity; no
LOAEL identified
Alterations in clinical
chemistry; increased
kidney, liver, and spleen
weights
Decreased body weight;
increased mortality
Decreased maternal
weight gain;
developmental toxicity
Nephropathy
Source
IRIS
PPRTV
IRIS
IRIS
IRIS
HHBP
IRIS
IRIS
IRIS
9.5.3.4. MCDA Results: Flow/back and Produced Water
1 The hazard potential scores of the selected 23 chemicals detected in flowback and produced water
2 are presented in Table 9-9.
Table 9-9. MCDA results for 23 chemicals in hydraulic fracturing flowback and produced
water.
Chemicals are ranked, from high to low, based on total hazard potential score. See Section 9.5.2 for
details on the calculation.
Chemical
Benzene
Pyridine
Naphthalene
CASRN
71-43-2
110-86-1
91-20-3
Physicochemical
properties score
0.75
0.75
0.75
Occurrence
score
1.00
1.00
0.67
Toxicity
score
1.00
1.00
1.00
Total hazard
potential score
2.75
2.75
2.42
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-31 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Chemical
2,4-Dimethylphenol
2-Methylnaphthalene
Chloroform
2-Methylphenol
Benzyl alcohol
Bis(Z-Ethylhexyl) Phthalate
Carbon Disulfide
Toluene
Acetone
Pyrene
Di-n-butyl Phthalate
1,4-Dioxane
Fluoranthene
Xylenes
Ethylbenzene
Phenol
Diphenylamine
Isopropylbenzene
Acetophenone
Fluorene
CASRN
105-67-9
91-57-6
67-66-3
95-48-7
100-51-6
117-81-7
75-15-0
108-88-3
67-64-1
129-00-0
84-74-2
123-91-1
206-44-0
1330-20-
7
100-41-4
108-95-2
122-39-4
98-82-8
98-86-2
86-73-7
Physicochemical
properties score
1.00
0.25
0.75
1.00
1.00
0.25
0.50
0.50
0.75
0.75
0.75
1.00
1.00
0.50
0.50
1.00
1.00
0.25
0.75
0.00
Occurrence
score
0.33
1.00
0.33
0.33
0.67
0.67
1.00
1.00
0.67
0.00
0.33
0.00
0.00
1.00
0.33
0.67
0.00
0.67
0.00
0.00
Toxicity
score
1.00
1.00
1.00
0.67
0.33
1.00
0.33
0.33
0.00
0.67
0.33
0.67
0.67
0.00
0.33
0.00
0.33
0.33
0.33
0.67
Total hazard
potential score
2.33
2.25
2.08
2.00
2.00
1.92
1.83
1.83
1.42
1.42
1.42
1.67
1.67
1.50
1.17
1.67
1.33
1.25
1.08
0.67
1 The highest total hazard potential scores for chemicals in flowback and produced water went to
2 benzene and pyridine, followed closely by naphthalene. These three chemicals all have RfVs that fell
3 in the lowest (most toxic) quartile relative to other chemicals in the hazard evaluation (RfDs of
4 0.004, 0.001, and 0.02 mg/kg-day, respectively). Benzene fell in the upper quartile of observed
5 chemical concentrations (with a maximum reported average concentration of 680 [J.g/1; Barnett
6 shale produced water, Table E-9), while pyridine and naphthalene fell in the second highest quartile
7 (with maximum reported average concentrations of 413 and 238 [j.g/1, respectively; Barnett shale
8 produced water, Table E-10). These three chemicals only scored moderately in terms of their
9 physicochemical properties, however, as all three are expected to have somewhat lower transport
10 in water compared to other chemicals in the assessment 2-Methylnaphthalene also fell in the
11 lowest quartile in terms of toxicity (RfD of 0.004 mg/kg-day) and the highest quartile in terms of
12 concentration (average of 1,362 [J.g/1; Barnett shale produced water, Table E-10), but received a
13 slightly lower score than these chemicals with regards to physiochemical properties.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
1 Other chemicals occurring in the upper quartile of flowback and produced water concentrations
2 include toluene (average of 760 [J.g/1; Barnett shale produced water, Table E-9), xylenes (average of
3 360 [J.g/1; Barnett shale produced water, Table E-9), and carbon disulfide (median of 400 [J.g/1;
4 Marcellus shale produced water, Table E-10). These chemicals all received moderate hazard
5 potential scores, as all have higher RfDs (lower toxicity) relative to many of the other chemicals in
6 the hazard evaluation, and are all expected to have moderate transport in water relative to the
7 other chemicals.
8 Other chemicals with RfVs that fell in the lowest (most toxic) quartile in flowback and produced
9 water include chloroform (RfD of 0.01 mg/kg-day), di(2-ethylhexyl)phthalate (RfD of 0.02 mg/kg-
10 day), and 2,4,-dimethylphenol (RfD of 0.02 mg/kg-day). Of these, di(2-ethylhexyl)phthalate was
11 detected at moderately high concentrations relative to other chemicals in the assessment (average
12 of 210 [J.g/1; Barnett shale produced water, Table E-10), but is expected to have reduced mobility in
13 water due primarily to its more hydrophobic properties. The rest are expected to have moderate to
14 high transport in water, but were detected at relatively lower average concentrations compared to
15 other chemicals in the assessment.
9.5.4. Summary of Chemicals Detected in Multiple Stages of the Hydraulic Fracturing Water
Cycle
16 A number of chemicals with federal chronic RfVs that are used in hydraulic fracturing fluids were
17 also found to be present in flowback and produced water stages of the hydraulic fracturing water
18 cycle. The use of a chemical in hydraulic fracturing fluids, and subsequent presence in later stages
19 of the hydraulic fracturing water cycle, is of particular interest in demonstrating which chemicals in
20 this dataset may be mixed, injected, and then detected downstream in the water cycle. This section
21 focuses on that group of chemicals.
22 Based on the available information in our datasets, 23 chemicals overall had federal chronic RfVs
2 3 and were identified as being used in hydraulic fracturing fluids and detected in the
24 flowback/produced water stage of the hydraulic fracturing water cycle. These chemicals are shown
25 in Table 9-10. 10 of these chemicals were included in both the hazard evaluation of hydraulic
26 fracturing fluids (see Table 9-6 and Table 9-7) and the flowback and produced water hazard
27 evaluation (see Table 9-8 and Table 9-9). This means that these 10 chemicals had both frequency of
28 use data from FracFocus and a reported measured concentration in flowback and produced water
29 from Chapter 7 (Appendix E). These 10 chemicals included all of the BTEX chemicals, as well as
30 naphthalene, 1,4 dioxane, acetone, acetophenone, cumene, and phenol. The chemicals of this group
31 with the lowest chronic oral RfVs were benzene, naphthalene, and 1,4-dioxane. These chemicals all
32 have RfDs within an order of magnitude of each other and are known or likely human carcinogens.
33 The next chemical of this group—toluene—has an RfD 20 times greater than benzene. Overall,
34 benzene was the most toxic of the chemicals listed in Table 9-10.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-33 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Table 9-10. List of the 23 chemicals with federal chronic RfVs identified to be used in
hydraulic fracturing fluids and detected in the flowback/produced water stage of
the hydraulic fracturing water cycle.
Chemical
1,4-Dioxane
Acetone
Acetophenone
Benzene
Cumene
Ethylbenzene
Naphthalene
Phenol
Toluene
Xylenes
1,2-Propylene
glycol
Dichloromethane
Ethylene glycol
Formic acid
Methanol
Aluminum
Iron
Di(Z-ethylhexyl)
phthalate
Acrolein
Arsenic
Chlorine
Chromium (III)
Chromium (VI)
Zinc
CASRN
123-91-1
67-64-1
98-86-2
71-43-2
98-82-8
100-41-4
91-20-3
108-95-2
108-88-3
1330-20-7
57-55-6
75-09-2
107-21-1
64-18-6
67-56-1
7429-90-5
7439-89-6
117-81-7
107-02-8
7440-38-2
7782-50-5
16065-83-1
18540-29-9
7440-66-6
Used in
hydraulic
fracturing
fluids?
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
FracFocus
frequency
of use
data?
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
-
-
-
-
-
-
-
Detected in
flowback or
produced
water?
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Physicochemical
properties data
available?
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
Y
-
-
Y
Y
-
-
-
-
-
In hazard
evaluation?3
FF+FB
FF+FB
FF+FB
FF+FB
FF+FB
FF+FB
FF+FB
FF+FB
FF+FB
FF+FB
FF
FF
FF
FF
FF
No
No
FB
No
No
No
No
No
No
a FF+FB: chemical in both the hydraulic fracturing fluid and flowback/produced water hazard evaluations; FF or FB: chemical in
either the hydraulic fracturing fluid or flowback/produced water hazard evaluations. A dash indicates data for chemical not
available.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-34 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
1 An additional 6 chemicals were included in either the hazard evaluation of hydraulic fracturing
2 fluids (see Table 9-6 and Table 9-7) or the flowback and produced water hazard evaluation (see
3 Table 9-8 and Table 9-9), but not both. These chemicals were reported to be have been used in
4 hydraulic fracturing fluids and detected in flowback/produced water, but lacked the occurrence
5 data (frequency of use or a measured concentration) to support inclusion in both of these hazard
6 evaluations. The remaining 8 chemicals reported to have been used in hydraulic fracturing fluids or
7 detected in flowback/produced water were not included in either of the hazard evaluations
8 presented above because they lacked one or more of the inclusion criteria. These chemicals include
9 acrolein as well as several metals. Arsenic and acrolein have the lowest RfDs by an order of
10 magnitude and arsenic is classified as a known human carcinogen by the EPA, IARC, and NTP.
11 Chromium (VI) is also classified as a known human carcinogen by IARC and NTP.
9.6. Synthesis
12 The overall objective of this chapter was to identify and provide information on the toxicological
13 properties of chemicals used in hydraulic fracturing and of hydraulic fracturing waste water
14 constituents, and to evaluate the potential hazard of these chemicals to drinking water resources.
15 Toward this end, the EPA developed a comprehensive list of 1,173 chemicals with reported
16 occurrence in the hydraulic fracturing water cycle, separating them into subsets based on whether
17 they were reported to have been used in hydraulic fracturing fluids or detected in flowback and
18 produced water. First, for each of these chemicals, RfVs and OSFs from selected federal, state, and
19 international sources were collected when available. Second, for subsets of chemicals that were
20 identified as being of interest in previous chapters of this report, federal chronic RfVs were used to
21 conduct an initial identification of the potential human health hazards inherent to these chemicals.
22 Finally, for other subsets of chemicals that had data available, an approach for a more data-
23 informed hazard evaluation was illustrated by integrating data on federal chronic RfVs, occurrence,
24 and physicochemical properties using an MCDA framework.
9.6.1. Summary of Findings
2 5 Across the industrial landscape, thousands of chemicals are used commercially that lack toxicity
26 data (Judsonetal.. 2009). Similarly, major knowledge gaps exist regarding the toxicity of most
27 chemicals used in hydraulic fracturing fluids or detected in flowback/produced water, impeding the
28 assessment of human health risks associated with drinking water resources affected by hydraulic
29 fracturing.
30 Of the 1,076 chemicals used in hydraulic fracturing fluids, chronic RfVs and/or OSFs from all of the
31 selected federal, state, or international sources were available for 90 chemicals (8.4%). From the
32 federal sources alone, chronic oral RfVs were available for 73 chemicals (6.8%), and OSFs were
33 available for 15 (1.4%). Potential hazards associated with these chemicals include carcinogenesis,
34 immune system effects, changes in body weight, changes in blood chemistry, cardiotoxicity,
35 neurotoxicity, liver and kidney toxicity, and reproductive and developmental toxicity.
36 Of the 134 chemicals that are reported to have been detected in hydraulic fracturing flowback or
37 produced water, chronic RfVs and/or OSFs from all of the selected federal, state, or international
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 9-35 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
1 sources were available for 83 chemicals (62%). From the federal sources alone, chronic RfVs were
2 available for 70 chemicals (52%), and OSFs were available for 20 (15%). Potential hazards
3 associated with these chemicals include carcinogenesis, immune system effects, changes in body
4 weight, changes in blood chemistry, pulmonary toxicity, neurotoxicity, liver and kidney toxicity, and
5 reproductive and developmental toxicity.
6 Of the chemicals included in the hazard evaluations, benzene is the only one of these chemicals with
7 an OSF that is classified as a known human carcinogen, while acrylamide was found to be the most
8 potent likely human carcinogen. Several other chemicals, including 1,4-dioxane, dichloromethane,
9 naphthalene, and ethylbenzene are also classified as possible, probable, or likely human
10 carcinogens.
11 Toxicity information spans a wide range with respect to extent, quality and reliability. The sources
12 of RfVs and OSFs selected for the purposes of this chapter are based on criteria developed
13 specifically for this report For the total 1,173 chemicals identified on the EPA's list, federal, state,
14 and international chronic RfVs and/or OSFs that met stringent selection criteria were available for
15 147 (13%) of the chemicals. Several of the RfVs from selected sources were derived using UFs of up
16 to several orders of magnitude, indicating uncertainty when comparing chemicals for potential
17 toxicity and identifying the chemicals that may be more likely to present a human health hazard.
18 For many of the chemicals used in hydraulic fracturing or found in flowback or produced water
19 there may be relevant information, including cancer and noncancer-related information, from one
20 or more sources that were not evaluated in this chapter. In instances where toxicity data is not
21 available from selected sources, risk assessors may need to draw from alternative sources of hazard
22 information. The chapter discusses two available resources for consideration when RfVs and/or
23 OSFs are not available: QSAR-predicted toxicity data, and toxicity data from the EPA's ACToR
24 database. Oral toxicity data was available on ACToR for 642 (55%) of the chemicals. The
25 information available in the ACToR data warehouse ranges from the federal RfVs discussed in
26 Section 9.3.1, which have undergone extensive peer review, to RfVs and study and test results that
27 have undergone little to no peer review.
28 When considering the potential impact of chemicals on drinking water resources and human health,
29 it is important to consider exposure as well as toxicological properties. The majority of chemicals
30 identified in this report lacked the necessary data to conduct such an assessment However,
31 integrating data on toxicity, occurrence, and physicochemical properties using an MCDA framework
32 enabled a more data-informed hazard evaluation on some chemicals. This analysis highlighted
33 several chemicals that may be more likely than others to reach drinking water and create a
34 toxicological hazard. In hydraulic fracturing fluid, an example is propargyl alcohol. It was among the
35 chemicals with the lowest RfVs considered in this hazard evaluation, was used in 33% of wells in
36 the FracFocus database, and is water soluble with low volatility. In flowback and produced water,
37 examples of such chemicals include benzene, pyridine, and naphthalene. These chemicals were also
38 among those with the lowest RfVs considered in this hazard evaluation, are expected to be
39 relatively mobile in water, and were present at relatively high average concentrations in flowback.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
9.6.2. Factors Affecting the Frequency or Severity of Impacts
1 When assessing chemical hazards, there are multiple pieces of information that could be taken into
2 account This includes knowledge of the chemicals used at a given well site, the toxicological and
3 physicochemical properties of these chemicals, the amount of fluid being used and recovered, the
4 likelihood of well integrity failures, and the likelihood of spills and other unintentional releases.
5 These topics were previously discussed in Chapters 5 through 8 of this report Because of the large
6 volumes of fluid being injected, even chemicals representing a small percentage of the total fluid by
7 mass may pose a potential for exposure in the event of a spill or leak.
8 Overall, contamination of drinking water resources depends on site-, chemical-, and fluid-specific
9 factors [Goldstein etal.. 2014], and the exact mixture and concentrations of chemicals at a site will
10 depend upon the geology and the company's preferences. Therefore, potential hazard and risk
11 considerations are best made on a site-specific, well-specific basis. While the MCDA results in this
12 chapter illustrate an approach to evaluate the relative hazards of these chemicals at the national
13 level, a site-specific hazard evaluation would be necessary in order to identify chemicals of concern
14 at the local level.
15 For example, consider (E)-crotonaldehyde, which is one of the more toxic chemicals considered in
16 the hazard evaluation of hydraulic fracturing fluids. (E)-crotonaldehyde is reportedly used in only
17 0.06% of wells in the FracFocus database, based on the EPA's analysis. If the FracFocus database
18 represents a fair sample of all of the wells across the country, then the likelihood of (E)-
19 crotonaldehyde contamination on a nationwide scale is limited. However, this in no way diminishes
20 the likelihood of (E)-crotonaldehyde contamination at well sites where this chemical is used.
21 Therefore, potential exposures to more toxic but infrequently used chemicals are more of a local
22 issue, rather than a national one.
23 This is in contrast with methanol, which was reported in 73% of wells in the FracFocus database.
24 Methanol is soluble and relatively mobile in water, but has a higher RfV relative to other chemicals
25 in the hazard evaluation. Therefore, when considering chemical usage on a nationwide basis,
26 methanol may be expected to have a higher exposure potential compared to other chemicals, with a
27 moderate overall hazard potential due to its relatively high RfV.
9.6.3. Uncertainties
2 8 There are several notable uncertainties in the chemical and toxicological data that limit a
29 comprehensive assessment of the potential health impacts of hydraulic fracturing on drinking
30 water resources.
31 For the purposes of this chapter, the lack of RfVs and OSFs from the sources meeting stringent
32 selection criteria is the most significant data gap. For instance, of the 32 chemicals (excluding
33 water, quartz, and sodium chloride) that are used in >10% of wells nationwide according to
34 FracFocus, federal chronic RfVs were only available for 7 chemicals. Without these reliable and peer
3 5 reviewed data, comprehensive hazard evaluation and hazard identification of chemicals is difficult,
36 and the ability to consider the potential cumulative effects of exposure to chemical mixtures in
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
1 hydraulic fracturing fluid, flowback, or produced water is limited. Consequently, potential impacts
2 on drinking water resources and human health may not be assessed adequately.
3 Another major uncertainty lies in the total list of chemicals that was compiled for this chapter. As
4 discussed in Section 5.1.3, information is lacking on the chemicals that are used in hydraulic
5 fracturing fluid formulation. CBI chemicals, which were present in approximately 70% of well
6 records on the FracFocus database, were excluded from the EPA's analysis. The analysis also
7 excluded ingredient records that were not able to be assigned standardized chemical names, which
8 resulted in approximately 35% of FracFocus ingredient records being excluded from the report
9 This lack of data limits the ability to more completely assess the impact of chemicals that are
10 potentially used with great frequency. Moreover, there may be a regional bias in the EPA's analysis
11 of FracFocus, as 78% of chemical disclosures in the FracFocus database came from five states, and
12 47% were from Texas. Despite these limitations, the FracFocus database remains the most
13 complete source for tracking hydraulic fracturing chemical usage in the United States, and therefore
14 was the best available source for the hazard evaluation in this chapter. Although the sources used to
15 compile the chemical list represented the best available data at the time of this study, it is possible
16 that some of these chemicals are no longer used at all, and many of these chemicals may only be
17 used infrequently. Therefore, it may be possible that significantly fewer than 1,076 chemicals are
18 currently used in abundance. Consequently, having a better understanding of the chemicals and
19 formulations, including those that are CBI, along with their frequency of use and volumes, would
2 0 greatly benefit risk assessment and risk management decisions.
21 Additionally, the list of flowback and produced water chemicals identified in this chapter is almost
2 2 certainly incomplete. Few studies to date have examined the chemical composition of flowback and
2 3 produced water, and the hazard evaluation in this chapter relied on data from the relatively small
24 number of studies that are presented in Appendix E of this assessment. As discussed in Chapter 7,
2 5 chemicals and their metabolites may go undetected simply because they were not included in the
2 6 analytical methodology. Additionally, chemical analysis of flowback and produced water may be
2 7 challenging, because high levels of dissolved solids in flowback and wastewater can interfere with
2 8 chemical detection. As a result, it is likely that there are chemicals of concern in flowback and
29 produced water that have not been detected or reported.
3 0 Finally, when considering the MCDA framework that was used to illustrate an approach for hazard
31 evaluation, it should be noted that the physicochemical variables were chosen specifically to reflect
3 2 chemical mobility and persistence in water. While this framework draws attention towards those
3 3 chemicals that are most likely to be carried in water, it does not attempt to address the numerous
34 other physicochemical variables that may affect chemical exposure. For instance, as discussed in
35 Chapter 5, hydrophobic chemicals may act as long-term sources of pollution by sorbing to soils or
36 sediments. Additionally, volatile chemicals that dissipate into the air have the potential to pose air
37 pollution hazards, which are not considered in this drinking water assessment; or could potentially
38 be deposited in bodies of water that are distant from the hydraulic fracturing site. Furthermore, as
39 discussed in Chapter 5, chemical fate and transport will be influenced by environmental and site-
40 specific conditions. The fate of a chemical in a chemical mixture will be also influenced by the other
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 9 - Identification and Ht
Across the Hyc
1 chemicals that are present in the mixture, and the relative concentrations of each. Although the
2 assessment of these various scenarios is outside the scope of this report, the potential hazards
3 associated with hydrophobic or volatile chemicals should not be discounted when interpreting the
4 results of this hazard evaluation. It should be emphasized that the MCDA framework illustrated in
5 this chapter represents just one method that can be used to integrate chemical data for hazard
6 evaluation, and is readily adaptable to include different variables, different weights for the
7 variables, and site-specific considerations.
9.6.4. Conclusions
8 The EPA has identified 1,173 chemicals used or detected in the hydraulic fracturing water cycle.
9 Toxicity-based chronic RfVs and/or OSFs from sources meeting selection criteria are not available
10 for the large majority (87%) of these chemicals. In addition, 56% of these chemicals do not have
11 physicochemical property data. Furthermore, 36% of the chemicals used in hydraulic fracturing
12 fluids lack data on their nationwide frequency of use, and very few studies have analyzed the
13 chemical composition of flowback and produced water. Given the large number of chemicals used
14 or detected in various stages of the hydraulic fracturing water cycle, as well as the large number of
15 hydraulic fracturing wells nationwide, this missing chemical information represents a significant
16 data gap. Because of these large data gaps for drinking water resources, it remains challenging to
17 fully understand the toxicity and potential health impacts for single chemicals as well as mixtures of
18 chemicals associated with hydraulic fracturing processes. This chapter provides an initial overall
19 assessment of the potential human health effects associated with hydraulic fracturing on a
20 nationwide basis. It also provides tools that may support risk assessment and risk management
21 decision making at the local and regional level.
22 The toxicological data, occurrence data, and physicochemical data compiled in this report provide a
23 resource for assessing the potential hazards associated with chemicals in the hydraulic fracturing
24 water cycle. Additionally, the MCDA framework presented herein illustrates one method for
25 integrating these data for hazard evaluation. While the analysis in this chapter is constrained to the
26 assessment of chemicals on a nationwide scale, this approach is readily adaptable for use on a
27 regional or site-specific basis.
28 This collection of data provides a tool to inform decisions about protection of drinking water
29 resources. Agencies may use these results to prioritize chemicals for hazard assessment or for
30 determining future research priorities. Industry may use this information to prioritize chemicals for
31 replacement with less toxic, persistent, and mobile alternatives. A summary of the findings related
32 to the overall objective of this chapter and the research questions is presented in Text Box 9-1.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Chapter 9 - Identification and Ht
Across the Hyc
Text Box 9-1. Research Questions Revisited.
1 What are the toxicological properties of hydraulic fracturing fluid chemical additives?
2 • In a nationwide assessment, the EPA identified 1,076 chemicals that are used in hydraulic fracturing
3 fluids. This does not include chemicals classified as CBI, which the FracFocus database indicates are used
4 in more than 70% of wells. Chronic RfVs and/or OSFs from selected federal, state, and international
5 sources were available for 90 (8.4%) of these chemicals. From the federal sources alone, chronic RfVs
6 were available for 73 chemicals (6.8%), and OSFs were available for 15 chemicals (1.4%). RfVs and OSFs
7 were not available for the majority of chemicals that are used in hydraulic fracturing fluid, representing a
8 significant data gap with regards to hazard identification. Of the chemicals that have selected RfVs, health
9 effects include the potential for carcinogenesis, immune system effects, changes in body weight, changes
10 in blood chemistry, cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and
11 developmental toxicity.
12 • When considering the hazard evaluation of these chemicals on a nationwide scale, chemicals such as
13 propargyl alcohol stand out for their relatively lower RfVs, high frequency of use, and expected transport
14 and mobility in water. However, the FracFocus database indicates that most chemicals are used
15 infrequently on a nationwide scale; therefore, potential exposures to the majority of these chemicals are
16 more likely to be a local issue, rather than a national one. Accordingly, potential hazard and risk
17 considerations for hydraulic fracturing fluid chemical additives are best made on a site-specific, well-
18 specific basis.
19 What are the toxicological properties of hydraulic fracturing wastewater constituents?
20 • This assessment identified 134 chemicals that are reported to have been detected in hydraulic fracturing
21 flowback or produced water. These include chemicals that are added to hydraulic fracturing fluids during
22 the chemical mixing stage, as well as naturally occurring organic chemicals, metals, naturally occurring
23 radioactive material, and other subterranean chemicals that may be mobilized by the hydraulic fracturing
24 process. Chronic RfVs and/or OSFs from selected federal, state, and international sources were available
25 for 83 (62%) of these chemicals. From the federal sources alone, chronic RfVs were available for 70
26 chemicals (52%), and OSFs were available for 20 chemicals (15%). Of the chemicals that had selected
27 RfVs, health effects include the potential for carcinogenesis, immune system effects, changes in body
28 weight, changes in blood chemistry, pulmonary toxicity, neurotoxicity, liver and kidney toxicity, and
29 reproductive and developmental toxicity.
30 • In a hazard evaluation of flowback and produced water data, chemicals such as benzene, pyridine, and
31 naphthalene stood out for their relatively lower RfVs, high average concentrations, and expected
32 transport and mobility in water. However, the chemicals present in flowback and produced water are
33 likely to vary on a regional and well-specific basis as a result of geological differences as well as
34 differences between hydraulic fracturing fluid formulations. Therefore, potential hazard and risk
35 considerations are best made on a site-specific basis.
This document is a draft for review purposes only and does not constitute Agency policy.
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9.7. References for Chapter 9
Colborn, T: Kwiatkowski, C: Schultz, K: Bachran, M. (2011). Natural gas operations from a public health
perspective. Hum Ecol Risk Assess 17:1039-1056. http://dx.doi.org/10.1080/10807039.2011.605662
Finkel. M: Hays. I: Law. A. (2013). The shale gas boom and the need for rational policy. Am J Public Health
103: 1161-1163. http://dx.doi.org/10.2105/AIPH.2013.301285
Goldstein. BD: Brooks. BW: Cohen. SD: Gates. AE: Honeycutt. ME: Morris. IB: Orme-Zavaleta. I: Penning. TM:
Snawder, I. (2014). The role of lexicological science in meeting the challenges and opportunities of
hydraulic fracturing. Toxicol Sci 139: 271-283. http://dx.doi.org/10.1093/toxsci/kfu061
House of Representatives (U.S. House of Representatives). (2011). Chemicals used in hydraulic fracturing.
Washington, D.C.: U.S. House of Representatives, Committee on Energy and Commerce, Minority Staff.
http://democrats.energycommerce.house.gov/sites/default/files/documents/Hydraulic-Fracturing-
Chemicals-2011-4-18.pdf
Hristozov. PR: Zabeo. A: Foran. C: Isigonis. P: Critto. A: Marcomini. A: Linkov. I. (2014). A weight of evidence
approach for hazard screening of engineered nanomaterials. Nanotoxicology 8: 72-87.
http://dx.doi.org/10.3109/17435390.2012.750695
ludson. R: Richard. A: Dix. PI: Houck. K: Martin. M: Kavlock. R: Dellarco. V: Henry. T: Holderman. T: Sayre. P:
Tan. S: Carpenter. T: Smith. E. (2009). The toxicity data landscape for environmental chemicals [Review].
Environ Health Perspect 117: 685-695. http://dx.doi.org/10.1289/ehp.0800168
Kahrilas. GA: Blotevogel. I: Stewart. PS: Borch. T. (2015). Biocides in hydraulic fracturing fluids: a critical
review of their usage, mobility, degradation, and toxicity. Environ Sci Technol 49:16-32.
http://dx.doi.org/10.1021/es503724k
Kassotis, CD: Tillitt, DE: Wade Davis, I: Hormann, AM: Nagel, SC. (2014). Estrogen and androgen receptor
activities of hydraulic fracturing chemicals and surface and ground water in a drilling-dense region.
Endocrinology 155: 897-907. http://dx.doi.org/10.1210/en.2013-1697
Korfmacher. KS: Jones. WA: Malone. SL: Vinci. LF. (2013). Public health and high volume hydraulic fracturing.
New Solutions: A Journal of Environmental and Occupational Health Policy 23:13-31.
http://dx.doi.Org/10.2190/NS.23.l.c
Linkov. I: Welle. P: Loney. D: Tkachuk. A: Canis. L: Kim. IB: Bridges. T. (2011). Use of multicriteria decision
analysis to support weight of evidence evaluation. RiskAnal 31:1211-1225.
http://dx.doi.0rg/10.llll/i.1539-6924.2011.01585.x
McKenzie. LM: Guo. R: Witter. RZ: Savitz. DA: Newman. L: Adgate. IL. (2014). Birth outcomes and maternal
residential proximity to natural gas development in rural Colorado. Environ Health Perspect 122: 412-
417. http://dx.doi.org/10.1289/ehp.1306722
Mitchell. I: Pabon. P: Collier. ZA: Egeghy. PP: Cohen-Hubal. E: Linkov. I: Vallero. DA. (2013b). A decision
analytic approach to exposure-based chemical prioritization. PLoS ONE 8: e70911.
http://dx.doi.org/1371/journal.pone.0070911
Moudgal. Cl: Venkatapathy. R: Choudhury. H: Bruce. RM: Lipscomb. 1C. (2003). Application of QSTRs in the
selection of a surrogate toxicity value for chemical of concern. Environ Sci Technol 37: 5228-5235.
NRC (National Research Council). (2014). A framework to guide selection of chemical alternatives.
Washington, D.C.: The National Academies Press, http://www.nap.edu/catalog/18872/a-framework-to-
guide-selection-of-chemical-alternatives
Rupp. B: Appel. KE: Gundert-Remy. U. (2010). Chronic oral LOAEL prediction by using a commercially
available computational QSAR tool. Arch Toxicol 84: 681-688. http://dx.doi.org/10.1007/s00204-010-
0532-x
This document is a draft for review purposes only and does not constitute Agency policy.
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Across the Hyc
Stringfellow. WT: Domen. IK: Camarillo. MK: Sandelin. WL: Borglin. S. (2014). Physical, chemical, and
biological characteristics of compounds used in hydraulic fracturing. J Hazard Mater 275: 37-54.
http://dx.doi.0rg/10.1016/j.jhazmat.2014.04.040
U.S. EPA (U.S. Environmental Protection Agency). (2002a). A review of the reference dose and reference
concentration processes. (EPA/630/P-02/002F). Washington, DC: U.S. Environmental Protection Agency,
Risk Assessment Forum. http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=51717
U.S. EPA (U.S. Environmental Protection Agency). (2002b). Toxicological review of benzene (noncancerous
effects) [EPA Report]. (EPA/635/R-02/001F). Washington, DC.
U.S. EPA (U.S. Environmental Protection Agency). (2005). Pollution prevention (P2) framework [EPA Report].
(EPA-748-B-04-001). Washington, DC: Office of Pollution Prevention and Toxics.
http://www.epa.gov/oppt/sf/pubs/p2frame-june05a2.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2010). Toxicological review of acrylamide (CAS No. 79-06-
1) in support of summary information on the Integrated Risk Information System (IRIS) [EPA Report].
(EPA/635/R-07/008F). Washington, DC.
U.S. EPA (U.S. Environmental Protection Agency). (2011a). Design for the Environment program alternatives
assessment criteria for hazard evaluation (version 2.0). Washington, D.C.
http://www2.epa.gov/saferchoice/alternatives-assessment-criteria-hazard-evaluation
U.S. EPA (U.S. Environmental Protection Agency). (2011d). Terminology services (TS): Vocabulary catalog -
IRIS glossary. Available online at
http://ofmpub.epa.gov/sor internet/registry/termreg/searchandretrieve/glossariesandkeywordlists/se
arch.do?details=&glossaryName=IRIS%20Glossary (accessed May 21, 2015).
U.S. EPA (U.S. Environmental Protection Agency). (2012f). Study of the potential impacts of hydraulic
fracturing on drinking water resources: Progress report. (EPA/601/R-12/011). Washington, DC: U.S.
Environmental Protection Agency, Office of Research and Development.
http://nepis.epa.gov/exe/ZyPURL.cgi?Dockey=P100FH8M.txt
U.S. EPA (U.S. Environmental Protection Agency). (2013f). Toxicological review of 1,4-Dioxane (with
inhalation update) (CAS No. 123-91-1) in support of summary information on the Integrated Risk
Information System (IRIS) [EPA Report]. (EPA-635/R-11/003-F). Washington, DC.
U.S. EPA (U.S. Environmental Protection Agency). (2014a). Alternatives assessment for the flame retardant
decabromodiphenyl ether (DecaBDE). Washington, D.C. http://www2.epa.gov/saferchoice/partnership-
evaluate-flame-retardant-alternatives-decabde-publications
U.S. EPA (U.S. Environmental Protection Agency). (2014d). Flame retardant alternatives for
hexabromocyclododecane (HBCD) [EPA Report]. (EPA/740/R-14/001). Washington, D.C.
http://www2.epa.gov/saferchoice/partnership-evaluate-flame-retardant-alternatives-hbcd-publications
U.S. EPA (U.S. Environmental Protection Agency). (2015a). Analysis of hydraulic fracturing fluid data from the
FracFocus chemical disclosure registry 1.0 [EPA Report]. (EPA/601/R-14/003). Washington, D.C.: Office
of Research and Development, U.S. Environmental Protection Agency.
http://www2.epa.gov/hfstudy/analysis-hydraulic-fracturing-fluid-data-fracfocus-chemical-disclosure-
registry-1-pdf
Venkatapathy. R: Moudgal. Cl: Bruce. RM. (2004). Assessment of the oral rat chronic lowest observed adverse
effect level model in TOPKAT, a QSAR software package for toxicity prediction. J chem inf comput sci 44:
1623-1629. http://dx.doi.org/10.1021/ci049903s
Wattenberg, EV: Bielicki, IM: Suchomel, AE: Sweet, IT: Void, EM: Ramachandran, G. (In Press) Assessment of
the acute and chronic health hazards of hydraulic fracturing fluids. J Occup Environ Hyg.
http://dx.doi.org/10.1080/15459624.2015.1029612
This document is a draft for review purposes only and does not constitute Agency policy.
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Weinhold. B. (2012). The future of tracking: new rules target air emissions for cleaner natural gas production.
Environ Health Perspect 120: a272-a279. http://dx.doi.org/10.1289/ehp.120-a272
9.8. Annex
9.8.1. Calculation of Physicochemical Property Scores (MCDA Hazard Evaluation)
1 Section 9.5.2 describes how physicochemical properties scores were based on three subcriteria:
2 mobility, volatility, and persistence. These subcriteria scores were calculated as follows:
3 Mobility score: Chemical mobility in water was assessed based upon three physicochemical
4 properties: the octanol-water partition coefficient (Kow), the organic carbon-water partition
5 coefficient [Koc], and aqueous solubility. Kow and aqueous solubility were previously discussed in
6 Section 5.8.3. Koc is a partitioning coefficient that measures the amount of chemical that is adsorbed
7 onto soil organic carbon per the amount of chemical that is dissolved in water. Like Kow, Koc is
8 typically reported as a base-10 logarithm (log Koc}. From EPI Suite™, Koc was estimated using the
9 MCI Method. Chemicals with low Kow and Koc values are hydrophilic, and thus are more likely to
10 move with water rather than sorbing to soils or sediments. Chemicals with high aqueous solubility
11 are also more likely to move with water. Therefore, chemicals with low Kow, low Koc, or high aqueous
12 solubility were ranked as having greater potential to affect drinking water resources. Using the
13 thresholds designated in Table 9-5, each of these properties was assigned a score of 1-4. The
14 highest of these three scores was designated as the mobility score for each chemical.
15 Volatility score: Chemical volatility was assessed based on the Henry's law constant, which was
16 previously discussed in Section 5.8.3. Chemicals with low Henry's law constants are less likely to
17 leave water via volatilization, and were therefore ranked as having greater potential to impact
18 drinking water. Using the thresholds designated in Table 9-5, the Henry's law constant for each
19 chemical was assigned a score of 1-4. This value was designated as the volatility score for each
20 chemical.
21 Persistence score: Chemical persistence was assessed based on estimated half-life in water, which
22 describes how long a chemical will persist in water before it is transformed or degraded. From EPI
23 Suite™, half-life in water was estimated using the Level III Fugacity model. Chemicals with longer
24 half-lives are more persistent, and were therefore ranked as having greater potential to affect
25 drinking water. Using the thresholds designated in Table 9-5, the half-life of each chemical was
26 assigned a score of 1-4. This value was designated as the persistence score for each chemical.
27 For each chemical, the mobility score, volatility score, and persistence score (each on a scale of 1 to
28 4) were summed to calculate a total physicochemical score. The total scores were then
29 standardized by scaling to the highest and lowest scores observed in the subset of chemicals, using
30 the equation described in Section 9.5.2.4.
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9.8.2. Example of MCDA Score Calculation
1 For an example of how the MCDA scores were calculated, consider benzene. This demonstrates how
2 the MCDA score was calculated for benzene in the hazard evaluation of chemicals used in hydraulic
3 fracturing fluids:
4 • With regards to toxicity (Appendix G), benzene was found to have a federal RfD of 0.004
5 mg/kg-day (source: IRIS). Within the entire set of chemicals in this hazard evaluation,
6 federal RfDs ranged from 0.001 mg/kg-day [(E)-crotonaldehyde] to 20 mg/kg-day (1,2-
7 propylene glycol). The RfD of benzene fell in the lowest (most toxic) quartile of these
8 scores, and therefore was given a toxicity score of 4. When the results were standardized
9 to the highest score (4) and lowest score (1) within the set of chemicals, benzene was
10 calculated to have a toxicity score of 1, as follows:
11 1 = (4-I)/(4-1)
12 • Benzene was used in 0.0056% of wells nationwide (U.S. EPA. 2015a). This usage frequency
13 falls in the lowest quartile of chemicals, and therefore benzene was given an occurrence
14 score of 1. When the results were standardized to the highest score (4) and lowest score
15 (1) within the set of chemicals, benzene was calculated to have an occurrence score of 0, as
16 follows:
17 0 = (l-l)/(4-l)
18 • Based on physicochemical properties, benzene received a mobility score of 4 (log Kow =
19 2.13; logKoc = 1.75; solubility = 2000 mg/1), a volatility score of 2 (Henry's law constant =
20 0.00555), and a persistence score of 2 (half-life in water = 37.5 days). These scores sum to
21 a total physicochemical properties score of 8. Within the entire set of chemicals in this
22 hazard evaluation, several chemicals received total scores of 9, which was the highest
23 observed score. Cumene received a total score of 6, which was the lowest observed score.
24 When the results were standardized to the high score (9) and low score (6) using the
25 equation above, benzene was calculated to have a physicochemical properties score of
26 0.67 as follows:
27 0.67 = (8-6)/(9-6)
28 To calculate the total hazard potential score for benzene, the physicochemical properties score,
29 toxicity score, and occurrence score were summed for a total of 1.67. These results can be seen in
30 Table 9-7, which shows the MCDA results for chemicals used in hydraulic fracturing fluid.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Chapter 10- Synthesis
Chapter 10
Synthesis
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Hydraulic Fracturing Drinking Water Assessment Chapter 10 - Synthesis
10. Synthesis
1 In this assessment, we examined the potential for hydraulic fracturing for oil and natural gas to
2 change the quality or quantity of drinking water resources, and identified factors that affect the
3 frequency or severity of potential impacts. Drinking water resources are defined broadly in this
4 report as any body of ground water or surface water that now serves, or in the future could serve,
5 as a source of drinking water for public or private use. We assessed potential effects on drinking
6 water resources from both routine operations and potential accidents. Impacts were defined as any
7 change in the quality or quantity of drinking water resources. Where possible, we identified the
8 mechanisms responsible or potentially responsible for any impacts. For example, a spill of
9 hydraulic fracturing fluid is a mechanism by which drinking water resources could be impacted.
10 We did this by following water through the hydraulic fracturing water cycle: (1) the withdrawal of
11 ground or surface water needed for hydraulic fracturing fluids; (2) the mixing of water, chemicals,
12 and proppant on the well pad to create the hydraulic fracturing fluid; (3) the injection of hydraulic
13 fracturing fluids into the well to fracture the geologic formation; (4) the management of flowback
14 and produced water, both on the well pad and in transit for reuse, treatment, or disposal; and (5)
15 the reuse, treatment and discharge, or disposal of hydraulic fracturing wastewater.
16 In this chapter, we summarize major findings of the assessment, organized by each stage of the
17 hydraulic fracturing water cycle (Section 10.1); highlight key uncertainties related to these major
18 findings (Section 10.2); and discuss the assessment's overall conclusions (Section 10.3) and
19 potential uses (Section 10.4).
10.1.Major Findings
20 From our assessment, we conclude there are above and below ground mechanisms by which
21 hydraulic fracturing activities have the potential to impact drinking water resources. These
22 mechanisms include water withdrawals in times of, or in areas with, low water availability; spills of
23 hydraulic fracturing fluids and produced water; fracturing directly into underground drinking
24 water resources; below ground migration of liquids and gases; and inadequate treatment and
25 discharge of wastewater.
26 We did not find evidence that these mechanisms have led to widespread, systemic impacts on
27 drinking water resources in the United States. Of the potential mechanisms identified in this report,
28 we found specific instances where one or more mechanisms led to impacts on drinking water
29 resources, including contamination of drinking water wells. The number of identified cases,
30 however, was small compared to the number of hydraulically fractured wells.
31 This finding could reflect a rarity of effects on drinking water resources, but may also be due to
32 other limiting factors. These factors include: insufficient pre- and post-fracturing data on the quality
33 of drinking water resources; the paucity of long-term systematic studies; the presence of other
34 sources of contamination precluding a definitive link between hydraulic fracturing activities and an
35 impact; and the inaccessibility of some information on hydraulic fracturing activities and potential
36 impacts.
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Hydraulic Fracturing Drinking Water Assessment Chapter 10 - Synthesis
1 Below, we provide a synopsis of the assessment's key findings, organized according to each stage of
2 the hydraulic fracturing water cycle. We provide answers to the research questions presented in
3 the Study Plan and Chapter 1. Results from Chapter 9 (Hazard Evaluation and Identification of
4 Chemicals across the Hydraulic Fracturing Water Cycle) are included in the Chemical Mixing and
5 the Flowback and Produced Water sections. While some citations are provided here, individual
6 chapters can be consulted for additional detail and citations.
10.1.1. Water Acquisition (Chapter 4)
7 Water is a major component of nearly all hydraulic fracturing operations. It typically makes up
8 almost 90% or more of the fluid injected into a well, and each hydraulically fractured well requires
9 thousands to millions of gallons of water. Cumulatively, hydraulic fracturing activities in the United
10 States used on average 44 billion gal of water a year in 2011 and 2 012, according to the EPA's
11 analysis of FracFocus 1.0 disclosures. Although this represents less than 1% of total annual water
12 use and consumption at this scale, water withdrawals could potentially impact the quantity and
13 quality of drinking water resources at more local scales.
Research Questions: Water Acquisition
• What are the types of water used for hydraulic fracturing?
14 Water for hydraulic fracturing typically comes from surface water, ground water, or reused
15 hydraulic fracturing waste water. Hydraulic fracturing operations in the eastern United States
16 generally rely on surface water, while operations in the more semi-arid to arid western states
17 generally use mixed supplies of surface and ground water. In the Marcellus Shale in Pennsylvania,
18 for example, most water used for hydraulic fracturing originates from surface water, whereas
19 surface and ground water are used in approximately equal proportions in the Barnett Shale in
20 Texas (see Figure 10-la,b). In areas that lack available surface water (e.g., western Texas), ground
21 water supplies most of the water needed for hydraulic fracturing.
22 Across the United States, the vast majority of water used in hydraulic fracturing is fresh, although
23 operators also make use of lower-quality water, including reused hydraulic fracturing waste water.
24 Based on available data, the median reuse of hydraulic fracturing wastewater as a percentage of
25 injected volumes is 5% nationally, with the percentage varying by location.: Available data on reuse
26 trends indicate increased reuse of wastewater over time in both Pennsylvania and West Virginia.
27 Reuse as a percentage of injected volumes is lower in other areas, including regions with more
28 water stress, likely because of the availability of disposal wells. For example, reused wastewater is
29 approximately 18% of injected volumes in the Marcellus Shale in Pennsylvania's Susquehanna
30 River Basin, whereas it is approximately 5% in the Barnett Shale in Texas (see Figure 10-la,b).
i Reused wastewater as a percentage of injected volumes differs from the percentage of wastewater that is managed
through reuse, as opposed to other wastewater management options. For example, in the Marcellus Shale in
Pennsylvania, approximately 18% of injected water is reused produced water, while approximately 70% or more of
wastewater is managed through reuse (see Figure 10-la).
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Hydraulic Fracturing Drinking Water Assessment
Chapter 10 - Syn th esis
Water Source
Well Wastewater Management
420,000 -1.3 million gal produced d
• Surface Water Reused Water Ground Water
Up to 10-30%
15% e _
60-90% '
- Reuse CWT • U 1C disposal well
Most of the injected fluid is retained
in the subsurface: Produced water
volumes over lOyearsare
approximately 10-30% of the original
injected fluid volume"
Water Source
- 4.S million gal
Well
Wastewater Management
47.5%
Produced
water volumes
over 3
years are
approximately
the same as
the original
injected fluid
volume"
• Surface Water Reused Water Ground Water -
UIC disposal well
Figure 10-1. Water budgets representative of practices in the Marcellus Shale in the
Susquehanna River Basin in Pennsylvania (a) and the Barnett Shale in Texas (b).
Pie size and arrow thickness represent the relative volume of water as it flows through the hydraulic
fracturing water cycle. Wastewater going to a centralized waste treatment (CWT) facility may be
either discharged to surface water or reused. Wastewater going to an underground injection control
(UIC) well is disposed of below ground. These examples represent typical water management practices
as depicted for the most recent time period reviewed by this assessment. They do not represent any
specific well. Sources for 10-la: (a) Table 4-1 (Hansen et al., 2013); (b) Table 4-3 (U.S. EPA, 2015c); (c)
Appendix Table B-5 (Hansen et al., 2013); (d) Table 7-2 [Ziemkiewicz etal.. 2014]—Note: produced
water value from the West Virginia portion of the Marcellus; it provided the longest-term
measurement of produced water volumes; (e) Figure 8-4 [PA PEP. 2015a] and Table 8-5 [Ma et al..
2014: Shaffer etal.. 2013]. Sources for 10-lb: (a) Appendix Table B-5 (U.S. EPA, 2015a; Nicot et al.,
2012; Nicot etal., 2011); (b) Table 4-3 (Nicot et al., 2014); (c) Table 4-1 (Nicot et al., 2012); d: Table 7-2
(Nicot etal., 2014); (e) Table 8-5 (Nicot et al., 2012); (f) Calculated by subtracting reuse values from
100% (see Table 8-5).
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Hydraulic Fracturing Drinking Water Assessment Chapter 10 - Synthesis
• How much water is used per well?
1 The national median volume of water used per hydraulically fractured well is approximately 1.5
2 million gal (5.7 million L), according to the EPA's analysis of FracFocus 1.0 disclosures. This
3 estimate likely represents a wide variety of fractured well types, including vertical wells that
4 generally use much less water per well than horizontal wells. Thus, published estimates for
5 horizontal shale gas wells are typically higher (e.g., approximately 4 million gal (Vengosh etal.,
6 2014]]. There is also wide variation within and among states and basins in the median water
7 volumes used per well, from more than 5 million gal (19 million L] in Arkansas, Louisiana and West
8 Virginia to less than 1 million gal (3.8 million L] in California, New Mexico, and Utah, among others.
9 This variation results from several factors, including well length, formation geology, and fracturing
10 fluid formulation.
• How might cumulative water withdrawals for hydraulic fracturing affect drinking water
quantity?
11 Cumulatively, hydraulic fracturing uses billions of gallons of water each year at the national and
12 state scales, and even in some counties. As noted above, hydraulic fracturing water use and
13 consumption are generally less than 1% of total annual water use and consumption at these scales.
14 However, there are a few counties in the United States where these percentages are higher. For
15 2011 and 2012, annual hydraulic fracturing water use was 10% or more compared to 2010 total
16 annual water use in 6.5% of counties with FracFocus 1.0 disclosures analyzed by the EPA, 30% or
17 more in 2.2% of counties, and 50% or more in 1.0% of counties. Consumption estimates followed
18 the same general pattern. For these counties, hydraulic fracturing is a relatively large user and
19 consumer of water.
20 High fracturing water use or consumption alone does not necessarily result in impacts to drinking
21 water resources. Rather, impacts result from the combination of water use/consumption and water
2 2 availability at local scales. In our survey of published literature, we did not find a case where
23 hydraulic fracturing water use or consumption alone caused a drinking water well or stream to run
24 dry. This could indicate an absence of effects or a lack of documentation in the literature we
25 reviewed. Additionally, water availability is rarely impacted by just one use or factor alone. In
26 Louisiana, for example, the state requested hydraulic fracturing operations switch from ground to
27 surface water, due to concerns that ground water withdrawals for fracturing could, in combination
28 with other uses, adversely affect drinking water supplies.
29 The potential for impacts to drinking water resources from hydraulic fracturing water withdrawals
30 is highest in areas with relatively high fracturing water use and low water availability. Southern
31 and western Texas are two locations where hydraulic fracturing water use, low water availability,
32 drought, and reliance on declining ground water has the potential to affect the quantity of drinking
33 water resources. Any impacts are likely to be realized locally within these areas. In a detailed case
34 study of southern Texas, Scanlonetal. (2014] observed generally adequate water supplies for
35 hydraulic fracturing, except in specific locations. They found excessive drawdown of local ground
36 water in a small proportion (approximately 6% of the area] of the Eagle Ford Shale. They suggested
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1 water management, particularly a shift towards brackish water use, could minimize potential future
2 impacts to fresh water resources.
3 The potential for impacts to drinking water quantity due to hydraulic fracturing water use appears
4 to be lower—but not eliminated—in other areas of the United States. Future problems could arise if
5 hydraulic fracturing increases substantially in areas with low water availability, or in times of water
6 shortages. In detailed case studies in western Colorado and northeastern Pennsylvania, the EPA did
7 not find current impacts, but did conclude that streams could be vulnerable to water withdrawals
8 from hydraulic fracturing. In northeast Pennsylvania, water management, such as minimum stream
9 flow requirements, limits the potential for impacts, especially in small streams. In western North
10 Dakota, ground water is limited, but the industry may have sufficient supplies of surface water from
11 the Missouri River system. These location-specific examples emphasize the need to focus on
12 regional and local dynamics when considering potential impacts of hydraulic fracturing water
13 acquisition on drinking water resources.
• What are the possible impacts of water withdrawals for hydraulic fracturing on water quality?
14 Water withdrawals for hydraulic fracturing, similar to all water withdrawals, have the potential to
15 alter the quality of drinking water resources. Ground water withdrawals exceeding natural
16 recharge rates decrease water storage in aquifers, potentially mobilizing contaminants or allowing
17 the infiltration of lower quality water from the land surface or adjacent formations. Withdrawals
18 could also decrease ground water discharge to streams, potentially affecting surface water quality.
19 Areas with large amounts of sustained ground water pumping are most likely to experience
2 0 impacts, particularly drought-prone regions with limited ground water recharge.
21 Surface water withdrawals also have the potential to affect water quality. Withdrawals may lower
22 water levels and alter stream flow, potentially decreasing a stream's capacity to dilute
23 contaminants. Case studies by the EPA show that streams can be vulnerable to changes in water
24 quality due to water withdrawals, particularly smaller streams and during periods of low flow.
2 5 Management of the rate and timing of surface water withdrawals has been shown to help mitigate
2 6 potential impacts of hydraulic fracturing withdrawals on water quality.
10.1.2. Chemical Mixing (Chapter 5)
27 Hydraulic fracturing fluids are developed to perform specific functions, including: create and
2 8 extend fractures, transport proppant, and place proppant in the fractures. The fluid generally
29 consists of three parts: (1) the base fluid, which is the largest constituent by volume and is typically
30 water; (2) the additives, which can be a single chemical or a mixture of chemicals; and (3) the
31 proppant Additives are chosen to serve a specific purpose (e.g., adjust pH, increase viscosity, limit
32 bacterial growth). Chemicals generally comprise a small percentage (typically 2% or less) of the
33 overall injected fluid volume. Because over one million gallons of fluid are typically injected per
34 well, thousands of gallons of chemicals can be potentially stored on-site and used during hydraulic
35 fracturing activities.
3 6 On-site storage, mixing, and pumping of chemicals and hydraulic fracturing fluids have the potential
37 to result in accidental releases, such as spills or leaks. Potential impacts to drinking water resources
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1 from spills of hydraulic fracturing fluids and chemicals depend on the characteristics of the spills,
2 and the fate, transport, and the toxicity of chemicals spilled.
Research Questions: Chemical Mixing
• What is currently known about the frequency, severity, and causes of spills of hydraulic
fracturing fluids and additives?
3 The frequency of on-site spills from hydraulic fracturing could be estimated for two states, but not
4 for operations nationally or for other areas. Frequency estimates from data and literature ranged
5 from one spill for every 100 wells in Colorado to between approximately 0.4 and 12.2 spills for
6 every 100 wells in Pennsylvania.1 These estimates include spills of hydraulic fracturing fluids and
7 chemicals, and produced water reported in state databases. Available data generally precluded
8 estimates of hydraulic fracturing fluid and/or chemical spill rates separately from estimates of an
9 overall spill frequency. It is unknown whether these spill estimates are representative of national
10 occurrences. If the estimates are representative, the number of spills nationally could range from
11 approximately 100 to 3,700 spills annually, assuming 25,000 to 30,000 new wells are fractured per
12 year.
13 The EPA characterized volumes and causes of hydraulic fracturing-related spills identified from
14 selected state and industry data sources. The spills occurred between January 2006 and April 2012
15 in 11 states and included 151 cases in which fracturing fluids or chemicals spilled on or near a well
16 pad. Due to the methods used for the EPA's characterization of spills, these cases were likely a
17 subset of all fracturing fluid and chemical spills during the study's time period. The reported
18 volume of fracturing fluids or chemicals spilled ranged from 5 gal to more than 19,000 gal (19 to
19 72,000 L), with a median volume of 420 gal (1,600 L) per spill. Spill causes included equipment
20 failure, human error, failure of container integrity, and other causes (e.g., weather and vandalism).
21 The most common cause was equipment failure, specifically blowout preventer failure, corrosion,
22 and failed valves. More than 30% of the 151 fracturing fluid or chemical spills were from fluid
23 storage units (e.g., tanks, totes, and trailers).
• What are the identities and volumes of chemicals used in hydraulic fracturing fluids, and how
might this composition vary at a given site and across the country?
24 In this assessment, we identified a list of 1,076 chemicals used in hydraulic fracturing fluids. This is
25 a cumulative list over multiple wells and years. These chemicals include acids, alcohols, aromatic
26 hydrocarbons, bases, hydrocarbon mixtures, polysaccharides, and surfactants. According to the
27 EPA's analysis of disclosures to FracFocus 1.0, the number of unique chemicals per well ranged
28 from 4 to 28, with a median of 14 unique chemicals per well.
29 Our analysis indicates that chemical use varies and that no single chemical is used at all well sites
30 across the country, although several chemicals are widely used. Methanol, hydrotreated light
1 Spill frequency estimates are for a given number of wells over a given period of time. These are not annual estimates nor
are they for the lifetime of a well.
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1 petroleum distillates, and hydrochloric acid were reported as used in 65% or more of wells,
2 according to FracFocus 1.0 disclosures analyzed by the EPA. Only 32 chemicals, excluding water,
3 quartz, and sodium chloride, were used in more than 10% of wells according to the EPA's analysis
4 of FracFocus disclosures. The composition of hydraulic fracturing fluids varies by state, by well, and
5 within the same service company and geologic formation. This variability likely results from several
6 factors, including the geology of the formation, the availability and cost of different chemicals, and
7 operator preference.
8 Estimates from the EPA's database developed from FracFocus 1.0 suggest median volumes of
9 individual chemicals injected per well range from a few gallons to thousands of gallons, with an
10 overall median of 650 gal (2,500 L) per chemical per well. Based on this overall median and
11 assuming 14 unique chemicals are used per well, an estimated 9,100 gal (34,000 L) of chemicals
12 may be injected per well. Given thatthe number of chemicals per well ranges from 4 to 28, the
13 estimated volume of chemicals injected per well may range from approximately 2,600 to 18,000 gal
14 (9,800 to 69,000 L).
• What are the chemical, physical, and toxicological properties of hydraulic fracturing chemical
additives?
15 Measured or estimated physicochemical properties were obtained for 453 chemicals of the toal
16 1,076 chemicals reported in hydraulic fracturing fluids. We could not estimate physicochemical
17 properties for the inorganic chemicals or mixtures. The 453 chemicals have a wide range of
18 physicochemical properties.
19 Properties affecting the likelihood of a spilled chemical reaching and impacting a drinking water
20 resource, include: mobility, solubility, and volatility. Of the 453 chemicals for which
21 physicochemical properties were available, 18 of the top 20 most mobile ones were reported in the
22 EPA's FracFocus 1.0 database for 2% or less of wells. Choline chloride and tetrakis (hydroxymethyl)
23 phosphonium were exceptions and were reported in 14% and 11% of wells, respectively. These
24 two chemicals appear to be relatively more common, and, if spilled, would move quickly through
25 the environment with the flow of water. The majority of the 453 chemicals associate strongly with
26 soils and organic materials, suggesting the potential for these chemicals to persist in the
27 environment as long-term contaminants. Many of the 453 chemicals fully dissolve in water, but
2 8 their aqueous solubility varies greatly. Few of the chemicals volatilize, and thus a large proportion
29 of most hydraulic fracturing chemicals tend to remain in water.
30 Oral reference values and oral slope factors meeting the criteria used in this assessment were not
31 available for the majority of chemicals used in hydraulic fracturing fluids, representing a significant
32 data gap for hazard identification.u Reference values and oral slope factors are important for
1 A reference value is an estimate of an exposure to the human population (including susceptible subgroups) for a given
duration that is likely to be without an appreciable risk of adverse health effects over a lifetime. Reference value is a
generic term not specific to a given route of exposure.
2 An oral slope factor is an upper-bound, approximating 95% confidence limit, on the increased cancer risk from a lifetime
oral exposure to an agent.
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1 understanding the potential human health effects resulting from exposure to a chemical. Chronic
2 oral reference values and/or oral slope factors from selected federal, state, and international
3 sources were available for 90 (8%) of the 1,076 chemicals used in hydraulic fracturing fluids. From
4 U.S. federal sources alone, chronic oral reference values were available for 73 chemicals (7%) of the
5 1,076 chemicals, and oral slope factors were available for 15 chemicals (1%). Of the 32 chemicals
6 reported as used in at least 10% of wells in the EPA's FracFocus database (excluding water, quartz,
7 and sodium chloride), seven (21%) have a federal chronic oral reference value. Oral reference
8 values and oral slope factors are a key component of the risk assessment process, although
9 comprehensive risk assessments that characterize the health risk associated with exposure to these
10 chemicals are not available.
11 Of the chemicals that had values available, the health endpoints associated with those values
12 include the potential for carcinogenesis, immune system effects, changes in body weight, changes in
13 blood chemistry, cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and
14 developmental toxicity. However, it is important to note that evaluating any potential risk to human
15 populations would require knowledge of the specific chemicals that are present at a particular site,
16 whether or not humans are exposed to those chemicals and, if so, at what levels and for what
17 duration, and the toxicity of the chemicals. Since most chemicals are used infrequently on a
18 nationwide basis, potential exposure is likely to be a local or regional issue, rather than a national
19 issue. Accordingly, consideration of hazards and risks associated with these chemical additives
20 would be most useful on a site-specific basis and is beyond the scope of this assessment.
• If spills occur, how might hydraulic fracturing chemical additives contaminate drinking water
resources?
21 There are several mechanisms by which a spill can potentially contaminate drinking water
22 resources. These include overland flow to nearby surface water, soil contamination and eventual
23 transport to surface water, and infiltration and contamination of underlying ground water. Of the
24 151 spills characterized by the EPA, fluids reached surface water in 13 (9% of 151) cases and soil in
25 97 (64%) cases. None of the spills of hydraulic fracturing fluid were reported to have reached
26 ground water. This could be due to an absence of impact; however, it can take several years for
27 spilled fluids to infiltrate soil and leach into ground water. Thus, it may not be immediately
28 apparent whether a spill has reached ground water or not
29 Based on the relative importance of each of these mechanisms, impacts have the potential to occur
30 quickly, be delayed short or long periods, or have a continual effect over time. In Kentucky, for
31 example, a spill impacted a surface water body relatively quickly when hydraulic fracturing fluid
32 entered a creek, significantly reducing the water's pH and increasing its conductivity (Papoulias
33 and Velasco. 20131
10.1.3. Well Injection (Chapter 6)
34 Hydraulic fracturing fluids are injected into oil or gas wells under high pressures. The fluids flow
35 through the well (commonly thousands of feet below the surface) into the production zone (i.e., the
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1 geologic formation being fractured) where the fluid injection pressures are sufficient to create
2 fractures in the rock.
3 There are two major subsurface mechanisms by which the injection of fluid and the creation and
4 propagation of fractures can lead to contamination of drinking water resources: (1) the unintended
5 movement of liquids or gases out of the production well or along the outside of the production well
6 into a drinking water resource via deficiencies in the well's casing or cement, and (2) the
7 unintended movement of liquids or gases from the production zone through subsurface geologic
8 formations into a drinking water resource. Combinations of these two mechanisms are also
9 possible.
Research Questions: Well Injection
• How effective are current well construction practices at containing fluids- both liquids and
gases - before, during, and after fracturing?
10 Production wells are constructed to access and convey hydrocarbons from the formations in which
11 they are found to the surface, and to isolate fluid-bearing zones (containing oil, gas, or water) from
12 each other. Typically, multiple casings are emplaced and cemented along the wellbore to protect
13 and isolate the oil and/or natural gas from the formations it must travel through to reach the
14 surface.
15 Below ground drinking water resources are often separated from the production well using casing
16 and cement. Cemented surface casing, in particular, is an important well construction feature for
17 isolating drinking water resources from liquids and gases that may move through the subsurface. A
18 limited risk modeling study of selected injection wells in the Williston Basin in North Dakota
19 suggests that the risk of aquifer contamination from leaks inside the well to the drinking water
20 resource decreases by a factor of approximately one thousand when surface casing extends below
21 the bottom of the drinking water resource [Michie and Koch. 1991). Most wells used in hydraulic
22 fracturing operations have casing and a layer of cement to protect drinking water resources, but
23 there are exceptions: a survey conducted by the EPA of oil and gas production wells hydraulically
24 fractured by nine oil and gas service companies in 2009 and 2010 estimated that at least 3% of the
25 wells (600 out of 23,000 wells) did not have cement across a portion of the casing installed through
26 the protected ground water resource identified by well operators. The absence of cement does not
27 in and of itself lead to an impact However, it does reduce the overall number of casing and cement
28 barriers fluids must travel through to reach ground water resources.
29 Impacts to drinking water resources from subsurface liquid and gas movement may occur if casing
30 or cement are inadequately designed or constructed, or fail. There are several examples of these
31 occurrences in hydraulically fractured wells that have or may have resulted in impacts to drinking
3 2 water resources. In one example, an inner string of casing burst during hydraulic fracturing, which
3 3 resulted in a release of fluids on the land surface and possibly into the aquifer near Killdeer, North
34 Dakota. The EPA found that, based on the data analysis performed for the study, the only potential
3 5 source consistent with conditions observed in two impacted monitoring wells was the blowout that
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1 occurred during hydraulic fracturing [U.S. EPA, 2015)]. In other examples, inadequately cemented
2 casing has contributed to impacts to drinking water resources. In Bainbridge, Ohio, inadequately
3 cemented casing in a hydraulically fractured well contributed to the buildup of natural gas and high
4 pressures along the outside of a production well. This ultimately resulted in movement of natural
5 gas into local drinking water aquifers [Bair etal., 2010: ODNR, 2008]. In the Mamm Creek gas field
6 in Colorado, inadequate cement placement in a production well allowed methane and benzene to
7 migrate along the production well and through natural faults and fractures to drinking water
8 resources [Science Based Solutions LLC. 2014: Crescent. 2011: COGCC. 2004]. These cases illustrate
9 how construction issues, sustained casing pressure, and the presence of natural faults and fractures
10 can work together to create pathways for fluids to migrate toward drinking water resources.
11 Fracturing older wells may also increase the potential for impacts to drinking water resources via
12 movement of liquids and gases from the inside of the production well or along the outside of the
13 production well to ground water resources. The EPA estimated that 6% of 23,000 oil and gas
14 production wells were drilled more than 10 years before being hydraulically fractured in 2009 or
15 2010. Although new wells can be designed to withstand the stresses associated with hydraulic
16 fracturing operations, older wells may not have been built or tested to the same specifications and
17 their reuse for this purpose could be of concern. Moreover, aging and use of the well can contribute
18 to casing degradation, which can be accelerated by exposure to corrosive chemicals such as
19 hydrogen sulfide, carbonic acid, and brines.
• Can subsurface migration of fluids- both liquids and gases- to drinking water resources occur,
and what local geologic or artificial features might allow this?
20 Physical separation between the production zone and drinking water resources can help protect
21 drinking water. Many hydraulic fracturing operations target deep formations such as the Marcellus
22 Shale or the Haynesville Shale (Louisiana/Texas], where the vertical distance between the base of
23 drinking water resources and the top of the shale formation may be a mile or greater. Numerical
24 modeling and microseismic studies based on a Marcellus Shale-like environment suggest that
25 fractures created during hydraulic fracturing are unlikely to extend upward from these deep
26 formations into shallow drinking water aquifers.
27 Not all hydraulic fracturing is performed in zones that are deep below drinking water resources.
28 For example, operations in the Antrim Shale (Michigan] and the New Albany Shale
29 (Illinois/Indiana/Kentucky] take place at shallower depths (100 to 1,900 ft or 30 to 579 m], with
30 less vertical separation between the formation and drinking water resources (NETL. 2013: GWPC
31 and ALL Consulting. 2009]. The EPA's survey of oil and gas production wells hydraulically fractured
32 by nine service companies in 2009 and 2010 estimated that 20% of 23,000 wells had less than
33 2,000 ft (610 m] of measured distance between the point of shallowest hydraulic fracturing and the
34 base of the protected ground water resources reported by well operators.
35 There are also places in the subsurface where oil and gas resources and drinking water resources
36 co-exist in the same formation. Evidence indicates that hydraulic fracturing occurs within these
37 formations. This results in the introduction of fracturing fluids into formations that may currently
38 serve, or in the future could serve, as a source of drinking water for public or private use. According
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1 to the data examined, the overall frequency of occurrence of this practice appears to be low, with
2 the activity generally concentrated in some areas in the western United States. The practice of
3 injecting fracturing fluids into a formation that also contains a drinking water resource directly
4 affects the quality of that water, since some of the fluid likely remains in the formation following
5 hydraulic fracturing. Hydraulic fracturing in a drinking water resource is a concern in the short-
6 term (should there be people currently using these zones as a drinking water supply) and the long-
7 term (if drought or other conditions necessitate the future use of these zones for drinking water).
8 Liquid and gas movement from the production zone to underground drinking water resources may
9 also occur via other production wells or injection wells near hydraulic fracturing operations.
10 Fractures created during hydraulic fracturing can intersect nearby wells or their fracture networks,
11 resulting in the flow of fluids into those wells. These well communications, or "frac hits," are more
12 likely to occur if wells are close to each other or on the same well pad. In the Woodford Shale in
13 Oklahoma, the likelihood of well communication was less than 10% between wells more than 4,000
14 ft (1,219 m) apart, but rose to nearly 50% between wells less than 1,000 ft (305 m) apart (Ajani and
15 Kelkar. 2012). If an offset well is not able to withstand the stresses applied during the hydraulic
16 fracturing of a neighboring well, well components may fail, which could result in a release of fluids
17 at the surface from the offset well. The EPA identified incidents in which surface spills of hydraulic
18 fracturing-related fluids were attributed to well communication events.
19 Older or inactive wells—including oil and gas wells, injection wells, or drinking water wells—near
20 the hydraulic fracturing operation may pose an even greater potential for impacts. A study in
21 Oklahoma found that older wells were more likely to be negatively affected by the stresses applied
22 by hydraulic fracturing in neighboring wells (Ajani and Kelkar. 2012). In some cases, inactive wells
23 in the vicinity of hydraulic fracturing activities may not have been plugged properly—many wells
24 plugged before the 1950s were done so with little or no cement. The Interstate Oil and Gas Compact
25 Commission estimates that over one million wells may have been drilled in the United States prior
26 to a formal regulatory system being in place, and the status and location of many of these wells are
27 unknown (IOGCC, 2008). State programs exist to plug identified inactive wells, and work is on-
28 going to identify and address such wells.
10.1.4. Flowback and Produced Water (Chapter 7)
29 Water, of variable quality, is a byproduct of oil and gas production. After hydraulic fracturing, the
30 injection pressure is released and water flows back from the well. Initially this water is similar to
31 the hydraulic fracturing fluid, but as time goes on the composition is affected by the characteristics
32 of the formation and possible reactions between the formation and the fracturing fluid. Water
33 initially produced from the well after hydraulic fracturing is sometimes called flowback in the
34 literature, and the term appears in this assessment However, hydraulic fracturing fluids and any
35 formation water returning to the surface are often referred to collectively as produced water. This
36 definition of produced water is used in this assessment
37 The amount of produced water varies, but typically averages 10% to 25% of injected volumes,
38 depending upon the amount of time since fracturing and the particular well (see Figure 10-la).
39 However, there are exceptions to this, such as in the Barnett Shale in Texas where the total volume
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1 of produced water can equal or exceed the injected volume of hydraulic fracturing fluid (see Figure
2 10-Ib). Flow rates are generally high initially, and then decrease over time throughout oil or gas
3 production.
4 Impacts on drinking water resources have the potential to occur if produced water is spilled and
5 enters surface water or ground water. Environmental transport of chemical constituents in
6 produced water depends on the characteristics of the spill (e.g., volume and duration), the
7 composition of spilled fluids, and the characteristics of the surrounding environment.
Research Questions: Flow/back and Produced Water
• What is currently known about the frequency, severity, and causes of spills of flow/back and
produced water?
8 Surface spills of produced water from hydraulically fractured wells have occurred. As noted in the
9 Chemical Mixing section above, the frequency of on-site spills from hydraulic fracturing activities
10 could be estimated for two states, but not nationally. Estimates of spill frequencies at hydraulic
11 fracturing sites in Colorado and Pennsylvania, including spills of produced water, ranged from
12 approximately 0.4 to 12.2 spills per 100 wells. Available data generally precluded estimates of
13 produced water spill rates separately from estimates of overall spill frequency. Away from the well,
14 produced water spills from pipelines and truck transport also have the potential to impact drinking
15 water resources.
16 The EPA characterized spill volumes and causes for 225 cases in which produced water spilled on
17 or near a well pad. These spills occurred between January 2006 and April 2012 in 11 states. The
18 median reported volume per produced water spill was 990 gallons (3,750 L), more than double that
19 for spills of hydraulic fracturing fluids and chemicals. The causes of produced water spills were
20 reported as human error, equipment failure, container integrity failure, miscellaneous causes (e.g.,
21 well communication), and unknown causes. Most of the total volume spilled (74%) for all 225 cases
2 2 combined was caused by a failure of container integrity.
• What is the composition of hydraulic fracturing flowback and produced water, and what
factors might influence this composition?
23 A combination of factors influence the composition of produced water, including: the composition
24 of injected hydraulic fracturing fluids, the type of formation fractured, subsurface processes, and
25 residence time. The initial chemical composition of produced water primarily reflects the chemistry
26 of the injected fluids. At later times, the chemical composition of produced water reflects the
2 7 geochemistry of the fractured formation.
28 Produced water varies in quality from fresh to highly saline, and can contain high levels of major
29 anions and cations, metals, organics, and naturally occurring radionuclides. Produced water from
30 shale and tight gas formations typically contains high levels of total dissolved solids (TDS) and ionic
31 constituents (e.g., bromide, calcium, chloride, iron, potassium, manganese, magnesium, and
32 sodium). Produced water also may contain metals (e.g., barium, cadmium, chromium, lead, and
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1 mercury), and organic compounds such as benzene. Produced water from coalbed methane
2 typically has much lower TDS levels compared to other produced water types, particularly if the
3 coalbed was deposited under fresh water conditions.
4 We identified 134 chemicals that have been detected in hydraulic fracturing produced water. These
5 include chemicals added during the chemical mixing stage, as well as naturally occurring organic
6 chemicals and radionuclides, metals, and other constituents of subsurface rock formations
7 mobilized by the hydraulic fracturing process. Data on measured chemical concentrations in
8 produced water were available for 75 of these 134 chemicals.
9 Most of the available data on produced water content are for shale and coalbed methane
10 formations, while less data are available for tight formations, such as sandstones. The composition
11 of produced water must be determined through sampling and analysis, both of which have
12 limitations—the former due to challenges in accessing production equipment, and the latter due to
13 difficulties identifying target analytes before analysis and the lack of appropriate analytical
14 methods. Most current data are for inorganic chemicals, while less data exist for organic chemicals.
15 Many more organic chemicals were reported as used in hydraulic fracturing fluid than have been
16 identified in produced water. The difference may be due to analytical limitations, limited study
17 scopes, and undocumented subsurface reactions.
• What are the chemical, physical, and toxicological properties of hydraulic fracturing flowback
and produced water constituents?
18 The identified constituents of produced water include inorganic chemicals (cations and anions, i.e.,
19 metals, metalloids, non-metals, and radioactive materials), organic chemicals and compounds, and
20 unidentified materials measured as total organic carbon and dissolved organic carbon. Some
21 constituents are readily transported with water (i.e., chloride and bromide), while others depend
22 strongly on the geochemical conditions in the receiving water body (i.e., radium and barium), and
23 assessment of their transport is based on site-specific factors. We were able to obtain actual or
24 estimated physicochemical properties for 86 (64%) of the 134 chemicals identified in produced
2 5 water.
26 As in the case of chemicals in hydraulic fracturing fluid, chemical properties that affect the
2 7 likelihood of an organic chemical in produced water reaching and impacting drinking water
28 resources include: mobility, solubility, and volatility. In general, physicochemical properties suggest
29 that organic chemicals in produced water tend to be less mobile in the environment. Consequently,
30 if spilled, these chemicals may remain in soils or sediments near spill sites. Low mobility may result
31 in smaller dissolved contaminant plumes in ground water, although these chemicals can be
32 transported with sediments in surface water or small particles in ground water. Organic chemical
33 properties vary with salinity, and effects depend on the nature of the chemical.
34 Oral reference values and/or oral slope factors from selected federal, state, and international
35 sources were available for 83 (62%) of the 134 chemicals detected in produced water. From U.S.
36 federal sources alone, chronic oral reference values were available for 70 (52%) of the 134
37 chemicals, and oral slope factors were available for 20 chemicals (15%). Of the chemicals that had
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1 values available, noted health effects include the potential for carcinogenesis, immune system
2 effects, changes in body weight, changes in blood chemistry, pulmonary toxicity, neurotoxicity, liver
3 and kidney toxicity, and reproductive and developmental toxicity. As noted above, evaluating any
4 potential risk to human populations would require knowledge of the specific chemicals that are
5 present at a particular site, whether or not humans are exposed to those chemicals and, if so, at
6 what levels and for what duration, and the toxicity of the chemicals. The chemicals present in
7 produced water can vary based on the formation and specific well, due to differences in fracturing
8 fluid formulation and formation geology. Accordingly, consideration of hazards and risks associated
9 with these chemicals would be most useful on a site-specific basis and is beyond the scope of this
10 assessment .
• // sp;7/s occur, how might hydraulic fracturing flowback and produced water contaminate
drinking water resources?
11 Impacts to drinking water resources from spills or releases of produced water depend on the
12 volume, timing, and composition of the produced water. Impacts are more likely the greater the
13 volume of the spill, the longer the duration of the release, and the higher the concentration of
14 produced water constituents (i.e., salts, naturally occurring radioactive material, and metals).
15 The EPA characterization of hydraulic fracturing-related spills found that 8% of the 225 produced
16 water spills included in the study reached surface water or ground water. These spills tended to be
17 of greater volume than spills that did not reach a water body. A well blowout in Bradford County,
18 Pennsylvania spilled an estimated 10,000 gal (38,000 L) of produced water into a tributary of
19 Towanda Creek, a state-designated trout fishery. The largest volume spill identified in this
20 assessment occurred in North Dakota, where approximately 2.9 million gal (11 million L) of
21 produced water spilled from a broken pipeline and impacted surface and ground water.
22 Chronic releases can and do occur from produced water disposed in unlined pits or impoundments,
23 and can have long-term impacts. Ground water impacts may persist longer than surface water
24 impacts because of lower flow rates and decreased mixing. Plumes from unlined pits used for
25 produced water have been shown to persist for long periods and extend to nearby surface water
26 bodies.
10.1.5. Wastewater Management and Waste Disposal (Chapter 8)
27 Hydraulic fracturing generates large volumes of produced water that require management. In this
2 8 section we refer to produced water and any other waters generated onsite by the single term
29 "wastewater." Clark and Veil (2009) estimated that in 2007 approximately one million active oil
30 and gas wells in the United States generated 2.4 billion gal per day (9.1 billion L per day) of
31 wastewater. There is currently no reliable way to estimate what fraction of this total volume can be
32 attributed to hydraulically fractured wells. Wastewater volumes in a region can increase sharply as
33 hydraulic fracturing activity increases.
34 Wastewater management and disposal could affect drinking water resources through multiple
3 5 mechanisms including: inadequate treatment of wastewater prior to discharge to a receiving water,
3 6 accidental releases during transport or leakage from wastewater storage pits, unpermitted
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1 discharges, migration of constituents in wastewaters following land application, inappropriate
2 management of residual materials from treatment, or accumulation of wastewater constituents in
3 sediments near outfalls of centralized waste treatment facilities (CWTs) or publicly owned
4 treatment works (POTWs) that have treated hydraulic fracturing wastewater. The scope of this
5 assessment excludes potential impacts to drinking water from the disposal of hydraulic fracturing
6 wastewater in underground injection control (UIC) wells.
Research Questions: Wastewater Management and Waste Disposal
• What are the common treatment and disposal methods for hydraulic fracturing wastewater,
and where are these methods practiced?
7 Hydraulic fracturing wastewater is managed using several options including disposal in UIC wells
8 (also called disposal wells); through evaporation ponds; treatment at CWTs, followed by reuse or
9 by discharge to either surface waters or POTWs; reuse with minimal or no treatment; and land
10 application or road spreading. Treatment of hydraulic fracturing wastewater by POTWs was used in
11 the past in Pennsylvania. This decreased sharply following new state-level requirements and a
12 request by the Pennsylvania Department of Environmental Protection (PA DEP) for well operators
13 to stop sending Marcellus Shale wastewater to POTWs (and 15 CWTs) discharging to surface
14 waters.
15 Wastewater management decisions are generally based on the availability and associated costs
16 (including transportation) of disposal or treatment facilities. A survey of state agencies found that,
17 in 2007, more than 98% of produced water from the oil and gas industry was managed via
18 underground injection (Clark and Veil. 2009). Available information suggests that disposal wells are
19 also the primary management practice for hydraulic fracturing wastewater in most regions in the
20 United States (e.g., the Barnett Shale; see Figure 10-lb). The Marcellus Shale region is a notable
21 exception, where most wastewater is reused because of the small number of disposal wells in
22 Pennsylvania (see Figure 10-la). Although this assessment does not address potential effects on
2 3 drinking water resources from the use of disposal wells, any changes in cost of disposal or
24 availability of disposal wells would likely influence wastewater management decisions.
2 5 Wastewater from some hydraulic fracturing operations is sent to CWTs, which may discharge
26 treated wastewater to surface waters, POTWs, or back to well operators for reuse in other
2 7 hydraulic fracturing operations. Available data indicate that the use of CWTs for treating hydraulic
28 fracturing wastewater is greater in the Marcellus Shale region than other parts of the country. Most
29 of the CWTs accepting hydraulic fracturing wastewater in Pennsylvania cannot significantly reduce
30 TDS, and many of these facilities provide treated wastewater to well operators for reuse and do not
31 currently discharge treated wastewater to surface water.
3 2 Reuse of wastewater for subsequent hydraulic fracturing operations may require no treatment,
33 minimal treatment, or more extensive treatment. Operators reuse a substantial amount (ca. 70-
34 90%) of Marcellus Shale wastewater in Pennsylvania (see Figure 10-la). Lesser amounts of reuse
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1 occur in other areas (e.g., the Barnett Shale; see Figure 10-lb). In certain formations, such as the
2 Bakken Shale in North Dakota, there is currently no indication of appreciable reuse.
3 In some cases, wastewater is used for land applications such as irrigation or road spreading for
4 deicing or dust suppression. Land application has the potential to introduce wastewater
5 constituents to surface water and ground water due to runoff and migration of brines. Studies of
6 road spreading of conventional oil and gas brines have found elevated levels of metals in soils and
7 chloride in ground water.
• How effective are conventional POTWs and commercial treatment systems in removing
organic and inorganic contaminants of concern in hydraulic fracturing wastewater?
8 Publicly owned treatment works using basic treatment processes are not designed to effectively
9 reduce TDS concentrations in highly saline hydraulic fracturing wastewater—although specific
10 constituents or constituents groups can be removed (e.g., metals, oil, and grease by chemical
11 precipitation or other processes). In some cases, wastewater treated at CWTs may be sent to a
12 POTW for additional treatment and discharge. It is blended with POTW influent to prevent
13 detrimental effects on biological processes in the POTW that aid in the treatment of wastewater.
14 Centralized waste treatment facilities with advanced wastewater treatment options, such as
15 reverse osmosis, thermal distillation, or mechanical vapor recompression, reduce TDS
16 concentrations and can treat contaminants currently known to be in hydraulic fracturing
17 wastewater. However, there are limited data on the composition of hydraulic fracturing
18 wastewater, particularly for organic constituents. It is unknown whether advanced treatment
19 systems are effective at removing constituents that are generally not tested for.
• What are the potential impacts from surface water disposal of treated hydraulic fracturing
wastewater on drinking water treatment facilities?
2 0 Potential impacts to drinking water resources may occur if hydraulic fracturing wastewater is
21 inadequately treated and discharged to surface water. Inadequately treated hydraulic fracturing
22 wastewater may increase concentrations of TDS, bromide, chloride, and iodide in receiving waters.
23 In particular, bromide and iodide are precursors of disinfection byproducts (DBFs) that can form in
24 the presence of organic carbon in drinking water treatment plants or wastewater treatment plants.
25 Drinking water treatment plants are required to monitor for certain types of DBFs, because some
2 6 are toxic and can cause cancer.
2 7 Radionuclides can also be found in inadequately treated hydraulic fracturing wastewater from
28 certain shales, such as the Marcellus. A recent study by the PADEP (2015b] found elevated radium
29 concentrations in the tens to thousands of picocuries per liter and gross alpha and gross beta in the
30 hundreds to thousands of picocuries per liter in effluent samples from some CWTs receiving oil and
31 gas wastewater. Radium, gross alpha, and gross beta were also detected in effluents from POTWs
32 receiving oil and gas wastewater (mainly as effluent from CWTs), though at lower concentrations
33 than from the CWTs. Research in Pennsylvania also indicates the accumulation of radium in
34 sediments and soils affected by the outfalls of some treatment plants that have handled oil and gas
35 wastewater, including Marcellus Shale wastewater, and other wastewaters (PADEP. 2015b:
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1 Warner etal., 2013a]. Mobilization of radium from sediments and potential impacts on downstream
2 water quality depend upon how strongly the radium has sorbed to sediments. Impacts may also
3 occur if sediment is resuspended (e.g., following storm events). There is no evidence of radionuclide
4 contamination in drinking water intakes due to inadequately treated hydraulic fracturing
5 wastewater.
6 Hydraulic fracturing wastewaters contain other constituents such as barium, boron, and heavy
7 metals. Barium in particular has been documented in some shale gas produced waters. Little data
8 exist on metal and organic compound concentrations in untreated and treated wastewaters in
9 order to evaluate whether treatment is effective, and whether there are potential downstream
10 effects on drinking water resources when wastewater is treated and discharged.
10.2.Key Data Limitations and Uncertainties
11 This assessment used available data and literature to examine the potential impacts of hydraulic
12 fracturing for oil and gas on drinking water resources nationally. As part of this effort, we identified
13 data limitations and uncertainties associated with current information on hydraulic fracturing and
14 its potential to affect drinking water resources. In particular, data limitations preclude a
15 determination of the frequency of impacts with any certainty. There is a high degree of uncertainty
16 about whether the relatively few instances of impacts noted in this report are the result of a rarity
17 of effects or a lack of data. These limitations and uncertainties are discussed in brief below.
10.2.1. Limitations in monitoring data and chemical information
18 While many activities conducted as part of the hydraulic fracturing water cycle take place above
19 ground, hydraulic fracturing itself occurs below ground and is not directly observable. Additionally,
20 potential mechanisms identified in this assessment may result in impacts to drinking water
21 resources that are below ground (e.g., spilled fluids leaching into ground water). Because of this,
22 monitoring data are needed before, during, and after hydraulic fracturing to characterize the status
23 of the well being fractured and the presence, migration, or transformation of chemicals in the
24 subsurface. These data can include results from mechanical integrity tests performed on
25 hydraulically fractured oil and gas production wells and data on local water quality collected pre-
26 and post-hydraulic fracturing. In particular, baseline data on local water quality is needed to
27 quantify changes to drinking water resources and to provide insights into whether nearby
28 hydraulic fracturing activities may have caused any detected changes. The limited amount of data
29 collected before and during hydraulic fracturing activities reduces the ability to determine whether
30 hydraulic fracturing affected drinking water resources in cases of alleged contamination.
31 Water quality testing for hydraulic fracturing-related chemicals is routinely conducted for a small
32 subset of chemicals reportedly used in hydraulic fracturing fluids or detected in produced water.
33 Public water systems regularly test for selected contaminants under the National Primary Drinking
34 Water Regulations. Approximately 6% of the 1,173 chemicals in Table A-2 and Table A-4 are
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1 routinely tested for under these regulations.: Private water wells are usually tested less often and
2 for fewer potential contaminants than public water supplies [USGS. 2014c]. Since chemical use
3 varies widely across the country, testing for any particular chemical may or may not be appropriate
4 for detecting potential impacts on a drinking water resource from a nearby hydraulic fracturing
5 operation. Furthermore, the concentration, mobility, and detectability (as determined by the lowest
6 concentration that an analytical method is able to determine a chemical's presence) of chemicals
7 used in or produced by hydraulic fracturing operations will affect whether or not it would be
8 identified in a drinking water resource in the event of its release into the environment.
9 Information (identity, frequency of use, physicochemical and toxicological properties, etc.) on the
10 chemicals associated with the hydraulic fracturing water cycle is not complete and limits
11 understanding of potential impacts on drinking water resources. Well operators identified one or
12 more chemicals as confidential in approximately 70% of wells reported to FracFocus 1.0 and
13 analyzed by the EPA (U.S. EPA. 2015a). Additionally, chemicals found in flowback and produced
14 water (see Table A-4) were identified for a limited number of geographic locations and formations.
15 These characterization studies are constrained by available methods for detecting organic and
16 inorganic compounds in flowback and produced water. The identity of hydraulic fracturing-related
17 chemicals is necessary to understand their chemical, physical, and toxicological properties, which
18 determine how they might move through the environment to drinking water resources and any
19 resulting effects. Knowing their identities would also help inform what chemicals to test for in the
2 0 event of suspected drinking water impacts and, in the case of wastewater, may help predict
21 whether current treatment systems are effective at removing them.
22 Peer reviewed toxicity data for known hydraulic fracturing-related chemicals is very limited. Of the
23 1,173 hydraulic fracturing-related chemicals identified in Appendix A, 147 have chronic oral
24 reference values and/or oral slope factors from the sources that met the selection criteria for
25 inclusion in this assessment Because the majority of chemicals identified in this report do not have
26 chronic oral reference values and/or oral slope factors, risk assessors at the local and regional level
27 may need to use alternative sources of toxicity information that could introduce greater
28 uncertainties. It also makes an assessment of potential cumulative effects of exposure to chemical
29 mixtures in hydraulic fracturing fluid, flowback, or produced water difficult
1 We identified 73 chemicals that are reported to be used in hydraulic fracturing fluids (see Table A-2) or that have been
detected in produced water (see Table A-4) that are tested for as part of the contaminant monitoring conducted for 40
different drinking water standards under the National Primary Drinking Water Regulations (NPDWR). For inorganic
chemicals regulated under the NPDWR, we identified the chemical or element itself, its regulated ion (as applicable), or
other more complex forms on the list of hydraulic fracturing-related chemicals. For regulated organic chemicals, we
identified only the chemical itself on the list of hydraulic fracturing-related chemicals with three exceptions: (1) we
identified all four trihalomethanes that comprise total trihalomethanes, (2) we identified two of the five regulated
chlorinated/brominated haloacetic acids as their sodium salts, and (3) we identified a subset of polychlorinated biphenyls
(PCBs) as Aroclor 1248. Although various forms of petroleum distillates are used in hydraulic fracturing fluids and may
contain BTEX or benzo(a)pyrene (the regulated entities that can occur naturally in petroleum distillates), we did not
include them in our count of 73 chemicals.
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10.2.2. Other Contributing Limitations
1 We found other limitations that hamper our ability to assess the potential impacts of hydraulic
2 fracturing on drinking water resources nationally. These include the number and location of
3 hydraulically fractured wells, the location of drinking water resources, and information on industry
4 practices and any changes that may take place in practices in the coming years. Our estimates of the
5 number of fractured wells are based on an evaluation of several commercial and public sources and
6 a number of assumptions. This lack of a definitive well count particularly contributes to
7 uncertainties regarding total water use or total wastewater volume estimates, and would limit any
8 kind of cumulative impact assessment
9 There are also some fundamental gaps in our understanding of drinking water resources, including
10 where they are located in relation to hydraulic fracturing operations and which might be most
11 vulnerable to impacts from hydraulic fracturing activities. Improving our assessment of potential
12 drinking water impacts requires better information, particularly about private drinking water well
13 locations and the depths of drinking water resources in relation to the hydraulically fractured
14 formations and well construction features (e.g., casing and cement). This information would allow
15 us to better assess whether subsurface drinking water resources are isolated from hydraulically
16 fractured oil and gas production wells.
17 Finally, this assessment summarizes available information on industry practices with respect to the
18 hydraulic fracturing water cycle. While some information on hydraulic fracturing activities is
19 available for many areas of the United States, specific data on water withdrawals for hydraulic
2 0 fracturing, volumes of flowback and produced water generated, and the disposal or reuse of
21 wastewaters is needed to better characterize potential impacts of hydraulic fracturing on drinking
22 water resources. Additionally, industry practices are rapidly changing (e.g., the number of wells
23 fractured, the location of activities, and the chemicals used), and it is unclear how changes in
24 industry practices could affect potential drinking water impacts in the future. Consideration of
2 5 future development scenarios was not a part of this assessment, but such an evaluation could help
2 6 establish potential short- and long-term impacts to drinking water resources and how to assess
27 them.
10.3.Conclusions
28 Through this national-level assessment, we have identified potential mechanisms by which
29 hydraulic fracturing could affect drinking water resources. Above ground mechanisms can affect
30 surface and ground water resources and include water withdrawals at times or in locations of low
31 water availability, spills of hydraulic fracturing fluid and chemicals or produced water, and
3 2 inadequate treatment and discharge of hydraulic fracturing wastewater. Below ground mechanisms
3 3 include movement of liquids and gases via the production well into underground drinking water
34 resources and movement of liquids and gases from the fracture zone to these resources via
3 5 pathways in subsurface rock formations.
36 We did not find evidence that these mechanisms have led to widespread, systemic impacts on
37 drinking water resources in the United States. Of the potential mechanisms identified in this report,
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1 we found specific instances where one or more of these mechanisms led to impacts on drinking
2 water resources, including contamination of drinking water wells. The cases occurred during both
3 routine activities and accidents and have resulted in impacts to surface or ground water. Spills of
4 hydraulic fracturing fluid and produced water in certain cases have reached drinking water
5 resources, both surface and ground water. Discharge of treated hydraulic fracturing waste water has
6 increased contaminant concentrations in receiving surface waters. Below ground movement of
7 fluids, including gas, most likely via the production well, have contaminated drinking water
8 resources. In some cases, hydraulic fracturing fluids have also been directly injected into drinking
9 water resources, as defined in this assessment, to produce oil or gas that co-exists in those
10 formations.
11 The number of identified cases where drinking water resources were impacted are small relative to
12 the number of hydraulically fractured wells. This could reflect a rarity of effects on drinking water
13 resources, or may be an underestimate as a result of several factors. There is insufficient pre- and
14 post-hydraulic fracturing data on the quality of drinking water resources. This inhibits a
15 determination of the frequency of impacts. Other limiting factors include the presence of other
16 causes of contamination, the short duration of existing studies, and inaccessible information related
17 to hydraulic fracturing activities.
10.4.Use of the Assessment
18 The practice of hydraulic fracturing is simultaneously expanding and changing rapidly. Over 60% of
19 new oil and gas wells are likely to be hydraulically fractured, and this percentage may be over 90%
20 in some locations. Economic forces are likely to cause short term volatility in the number of wells
21 drilled and fractured, yet hydraulic fracturing is expected to continue to expand and drive an
22 increase in domestic oil and gas production in coming decades [EIA. 2014a].1 As a result, hydraulic
23 fracturing will likely increase in existing locations, while also potentially expanding to new areas.
24 This state-of-the-science assessment contributes to the understanding of the potential impacts of
2 5 hydraulic fracturing on drinking water resources and the factors that may influence those impacts.
26 The findings in this assessment can be used by federal, state, tribal, and local officials; industry; and
2 7 the public to better understand and address any vulnerabilities of drinking water resources to
28 hydraulic fracturing activities. This assessment can also be used to help facilitate and inform
29 dialogue among interested stakeholders, and support future efforts, including: providing context to
30 site-specific exposure or risk assessments, local and regional public health assessments, and to
31 assessments of cumulative impacts of hydraulic fracturing on drinking water resources over time
32 or over defined geographic areas of interest
33 We hope the identification of limitations and uncertainties will promote greater attention to these
34 areas through pre- and post- hydraulic fracturing monitoring programs and by researchers. We also
1 In their reference case projections, the U.S. Energy Information Administration (EIA) forecasts that U.S. gas production
by 2035 will have increased 50% over 2012 levels. Crude oil production is projected to increase almost 40% above
current levels by 2025, before declining in subsequent decades [EIA. 2014a).
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1 hope it will lead to greater dissemination of data in forms accessible by a wide-range of researchers
2 and audiences.
3 Finally, and most importantly, this assessment advances the scientific basis for decisions by federal,
4 state, tribal, and local officials; industry; and the public, on how best to protect drinking water
5 resources now and in the future.
10.5.References for Chapter 10
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Hydraulic Fracturing Drinking Water Assessment All References
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Zhang. L: Anderson. N: Dilmore. R: Soeder. PI: Bromhal. G. (2014a). Leakage detection of Marcellus Shale
natural gas at an Upper Devonian gas monitoring well: a 3-d numerical modeling approach. Environ Sci
Technol 48:10795-10803. http://dx.doi.org/10.1021/es501997p
Zhang. T: Gregory. K: Hammack. RW: Vidic. RD. (2014b). Co-precipitation of radium with barium and
strontium sulfate and its impact on the fate of radium during treatment of produced water from
unconventional gas extraction. Environ Sci Technol 48: 4596-4603.
http://dx.doi.org/10.1021/es405168b
Ziemkiewicz. P: Donovan. I: Hause. I: Gutta. B: Fillhart. I: Mack. B: O'Neal. M. (2013). Water quality literature
review and field monitoring of active shale gas wells: Phase II for Assessing Environmental Impacts of
Horizontal Gas Well Drilling Operations. Charleston, WV: West Virginia Department of Environmental
Protection.
Ziemkiewicz. P: Ouaranta. ID: Mccawley. M. (2014). Practical measures for reducing the risk of environmental
contamination in shale energy production. Environ Sci Process Impacts 16:1692-1699.
http://dx.doi.org/10.1039/c3em00510k
Zoback. MD. (2010). Reservoir geomechanics. Cambridge, UK: Cambridge University Press.
This document is a draft for review purposes only and does not constitute Agency policy.
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DRAFT- DO NOT CITE OR QUOTE EPA/600/R-15/047b
External Review Draft
United States
Environmental Protection
Agency
Assessment of the Potential Impacts of Hydraulic
Fracturing for Oil and Gas on Drinking Water
Resources
(Appendices A - J)
NOTICE
THIS DOCUMENT IS AN EXTERNAL REVIEW DRAFT, for review purposes only. It has not
been formally disseminated by EPA. It does not represent and should not be construed to
represent any Agency determination or policy.
Office of Research and Development
U.S. Environmental Protection Agency
Washington, DC 20460
-------
Hydraulic Fracturing Drinking Water Assessment Appendices A-J
DISCLAIMER
This document is an external review draft. This information is distributed solely for the purpose of
pre-dissemination peer review under applicable information quality guidelines. It has not been
formally disseminated by EPA. It does not represent and should not be construed to represent any
Agency determination or policy. Mention of trade names or commercial products does not
constitute endorsement or recommendation for use.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendices A-J
Contents: Appendices
Appendix A. Chemicals Identified in Hydraulic Fracturing Fluids and/or Flowback and
Produced Water
A.I. Supplemental Tables and Information A-l
Table A-l. Description of sources used to create lists of chemicals used in fracturing fluids or
detected in flowback or produced water A-l
Table A-2. Chemicals reported to be used in hydraulic fracturing fluids A-4
Table A-3. List of generic names of chemicals reportedly used in hydraulic fracturing fluids A-46
Table A-4. Chemicals detected in flowback or produced water A-58
A.2. References for Appendix A A-63
Appendix B. Water Acquisition Tables B-l
B.I. Supplemental Tables B-l
Table B-l. Annual average hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010 by state B-l
Table B-2. Annual average hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010 by county B-3
Table B-3. Comparison of water use per well estimates from the EPA's project database of
disclosures to FracFocus 1.0 (U.S. EPA, 2015c) and literature sources B-20
Table B-4. Comparison of well counts from the EPA's project database of disclosures to FracFocus
1.0 (U.S. EPA, 2015c) and state databases for North Dakota, Pennsylvania, and West
Virginia B-21
Table B-5. Water use per hydraulically fractured well as reported in the EPA's project database of
disclosures to FracFocus 1.0 (U.S. EPA, 2015c) by state and basin B-22
Table B-6. Estimated percent domestic use water from ground water and self-supplied by county.
B-26
Table B-7. Projected hydraulic fracturing water use by Texas counties between 2015 and 2060,
expressed as a percentage of 2010 total county water use B-40
B.2. References for Appendix B B-52
Appendix C. Chemical Mixing Supplemental Tables and Information C-l
C.I. Supplemental Tables and Information C-l
Table C-l. Chemicals reported to FracFocus in 10% or more of disclosures for gas-producing wells,
with the number of disclosures where chemical is reported, percentage of disclosures,
and the median maximum concentration (% by mass) of that chemical in hydraulic
fracturing fluid C-l
Table C-2. Chemicals reported to FracFocus in 10% or more of disclosures for oil-producing wells,
with the number of disclosures where chemical is reported, percentage of disclosures,
and the median maximum concentration (% by mass) of that chemical in hydraulic
fracturing fluid C-3
Table C-3a. Top chemicals reported to FracFocus for each state and number (and percentage) of
disclosures where a chemical is reported for that state, Alabama to Montana (U.S.
EPA, 2015c) C-5
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Hydraulic Fracturing Drinking Water Assessment Appendices A-J
Table C-3b. Top chemicals reported to FracFocus for each state and number (and percentage) of
disclosures where a chemical is reported for that state, New Mexico to Wyoming (U.S.
EPA, 2015c) C-12
Table C-4. Estimated mean, median, 5th percentile, and 95th percentile volumes in gallons for
chemicals reported to FracFocus in 100 or more disclosures, where density
information was available C-20
Table C-5. Estimated mean, median, 5th percentile, and 95th percentile volumes in liters for
chemicals reported to FracFocus in 100 or more disclosures, where density
information was available C-23
Table C-6. Calculated mean, median, 5th percentile, and 95th percentile chemical masses reported
to FracFocus in 100 or more disclosures, where density information was available... C-26
Table C-7. Associated chemical densities and references used to calculate chemical mass and
estimate chemical volume C-29
Table C-8. Selected physicochemical properties of chemicals reported as used in hydraulic
fracturing fluids C-32
C.2. References for Appendix C C-76
Appendix D. Designing, Constructing, and Testing Wells for Integrity D-l
D.I. Design Goals for Well Construction D-l
D.2. Well Components D-l
Text Box D-l. Selected Industry-Developed Specifications and Recommended Practices for Well
Construction in North America D-2
D.2.1. Casing D-2
D.2.2. Cement D-3
Figure D-l. Atypical staged cementing process D-8
D.3. Well Completions D-9
Figure D-2. Examples of well completion types D-9
D.4. Mechanical Integrity Testing D-10
D.4.1. Internal Mechanical Integrity D-ll
D.4.2. External Mechanical Integrity D-12
D.5. References for Appendix D D-13
Appendix E. Flowback and Produced Water Supplemental Tables and Information E-l
E.I. Flowback and Long-Term Produced Water Volumes E-l
Table E-l. Flowback and long-term produced water characteristics for wells in unconventional
formations, formation-level data E-2
E.2. Produced Water Content E-6
E.2.1. Introduction E-6
E.2.2. General Water Quality Parameters E-6
Table E-2. Reported concentrations of general water quality parameters in produced water for
unconventional shale and tight formations, presented as: average
(minimum-maximum) or median (minimum-maximum) E-7
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Hydraulic Fracturing Drinking Water Assessment Appendices A-J
Table E-3. Reported concentrations of general water quality parameters in produced water for
unconventional coalbed basins, presented as: average (minimum-maximum) E-10
E.2.3. Salinity and Inorganics E-ll
Table E-4. Reported concentrations (mg/L) of inorganic constituents contributing to salinity in
unconventional shale and tight formations produced water, presented as: average
(minimum-maximum) or median (minimum-maximum) E-12
Table E-5. Reported concentrations (mg/L) of inorganic constituents contributing to salinity in
produced water for unconventional CBM basins, presented as: average
(minimum-maximum) E-14
E.2.4. Metals and Metalloids E-14
Table E-6. Reported concentrations (mg/L) of metals and metalloids from unconventional shale
and tight formation produced water, presented as: average (minimum-maximum) or
median (minimum-maximum) E-15
Table E-7. Reported concentrations (mg/L) of metals and metalloids from unconventional coalbed
produced water, presented as: average (minimum-maximum) E-18
E.2.5. Naturally Occurring Radioactive Material (NORM) and Technically Enhanced Naturally
Occurring Radioactive Material (TENORM) E-20
Table E-8. Reported concentrations (in pCi/L) of radioactive constituents in unconventional shale
and sandstone produced water, presented as: average (minimum-maximum) or
median (minimum-maximum) E-22
E.2.6. Organics E-24
Table E-9. Concentrations of select organic parameters from unconventional shale, a tight
formation, and coalbed produced water, presented as: average (minimum-maximum)
or median (minimum-maximum) E-25
Table E-10. Reported concentrations (u.g/L) of organic constituents in produced water for two
unconventional shale formations, presented as: average (minimum-maximum) or
median (minimum-maximum) E-28
Table E-ll. Reported concentrations of organic constituents in 65 samples of produced water
from the Black Warrior CBM Basin, presented as average (minimum-maximum) E-30
E.2.7. Chemical Reactions E-31
E.2.8. Microbial Community Processes and Content E-32
E.3. Produced Water Content Spatial Trends E-34
E.3.1. Variability between Plays of the Same Rock Type E-34
E.3.2. Local Variability E-36
E.4. Example Calculation for Roadway Transport E-36
E.4.1. Estimation of Transport Distance E-36
E.4.2. Estimation of Wastewater Volumes E-37
E.4.3. Estimation of Roadway Accidents E-37
Table E-12. Combination truck crashes in 2012 for the 2,469,094 registered combination trucks,
which traveled 163,458 million miles (U.S. Department of Transportation, 2012).a... E-37
Table E-13. Large truck crashes in 2012 (U.S. Department of Transportation, 2012).a E-38
E.4.4. Estimation of Material Release Rates in Crashes E-38
E.4.5. Estimation of Volume Released in Accidents E-38
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Hydraulic Fracturing Drinking Water Assessment Appendices A-J
Table E-14. Estimate of total truck-travel miles per well in the Susquehanna River Basin based on
the transport analysis performed by Gilmore et al. (2013) E-39
E.5. References for Appendix E E-39
Appendix F. Wastewater Treatment and Waste Disposal Supplemental Information F-l
F.I. Estimates of Wastewater Production in Regions where Hydraulic Fracturing is Occurring F-l
Table F-l. Estimated volumes (millions of gallons) of wastewater based on state data for selected
years and numbers of wells producing fluid F-2
F.2. Overview of Treatment Processes for Treating Hydraulic Fracturing Wastewater F-6
F.2.1. Basic Treatment F-6
Figure F-l. Electrocoagulation unit F-7
F.2.2. Advanced Treatment F-8
Figure F-2. Photograph of reverse osmosis system F-9
Figure F-3. Picture of mobile electrodialysis units in Wyoming F-10
Figure F-4. Picture of a mechanical vapor recompression unit near Decatur, Texas F-ll
Figure F-5. Mechanical vapor recompression process design - Maggie Spain Facility F-12
Figure F-6. Picture of a compressed bed ion exchange unit F-13
Figure F-7. Discharge water process used in the Pinedale Anticline field F-14
F.3. Treatment Technology Removal Capabilities F-14
Table F-2. Removal efficiency of different hydraulic fracturing wastewater constituents using
various wastewater treatment technologies.3 F-15
Table F-3. Treatment processes for hydraulic fracturing wastewater organic constituents F-18
Table F-4. Estimated effluent concentrations for example constituents based on treatment
process removal efficiencies F-20
F.4. Centralized Waste Treatment Facilities and Waste Management Options F-23
F.4.1. Discharge Options for CWTs F-23
F.5. Water Quality for Reuse F-24
Table F-5. Water quality requirements for reuse F-24
Figure F-8. Diagram of treatment for reuse of flowbackand produced water F-26
F.6. Hydraulic Fracturing Impacts on POTWs F-27
F.6.1. Potential Impacts on Treatment Processes F-27
F.7. Hydraulic Fracturing and DBPs F-27
F.8. References for Appendix F F-28
Appendix G. Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing
Water Cycle Supplemental Tables and Information G-l
G.I. Criteria for Selection and Inclusion of Reference Value (RfV) and Oral Slope Factor (OSF) Data Sources
G-l
G.I.I. Included Sources G-3
G.1.2. Excluded Sources G-3
G.2. Glossary of Toxicity Value Terminology G-4
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Hydraulic Fracturing Drinking Water Assessment Appendices A-J
G.3. Tables G-9
Table G-la. Chemicals reported to be used in hydraulic fracturing fluids, with available federal
chronic RfVsand OSFs G-9
Table G-lb. Chemicals reported to be used in hydraulic fracturing fluids, with available state
chronic RfVsand OSFs G-18
Table G-lc. Chemicals reported to be used in hydraulic fracturing fluids, with available
international chronic RfVs and OSFs G-19
Table G-ld. Chemicals reported to be used in hydraulic fracturing fluids, with available less-than-
chronic RfVsand OSFs G-20
Table G-2a. Chemicals reported to be detected in flowback or produced water, with available
federal chronic RfVsand OSFs G-23
Table G-2b. Chemicals reported to be detected in flowback or produced water, with available
state chronic RfVsand OSFs G-31
Table G-2c. Chemicals reported to be detected in flowback or produced water, with available
international chronic RfVs and OSFs G-33
Table G-2d. Chemicals reported to be detected in flowback or produced water, with available less-
than-chronic RfVsand OSFs G-34
G.4. References for Appendix G G-36
Appendix H. Description of EPA Hydraulic Fracturing Study Publications Cited in This Assessment H-l
Table H-l. Titles, descriptions, and citations for EPA hydraulic fracturing study publications cited
in this assessment H-l
Appendix I. Unit Conversions 1-1
Appendix J. Glossary J-l
J.I. Glossary Terms and Definitions J-l
J.2. References for Appendix J J-17
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Hydraulic Fracturing Drinking Water Assessment Appendix A
Appendix A
Chemicals Identified in Hydraulic Fracturing
Fluids and/or Flowback and Produced Water
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Hydraulic Fracturing Drinking Water Assessment Appendix A
Appendix A. Chemicals Identified in Hydraulic
Fracturing Fluids and/or Flowback and Produced
Water
A.I. Supplemental Tables and Information
1 The EPA identified authoritative sources for information on hydraulic fracturing chemicals and, to
2 the extent possible, verified the chemicals used in hydraulic fracturing fluids and detected in
3 flowback and produced water of hydraulically fractured wells. The EPA used 10 sources to identify
4 the chemicals used in hydraulic fracturing fluids or detected in flowback or produced water. Seven
5 sources are government entities (Congressional, federal, or state) that obtained the data directly
6 from industry. The remaining three represent collaborations between state, non-profit, academic,
7 and industry groups. FracFocus is the result of a collaboration between the Ground Water
8 Protection Council (a non-profit coalition of state ground water protection agencies) and
9 the Interstate Oil and Gas Compact Commission (a multi-state government agency). The Marcellus
10 Shale Coalition is a drilling industry trade group. &)]jbojnry^^ is a peer-reviewed journal
11 article. Most of the listed chemicals were cited by multiple sources.
12 Seven of the ten sources obtained information about the chemicals used in hydraulic fracturing
13 fluids from material safety data sheets (MSDSs) provided by chemical manufacturers for the
14 products they sell, as required by the Occupational Safety and Health Administration (OSHA). The
15 MSDSs must list all hazardous ingredients if they comprise atleast 1% of the product; for
16 carcinogens, the reporting threshold is 0.1%. However, chemical manufacturers may withhold
17 information (e.g., chemical name, concentration of the substance in a mixture) about a hazardous
18 substance from MSDSs if it is claimed as confidential business information (CBI), provided that
19 certain conditions are met (OSHA1_20_13,).
Table A-l. Description of sources used to create lists of chemicals used in fracturing fluids or
detected in flowback or produced water.
The number next to each citation in the reference column corresponds to numbers in the reference
columns found in Table A-2, Table A-3, and Table A-4.
Description / Content
Reference
Chemicals and other components used by 14 hydraulic fracturing service
companies from 2005 to 2009 as reported to the House Committee on Energy
, 7, ,_ ..... 7 . , , . HouseofRepresentatives
and Commerce. For each hydraulic fracturing product reported, companies - -
also provided an MSDS with information about the product's chemical
components.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Description / Content
Chemicals used during natural gas operations with some potential health
effects. The list of chemicals was compiled from MSDSs from several sources,
including the Bureau of Land Management, U.S. Forest Service, state agencies,
and industry.
Chemicals used or proposed for use in hydraulic fracturing in the Marcellus
Shale in New York based on product composition disclosures and MSDSs
submitted to the New York State Department of Environmental Conservation
(NYSDEC). Also includes data provided separately to NYSDEC by well operators
on analytical results of flowback water samples from Marcellus Shale
operations in Pennsylvania and West Virginia.
Chemicals reported to be used by nine hydraulic fracturing service companies
from 2005 to 2010. Companies provided the chemical names in MSDSs,
product bulletins, and formulation sheets.
MSDSs provided to the EPA during on-site visits to hydraulically fractured oil
and gas wells in Oklahoma and Colorado.
Characteristics of undiluted chemicals found in hydraulic fracturing fluids
associated with coalbed methane production, based on MSDSs, literature
searches, reviews of relevant MSDSs provided by service companies, and
discussions with field engineers, service company chemists, and state and
federal employees.
Chemicals used in Pennsylvania for hydraulic fracturing activities based on
MSDSs provided by industry.
Chemical records entered in FracFocus by oil and gas operators for individual
wells from January 1, 2011, through February 28, 2013. FracFocus is a publicly
accessible hydraulic fracturing chemical registry developed by the Ground
Water Protection Council and the Interstate Oil and Gas Compact Commission.
Chemicals claimed as confidential business information (CBI) do not have to be
reported in FracFocus.
Chemicals detected in flowback from 19 hydraulically fractured shale gas wells
in Pennsylvania and West Virginia, based on analyses conducted by 17
Marcellus Shale Coalition member companies.
Chemicals reportedly detected in flowback and produced water from 81 wells
provided to the EPA by nine well operating companies.
Reference
(2)
(2011Ja-b (3)
(4)
Sheets
(6)
(7)
U.S. EPA(2015c)a(8)
Haies (9)
(10)
a Sources used to identify chemicals used in hydraulic fracturing fluids.
bSources used to identify chemicals detected in flowback and produced water.
1 Once it had identified chemicals used in hydraulic fracturing fluids and chemicals detected in
2 flowback/preduced water, the EPA conducted an initial review of the chemicals for preliminary
3 validation of provided chemical name and Chemical Abstracts Service Registry Number (CASRN)
4 combinations. A CASRN is a unique numeric identifier assigned by the Chemical Abstracts Service
5 (CAS) to a chemical substance when it enters the CAS Registry Database. The EPA Office of Research
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Hydraulic Fracturing Drinking Water Assessment Appendix A
1 and Development's National Center for Computational Toxicology (NCCT) provided the final formal
2 validation and verification of the listed chemicals.
3 The EPA first compared the hydraulic fracturing chemical CASRNs and names with chemicals listed
4 in NCCT's Distributed Structure-Searchable Toxicity Database network (DSSTox) database (IIS,
5 EPA,_2fll3b). For the CASRNs and chemical names that did not appear in the DSSTox database, the
6 EPA's Substance Registry Services database and the U.S. National Library of Medicine ChemID
7 database were used to verify accurate chemical name and CASRN pairing (NL!MJ_2Iil4j UJLEJPAi
8 2014c). The EPA also identified cases where CASRN/name combinations could not be verified by
9 use of selected public sources and flagged those cases for resolution by NCCT.
10 NCCT then verified all of the CASRN and chemical names for the chemical lists generated by the EPA
11 in accordance with NCCT DSSTox Chemical Information Quality Review Procedures
12 (httpi//wwwLepa^
13 on the identification and validation of CASRN/chemical name combinations and resolution of
14 inconsistencies and problems including duplications, CASRN errors, and CASRN/chemical name
15 mismatches.
16 The general methodology for resolving conflicts between CASRN/chemical name combinations and
17 other chemical identification issues differed slightly depending on the data provided by each
18 source. To resolve chemical/CASRN conflict in data provided by the nine service companies, the
19 EPA worked with each company to verify the CASRN/chemical combinations proposed by NCCT. In
20 cases of CASRN/chemical name mismatches in data provided by FracFocus, chemical names were
21 considered primary to the CASRN (i.e., the name overrode the CASRN). When the chemical name
22 was non-specific and the CASRN was valid, then the CASRN was considered primary to the chemical
23 name, and the correct specific chemical name from DSSTox was assigned to the CASRN. For all other
24 sources, the CASRN was considered primary unless it was invalid or missing. In such cases, the
25 chemical name was primary. All Toxic Substance Control Act (TSCA) CBI chemical lists were
26 managed in accordance with TSCA CBI procedures.
27 Chemicals with verified CASRNs that are used in hydraulic fracturing fluids are presented in Table
28 A-2. Generic chemicals used in hydraulic fracturing fluids are presented in Table A-3. Chemicals
29 with verified CASRNs that have been detected in flowback or produced water are presented in
30 Table A-4. Chemicals found in both fracturing fluids (see Table A-2) and flowback and produced
31 water (see Table A-4) are italicized in each table.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Table A-2. Chemicals reported to be used in hydraulic fracturing fluids.
An "X" indicates the availability of physicochemical properties from EPI Suite™ (see Appendix C) and
selected toxicity reference values (see Appendix G). An empty cell indicates no information was
available from the sources we consulted. Reference number corresponds to the citations in Table A-l.
Italicized chemicals are found in both fracturing fluids and flowback/produced water.
Chemical name
(13Z)-N,N-bis(2-hydroxyethyl)-N-methyldocos-
13-en-l-aminium chloride
(2,3-dihydroxypropyl)trimethylammonium
chloride
(E)-Crotonaldehyde
[Nitrilotris(methylene)]tris-phosphonic acid
pentasodium salt
l-(l-Naphthylmethyl)quinolinium chloride
l-(Alkyl* amino)-3-aminopropane *(42%C12,
26%C18, 15%C14, 8%C16, 5%C10, 4%C8)
l-(Phenylmethyl)pyridinium Et Me derivs.,
chlorides
1,2,3-Trimethylbenzene
1, 2, 4- Trimethylbenzen e
l,2-Benzisothiazolin-3-one
l,2-Dibromo-2,4-dicyanobutane
1,2-Dimethylbenzene
1,2-Ethanediamine, polymer with 2-
methyloxirane
1,2-Ethanediaminium, N,N'-bis[2-[bis(2-
hydroxyethyl)methylammonio]ethyl]-N,N'-
bis(2-hydroxyethyl)-N,N'-dimethyl-,
tetrachloride
1,2-Propylene glycol
1,2-Propylene oxide
1,3,5-Triazine
1,3,5-Triazine- l,3,5(2H,4H,6H)-triethanol
1, 3, 5- Trimethylbenzen e
1,3- Butadiene
CASRN
120086-58-0
34004-36-9
123-73-9
2235-43-0
65322-65-8
68155-37-3
68909-18-2
526-73-8
95-63-6
2634-33-5
35691-65-7
95-47-6
25214-63-5
138879-94-4
57-55-6
75-56-9
290-87-9
4719-04-4
108-67-8
106-99-0
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxicity
reference
value
X
X
X
X
Reference
1
8
1,4
1
1
8
1, 2, 3, 4, 6, 8
1,4
1, 2, 3, 4, 5
1,3,4
1,4
4
8
1,4
1, 2, 3, 4, 8
1,4
8
1,4
1,4
8
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
1,3-Dichloropropene
1,4-Dioxane
l,4-Dioxane-2,5-dione, 3,6-dimethyl-, (3R,6R)-,
polymer with (3S,6S)-3,6-dimethyl-l,4-dioxane-
2,5-dione and (3R,6S)-rel-3,6-dimethyl-l,4-
dioxane-2,5-dione
1,6-Hexanediamine
1,6-Hexanediamine dihydrochloride
l-[2-(2-Methoxy-l-methylethoxy)-l-
methylethoxy]-2-propanol
l-Amino-2-propanol
1-Benzylquinolinium chloride
1-Butanol
l-Butoxy-2-propanol
1-Decanol
l-Dodecyl-2-pyrrolidinone
1-Eicosene
l-Ethyl-2-methylbenzene
1-Hexadecene
1-Hexanol
1-Hexanol, 2-ethyl-, manuf. of, by products
from, distn. residues
IH-lmidazole-l-ethanamine, 4,5-dihydro-, 2-
nortall-oil alkyl derivs.
l-Methoxy-2-propanol
1-Octadecanamine, acetate (1:1)
1-Octadecanamine, N,N-dimethyl-
1-Octadecene
1-Octanol
1-Pentanol
1-Propanaminium, 3-amino-N-(carboxymethyl)-
N,N-dimethyl-, N-coco acyl derivs., chlorides,
sodium salts
CASRN
542-75-6
123-91-1
9051-89-2
124-09-4
6055-52-3
20324-33-8
78-96-6
15619-48-4
71-36-3
5131-66-8
112-30-1
2687-96-9
3452-07-1
611-14-3
629-73-2
111-27-3
68909-68-7
68442-97-7
107-98-2
2190-04-7
124-28-7
112-88-9
111-87-5
71-41-0
61789-39-7
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
Reference
8
2,3,4
1,4,8
1,2
1
4
8
1,3,4
1, 2, 3, 4, 7
8
1,4
1,4
3
4
3
1,4,8
4
2,4
1, 2, 3, 4
8
1,3,4
3
1,4
8
1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-5 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
1-Propanaminium, 3-amino-N-(carboxymethyl)-
N,N-dimethyl-, N-coco acyl derivs., inner salts
1-Propanaminium, 3-chloro-2-hydroxy-N,N,N-
trimethyl-, chloride
1-Propanaminium, N-(3-aminopropyl)-2-
hydroxy-N,N-dimethyl-3-sulfo-, N-coco acyl
derivs., inner salts
1-Propanaminium, N-(carboxymethyl)-N,N-
dimethyl-3-[(l-oxooctyl)amino]-, inner salt
1-Propanesulfonic acid
1-Propanol
1-Propanol, zirconium(4+) salt
1-Propene
l-tert-Butoxy-2-propanol
1-Tetradecene
1-Tridecanol
1-Undecanol
2-(2-Butoxyethoxy)ethanol
2-(2-Ethoxyethoxy)ethanol
2-(2-Ethoxyethoxy)ethyl acetate
2-(Dibutylamino)ethanol
2-(Hydroxymethylamino)ethanol
2-(Thiocyanomethylthio)benzothiazole
2,2'-(diazene-l,2-diyldiethane-l,l-diyl)bis-4,5-
dihydro-lH-imidazole dihydrochloride
2,2'-(Octadecylimino)diethanol
2,2'-[Ethane-l,2-diylbis(oxy)]diethanamine
2,2'-Azobis(2-amidinopropane) dihydrochloride
2,2-Dibromo-3-nitrilopropionamide
2,2-Dibromopropanediamide
2,4-Hexadienoic acid, potassium salt, (2E,4E)-
CASRN
61789-40-0
3327-22-8
68139-30-0
73772-46-0
5284-66-2
71-23-8
23519-77-9
115-07-1
57018-52-7
1120-36-1
112-70-9
112-42-5
112-34-5
111-90-0
112-15-2
102-81-8
34375-28-5
21564-17-0
27776-21-2
10213-78-2
929-59-9
2997-92-4
10222-01-2
73003-80-2
24634-61-5
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
Reference
1, 2, 3, 4
8
1,3,4
8
3
1, 2, 4, 5
1,4,8
2
8
3
1,4
2
2,4
1,4
1,4
1,4
1,4
2
3
1
1,4
1,4
1, 2, 3, 4, 6,
7,8
3
3
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-6 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
2,6,8-Trimethyl-4-nonanol
2-Acrylamide - 2-propanesulfonic acid and N,N-
dimethylacrylamide copolymer
2-Acrylamido -2-methylpropanesulfonic acid
copolymer
2-Acrylamido-2-methyl-l-propanesulfonic acid
2-Amino-2-methylpropan-l-ol
2-Aminoethanol ester with boric acid (H3BO3)
(1:1)
2-Aminoethanol hydrochloride
2-Bromo-3-nitrilopropionamide
2-Butanone oxime
2-Butenediamide, (2E)-, N,N'-bis[2-(4,5-dihydro-
2-nortall-oil alkyl-lH-imidazol-l-yl)ethyl] derivs.
2-Butoxy-l-propanol
2-Butoxyethanol
2-Dodecylbenzenesulfonic acid- n-(2-
aminoethyl)ethane-l,2-diamine(l:l)
2-Ethoxyethanol
2-Ethoxynaphthalene
2-Ethyl-l-hexanol
2-Ethyl-2-hexenal
2-Ethylhexyl benzoate
2-Hydroxyethyl acrylate
2-Hydroxyethylammonium hydrogen sulphite
2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-
methylethanaminium chloride
2-Mercaptoethanol
2-Methoxyethanol
2-Methyl-l-propanol
2-Methyl-2,4-pentanediol
CASRN
123-17-1
NOCAS_51252
NOCAS_51255
15214-89-8
124-68-5
10377-81-8
2002-24-6
1113-55-9
96-29-7
68442-77-3
15821-83-7
111-76-2
40139-72-8
110-80-5
93-18-5
104-76-7
645-62-5
5444-75-7
818-61-1
13427-63-9
7006-59-9
60-24-2
109-86-4
78-83-1
107-41-5
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
Reference
8
2
8
1,3
8
8
4,8
1, 2, 3, 4, 5
1
3,8
8
1, 2, 3, 4, 6,
7,8
8
6
3
1, 2, 3, 4, 5
2
4
1,4
1
8
1,4
4
1,2,4
1,2,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-7 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
2-Methyl-3(2H)-isothiazolone
2-Methyl-3-butyn-2-ol
2-Methylbutane
2-Methylquinoline hydrochloride
2-Phosphono-l,2,4-butanetricarboxylic acid
2-Phosphonobutane-l,2,4-tricarboxylic acid,
potassium salt (l:x)
2-Propanol, aluminum salt
2-Propen-l-aminium, N,N-dimethyl-N-2-
propenyl-, chloride, homopolymer
2-Propenamide, homopolymer
2-Propenoic acid, 2-(2-hydroxyethoxy)ethyl
ester
2-Propenoic acid, 2-ethylhexyl ester, polymer
with 2-hydroxyethyl 2-propenoate
2-Propenoic acid, 2-methyl-, polymer with 2-
propenoic acid, sodium salt
2-Propenoic acid, 2-methyl-, polymer with
sodium 2-methyl-2-[(l-oxo-2-propen-l-
yl)amino]-l-propanesulfonate (1:1)
2-Propenoic acid, ethyl ester, polymer with
ethenyl acetate and 2,5-furandione, hydrolyzed
2-Propenoic acid, ethyl ester, polymer with
ethenyl acetate and 2,5-furandione,
hydrolyzed, sodium salt
2-Propenoic acid, polymer with 2-propenamide,
sodium salt
2-Propenoic acid, polymer with ethene, zinc salt
2-Propenoic acid, polymer with ethenylbenzene
2-Propenoic acid, polymer with sodium
ethanesulfonate, peroxydisulfuric acid,
disodium salt- initiated, reaction products with
tetrasodium ethenylidenebis (phosphonata)
2-Propenoic acid, polymer with sodium
phosphinate (1:1), sodium salt
CASRN
2682-20-4
115-19-5
78-78-4
62763-89-7
37971-36-1
93858-78-7
555-31-7
26062-79-3
25038-45-3
13533-05-6
36089-45-9
28205-96-1
136793-29-8
113221-69-5
111560-38-4
25987-30-8
28208-80-2
25085-34-1
397256-50-7
129898-01-7
Physico-
chemical
properties
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
Reference
1,2,4
3
2
3
1,4
1
1
3
8
4
8
8
8
4,8
8
3,4,8
8
8
8
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-8 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
2-Propenoic acid, sodium salt (1:1), polymer
with sodium 2-methyl-2-((l-oxo-2-propen-l-
yl)amino)-l-propanesulfonate (1:1)
2-Propenoic acid, telomer with sodium 4-
ethenylbenzenesulfonate (1:1), sodium 2-
methyl-2-[(l-oxo-2-propen-l-yl)amino]-l-
propanesulfonate (1:1) and sodium sulfite (1:1),
sodium salt
2-Propenoic, polymer with sodium phosphinate
3-(Dimethylamino)propylamine
3,4,4-Trimethyloxazolidine
3,5,7-Triazatricyclo(3.3.1.13,7)decane, l-(3-
chloro-2-propenyl)-, chloride, (Z)-
3,7-Dimethyl-2,6-octadienal
3-Hydroxybutanal
3-Methoxypropylamine
3-Phenylprop-2-enal
4,4-Dimethyloxazolidine
4,6-Dimethyl-2-heptanone
4-[Abieta-8,ll,13-trien-18-yl(3-oxo-3-
phenylpropyl)amino]butan-2-one hydrochloride
4-Ethyloct-l-yn-3-ol
4-Hydroxy-3-methoxybenzaldehyde
4-Methoxybenzyl formate
4-Methoxyphenol
4-Methyl-2-pentanol
4-Methyl-2-pentanone
4-Nonylphenol
4-Nonylphenol polyethoxylate
5-Chloro-2-methyl-3(2H)-isothiazolone
Acetaldehyde
Acetic acid
CASRN
37350-42-8
151006-66-5
71050-62-9
109-55-7
75673-43-7
51229-78-8
5392-40-5
107-89-1
5332-73-0
104-55-2
51200-87-4
19549-80-5
143106-84-7
5877-42-9
121-33-5
122-91-8
150-76-5
108-11-2
108-10-1
104-40-5
68412-54-4
26172-55-4
75-07-0
64-19-7
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
Reference
1
4
3,4
8
8
3
3
1,2,4
8
1, 2, 3, 4, 7
8
8
1,4
1, 2, 3, 4
3
3
4
1,4
5
8
2,3,4
1,2,4
1,4
1, 2, 3, 4, 5,
6,7,8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-9 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Acetic acid ethenyl ester, polymer with ethenol
Acetic acid, C6-8-branched alkyl esters
Acetic acid, hydroxy-, reaction products with
triethanolamine
Acetic acid, mercapto-, monoammonium salt
Acetic anhydride
Acetone
Acetonitrile, 2,2',2"-nitrilotris-
Acetophenone
Acetyltriethyl citrate
Acrolein
Acrylamide
Acrylamide/ sodium acrylate copolymer
Acrylamide-sodium-2-acrylamido-2-
methlypropane sulfonate copolymer
Acrylic acid
Acrylic acid, with sodium-2-acrylamido-2-
methyl-1-propanesulfonate and sodium
phosphinate
Alcohols (C13-C15), ethoxylated
Alcohols, C10-12, ethoxylated
Alcohols, C10-14, ethoxylated
Alcohols, Cll-14-iso-, CIS-rich
Alcohols, Cll-14-iso-, CIS-rich, butoxylated
ethoxylated
Alcohols, Cll-14-iso-, CIS-rich, ethoxylated
Alcohols, C12-13, ethoxylated
Alcohols, C12-14, ethoxylated
Alcohols, C12-14, ethoxylated propoxylated
Alcohols, C12-14-secondary
Alcohols, C12-14-secondary, ethoxylated
Alcohols, C12-15, ethoxylated
CASRN
25213-24-5
90438-79-2
68442-62-6
5421-46-5
108-24-7
67-64-1
7327-60-8
98-86-2
77-89-4
107-02-8
79-06-1
25085-02-3
38193-60-1
79-10-7
110224-99-2
64425-86-1
67254-71-1
66455-15-0
68526-86-3
228414-35-5
78330-21-9
66455-14-9
68439-50-9
68439-51-0
126950-60-5
84133-50-6
68131-39-5
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
Reference
1,4
4
3
2,8
1, 2, 3, 4, 7
1, 3, 4, 6
1,4
1
1,4
2
1, 2, 3, 4
1, 2, 3, 4, 8
1, 2, 3, 4
2,4
8
8
3
3
3
1
3,4,8
4
2, 3, 4, 8
1, 3, 4, 8
1,3,4
3,4,8
3,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-10 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Alcohols, C12-16, ethoxylated
Alcohols, C14-15, ethoxylated
Alcohols, C6-12, ethoxylated
Alcohols, C7-9-JSO-, C8-rich, ethoxylated
Alcohols, C8-10, ethoxylated propoxylated
Alcohols, C9-11, ethoxylated
Alcohols, C9-ll-iso-, ClO-rich, ethoxylated
Alkanes C10-16-branched and linear
Alkanes, CIO- 14
Alkanes, C12-14-iso-
Alkanes, C13-16-iso-
Alkenes, C>10 .alpha. -
Alkenes, C>8
Alkenes, C24-25 alpha-, polymers with maleic
anhydride, docosyl esters
Alkyl quaternary ammonium with bentonite
Alkyl* dimethyl ethylbenzyl ammonium
chloride *(50%C12, 30%C14, 17%C16, 3%C18)
Alkyl* dimethyl ethylbenzyl ammonium
chloride *(60%C14, 30%C16, 5%C12, 5%C18)
Alkylbenzenesulfonate, linear
Almandite and pyrope garnet
alpha-[3.5-dimethyl-l-(2-methylpropyl)hexyl]-
omega-hydroxy-poly(oxy-l,2-ethandiyl)
alpha-Amylase
alpha-Lactose monohydrate
alpha-Terpineol
Alumina
Aluminatesilicate
Aluminum
Aluminum calcium oxide (AI2CaO4)
CASRN
68551-12-2
68951-67-7
68439-45-2
78330-19-5
68603-25-8
68439-46-3
78330-20-8
90622-52-9
93924-07-3
68551-19-9
68551-20-2
64743-02-8
68411-00-7
68607-07-8
71011-24-0
85409-23-0_l
68956-79-6
42615-29-2
1302-62-1
60828-78-6
9000-90-2
5989-81-1
98-55-5
1344-28-1
1327-36-2
7429-90-5
12042-68-1
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
Reference
3,4,8
3,4,8
3,4,8
2,4,8
3
3,4
1, 2, 4, 8
4
1
2,4,8
1,4
1, 3, 4, 8
1
8
4
8
8
1,4,6
1,4
3
4
8
3
1,2,4
8
1,4,6
2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-ll DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Aluminum chloride
Aluminum chloride hydroxide sulfate
Aluminum chloride, basic
Aluminum oxide (AI2O3)
Aluminum oxide silicate
Aluminum silicate
Aluminum sulfate
Amaranth
Amides, C8-18 and C18-unsatd., N,N-
bis(hydroxyethyl)
Amides, coco, N-[3-(dimethylamino)propyl]
Amides, coco, N-[3-(dimethylamino)propyl],
alkylation products with chloroaceticacid,
sodium salts
Amides, coco, N-[3-(dimethylamino)propyl],
alkylation products with sodium 3-chloro-2-
hydroxypropanesulfonate
Amides, coco, N-[3-(dimethylamino)propyl], N-
oxides
Amides, from C16-22 fatty acids and
diethylenetriamine
Amides, tall-oil fatty, N,N-bis(hydroxyethyl)
Amides, tallow, N-[3-(dimethylamino)propyl],N-
oxides
Amine oxides, cocoalkyldimethyl
Amines, C14-18; C16-18-unsaturated, alkyl,
ethoxylated
Amines, C8-18 and C18-unsatd. alkyl
Amines, coco alkyl
Amines, coco alkyl, acetates
Amines, coco alkyl, ethoxylated
Amines, coco alkyldimethyl
Amines, dicoco alkyl
CASRN
7446-70-0
39290-78-3
1327-41-9
90669-62-8
12068-56-3
12141-46-7
10043-01-3
915-67-3
68155-07-7
68140-01-2
70851-07-9
70851-08-0
68155-09-9
68876-82-4
68155-20-4
68647-77-8
61788-90-7
68155-39-5
68037-94-5
61788-46-3
61790-57-6
61791-14-8
61788-93-0
61789-76-2
Physico-
chemical
properties
X
Selected
toxic ity
reference
value
Reference
1,4
8
3,4
8
1,2,4
1,2,4
1,4
4
3
1,4
1,4
8
1,3,4
3
3,4
1,4
8
1
5
4
1,4
8
8
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-12 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Amines, dicoco alkylmethyl
Amines, ditallow alkyl, acetates
Amines, hydrogenated tallow alkyl, acetates
Amines, N-tallow alkyltrimethylenedi-,
ethoxylated
Amines, polyethylenepoly-, ethoxylated,
phosphonomethylated
Amines, polyethylenepoly-, reaction products
with benzyl chloride
Amines, tallow alkyl
Amines, tallow alkyl, ethoxylated, acetates
(salts)
Amines, tallow alkyl, ethoxylated, phosphates
Aminotrimethylene phosphonic acid
Ammonia
Ammonium (lauryloxypolyethoxy)ethyl sulfate
Ammonium acetate
Ammonium acrylate
Ammonium acrylate-acrylamide polymer
Ammonium bisulfate
Ammonium bisulfite
Ammonium chloride
Ammonium citrate (1:1)
Ammonium citrate (2:1)
Ammonium dodecyl sulfate
Ammonium fluoride
Ammonium hydrogen carbonate
Ammonium hydrogen difluoride
Ammonium hydrogen phosphonate
Ammonium hydroxide
Ammonium lactate
CASRN
61788-62-3
71011-03-5
61790-59-8
61790-85-0
68966-36-9
68603-67-8
61790-33-8
68551-33-7
68308-48-5
6419-19-8
7664-41-7
32612-48-9
631-61-8
10604-69-0
26100-47-0
7803-63-6
10192-30-0
12125-02-9
7632-50-0
3012-65-5
2235-54-3
12125-01-8
1066-33-7
1341-49-7
13446-12-3
1336-21-6
515-98-0
Physico-
chemical
properties
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
Reference
8
8
4
8
1,4
1
8
1,3,4
4
1,4,8
1, 2, 3, 4, 7
4
1, 3, 4, 5, 8
8
2,4,8
2
1, 2, 3, 4, 7
1, 2, 3, 4, 5,
6,8
3
8
1
1,4
1,4
1, 3, 4, 7
4
1,3,4
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-13 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Ammonium ligninsulfonate
Ammonium nitrate
Ammonium phosphate
Ammonium sulfate
Ammonium thiosulfate
Amorphous silica
Anethole
Aniline
Antimony pentoxide
Antimony trichloride
Antimony trioxide
Arsenic
Ashes, residues
Asphalt, sulfonated, sodium salt
Attapulgite
Aziridine, polymer with 2-methyloxirane
Barium sulfate
Bauxite
Benactyzine hydrochloride
Bentonite
Bentonite, benzyl(hydrogenated tallow alkyl)
dimethylammonium stearate complex
Benzamorf
Benzene
Benzene, l,l'-oxybis-, sec-hexyl derivs.,
sulfonated, sodium salts
Benzene, l,l'-oxybis-, tetrapropylene derivs.,
sulfonated
Benzene, l,l'-oxybis-, tetrapropylene derivs.,
sulfonated, sodium salts
Benzene, C10-16-alkyl derivs.
CASRN
8061-53-8
6484-52-2
7722-76-1
7783-20-2
7783-18-8
99439-28-8
104-46-1
62-53-3
1314-60-9
10025-91-9
1309-64-4
7440-38-2
68131-74-8
68201-32-1
12174-11-7
31974-35-3
7727-43-7
1318-16-7
57-37-4
1302-78-9
121888-68-4
12068-08-5
71-43-2
147732-60-3
119345-03-8
119345-04-9
68648-87-3
Physico-
chemical
properties
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
X
Reference
2
1,2,3
1,4
1, 2, 3, 4, 6
8
1,7
3
2,4
1,4
1,4
8
4
4
2
2,3
4,8
1,2,4
1,2,4
8
1, 2, 4, 6
3,4
1,4
1,3,4
8
8
3,4,8
1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-14 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Benzene, ethenyl-, polymer with 2-methyl-l,3-
butadiene, hydrogenated
Benzenemethanaminium, N,N-dimethyl-N-(2-
((l-oxo-2-propen-l-yl)oxy)ethyl)-, chloride
(1:1), polymer with 2-propenamide
Benzenesulfonicacid
Benzenesulfonic acid, (1-methylethyl)-,
Benzenesulfonic acid, (1-methylethyl)-,
ammonium salt
Benzenesulfonic acid, (1-methylethyl)-, sodium
salt
Benzenesulfonic acid, C10-16-alkyl derivs.
Benzenesulfonic acid, C10-16-alkyl derivs.,
compds. with cyclohexylamine
Benzenesulfonic acid, C10-16-alkyl derivs.,
compds. with triethanolamine
Benzenesulfonic acid, C10-16-alkyl derivs.,
potassium salts
Benzenesulfonic acid, dodecyl-, branched,
compds. with 2-propanamine
Benzenesulfonic acid, mono-C10-16 alkyl
derivs., compds. with 2-propanamine
Benzenesulfonic acid, mono-C10-16-alkyl
derivs., sodium salts
Benzoicacid
Benzyl chloride
Benzyldimethyldodecylammonium chloride
Benzylhexadecyldimethylammonium chloride
Benzyltrimethylammonium chloride
Bicine
Bio-Perge
Bis(l-methylethyl)naphthalenesulfonicacid,
cyclohexylamine salt
Bis(2-chloroethyl) ether
CASRN
68648-89-5
74153-51-8
98-11-3
37953-05-2
37475-88-0
28348-53-0
68584-22-5
255043-08-4
68584-25-8
68584-27-0
90218-35-2
68648-81-7
68081-81-2
65-85-0
100-44-7
139-07-1
122-18-9
56-93-9
150-25-4
55965-84-9
68425-61-6
111-44-4
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
Reference
8
3
2
4
3,4
8
1,4
1
8
1,4,8
4
1,4
8
1,4,7
1, 2, 4, 8
2,8
8
8
1,4
8
1
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-15 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Bisphenol A
Bisphenol A/ Epichlorohydrin resin
Bisphenol A/ Novolac epoxy resin
Blast furnace slag
Borax
Boric acid
Boric acid (H3BO3), compd. with 2-
aminoethanol (l:x)
Boric oxide
Boron potassium oxide (B4K2O7)
Boron potassium oxide (B4K2O7), tetrahydrate
Boron potassium oxide (B5KO8)
Boron sodium oxide
Boron sodium oxide pentahydrate
Bronopol
Butane
Butanedioic acid, sulfo-, l,4-bis(l,3-
dimethylbutyl) ester, sodium salt
Butene
Butyl glycidyl ether
Butyl lactate
Butyryl trihexyl citrate
C.I. Acid Red 1
C.I. Acid violet 12, disodium salt
C.I. Pigment Red 5
C.I. Solvent Red 26
C10-16-Alkyldimethylamines oxides
C10-C16 ethoxylated alcohol
Cll-15-Secondary alcohols ethoxylated
C12-14tert-alkyl ethoxylated amines
C8-10 Alcohols
CASRN
80-05-7
25068-38-6
28906-96-9
65996-69-2
1303-96-4
10043-35-3
26038-87-9
1303-86-2
1332-77-0
12045-78-2
11128-29-3
1330-43-4
12179-04-3
52-51-7
106-97-8
2373-38-8
25167-67-3
2426-08-6
138-22-7
82469-79-2
3734-67-6
6625-46-3
6410-41-9
4477-79-6
70592-80-2
68002-97-1
68131-40-8
73138-27-9
85566-12-7
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
Reference
4
1,2,4
1,4
2,3
1, 2, 3, 4, 6
1, 2, 3, 4, 6, 7
8
1, 2, 3, 4
8
8
1
1,2,4
8
1, 2, 3, 4, 6
2,5
1
8
1,4
1,4
8
4
4
4
4
4
1, 2, 3, 4, 8
1,2,8
3
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-16 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Calcined bauxite
Calcium aluminate
Calcium bromide
Calcium carbide (CaC2)
Calcium chloride
Calcium dichloride dihydrate
Calcium dodecylbenzene sulfonate
Calcium fluoride
Calcium hydroxide
Calcium hypochlorite
Calcium magnesium hydroxide oxide
Calcium oxide
Calcium peroxide
Calcium sulfate
Calcium sulfate dihydrate
Camphor
Canola oil
Carbon black
Carbon dioxide
Carbonic acid calcium salt (1:1)
Carbonic acid, dipotassium salt
Carboxymethyl guar gum, sodium salt
Castor oil
Cedarwood oil
Cellophane
Cellulose
Chloride
Chlorine
Chlorine dioxide
Choline bicarbonate
CASRN
66402-68-4
12042-78-3
7789-41-5
75-20-7
10043-52-4
10035-04-8
26264-06-2
7789-75-5
1305-62-0
7778-54-3
58398-71-3
1305-78-8
1305-79-9
7778-18-9
10101-41-4
76-22-2
120962-03-0
1333-86-4
124-38-9
471-34-1
584-08-7
39346-76-4
8001-79-4
8000-27-9
9005-81-6
9004-34-6
16887-00-6
7782-50-5
10049-04-4
78-73-9
Physico-
chemical
properties
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
2,8
2
4
8
1, 2, 3, 4, 7
1,4
4
1,4
1, 2, 3, 4
1,2,4
4
1, 2, 4, 7
1, 3, 4, 8
1,2,4
2
3
8
1,2,4
1, 3, 4, 6
1,2,4
1, 2, 3, 4, 8
1,2,4
8
3
1,4
1, 2, 3, 4
4,8
2
1, 2, 3, 4, 8
3,8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-17 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Choline chloride
Chromium (III)
Chromium (VI)
Chromium acetate, basic
Chromium(lll) acetate
Citric acid
Citronella oil
Citronellol
Citrus extract
Coal, granular
Cobalt(ll) acetate
Coco-betaine
Coconut oil
Coconut oil acid/Diethanolamine condensate
(2:1)
Coconut trimethylammonium chloride
Copper
Copper sulfate
Copper(l) chloride
Copper(l) iodide
Copper(ll) chloride
Copper(ll) sulfate, pentahydrate
Corn flour
Corn sugar gum
Corundum (Aluminum oxide)
Cottonseed, flour
Coumarin
Cremophor(R) EL
Cristobalite
Crystalline silica, tridymite
CASRN
67-48-1
16065-83-1
18540-29-9
39430-51-8
1066-30-4
77-92-9
8000-29-1
106-22-9
94266-47-4
50815-10-6
71-48-7
68424-94-2
8001-31-8
68603-42-9
61789-18-2
7440-50-8
7758-98-7
7758-89-6
7681-65-4
7447-39-4
7758-99-8
68525-86-0
11138-66-2
1302-74-5
68308-87-2
91-64-5
61791-12-6
14464-46-1
15468-32-3
Physico-
chemical
properties
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
Reference
1, 3, 4, 7, 8
2,6
6
2
1,2
1, 2, 3, 4, 7
3
3
1, 3, 4, 8
1,2,4
1,4
3
8
1
1,8
1,4
1,4,8
1,4
1, 2, 4, 6
1,3,4
8
4
1,2,4
4,8
2,4
3
1,3
1,2,4
1,2,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-18 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Cum en e
Cupric chloride dihydrate
Cyclohexane
Cyclohexanol
Cyclohexanone
Cyclohexylamine sulfate
D&C Red 28
D&C Red No. 33
Daidzein
Dapsone
Dazomet
Decamethylcyclopentasiloxane
Decyldimethylamine
Deuterium oxide
D-Glucitol
D-Gluconic acid
D-Glucopyranoside, methyl
D-Glucose
Di(2-ethylhexyl) phthalate
Diammonium peroxydisulfate
Diatomaceous earth
Diatomaceous earth, calcined
Dibromoacetonitrile
Dicalcium silicate
Dichloromethane
Didecyldimethylammonium chloride
Diethanolamine
Diethylbenzene
Diethylene glycol
CASRN
98-82-8
10125-13-0
110-82-7
108-93-0
108-94-1
19834-02-7
18472-87-2
3567-66-6
486-66-8
80-08-0
533-74-4
541-02-6
1120-24-7
7789-20-0
50-70-4
526-95-4
3149-68-6
50-99-7
117-81-7
7727-54-0
68855-54-9
91053-39-3
3252-43-5
10034-77-2
75-09-2
7173-51-5
111-42-2
25340-17-4
111-46-6
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
Reference
1, 2, 3, 4
1,4,7
1,7
8
1,4
8
4
8
8
1,4
1, 2, 3, 4, 7, 8
8
3,4
8
1,3,4
1,4
2
1,4
1,4
1, 2, 3, 4, 6,
7,8
2,4
1,2,4
1, 2, 3, 4, 8
1,2,4
8
1, 2, 4, 8
1, 2, 3, 4, 6
1,3,4
1, 2, 3, 4, 7
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-19 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Diethylene glycol monomethyl ether
Diethylenetriamine
Diethylenetriamine reaction product with fatty
acid dimers
Diisobutyl ketone
Diisopropanolamine
Diisopropylnaphthalene
Dimethyl adipate
Dimethyl glutarate
Dimethyl polysiloxane
Dimethyl succinate
Dimethylaminoethanol
Dimethyldiallylammonium chloride
Diphenyl oxide
Dipotassium monohydrogen phosphate
Dipropylene glycol
Di-sec-butylphenol
Disodium dodecyl(sulphonatophenoxy)
benzenesulphonate
Disodium ethylenediaminediacetate
Disodium ethylenediaminetetraacetate
dihydrate
Disodium octaborate
Disodium octaborate tetrahydrate
Disodium sulfide
Distillates, petroleum, catalytic reformer
fractionator residue, low-boiling
Distillates, petroleum, heavy arom.
Distillates, petroleum, hydrodesulfurized light
catalytic cracked
Distillates, petroleum, hydrodesulfurized
middle
CASRN
111-77-3
111-40-0
68647-57-4
108-83-8
110-97-4
38640-62-9
627-93-0
1119-40-0
63148-62-9
106-65-0
108-01-0
7398-69-8
101-84-8
7758-11-4
25265-71-8
31291-60-8
28519-02-0
38011-25-5
6381-92-6
12008-41-2
12280-03-4
1313-82-2
68477-31-6
67891-79-6
68333-25-5
64742-80-9
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
Reference
1,2,4
1, 2, 4, 5
2
8
8
3,4
8
1,4
1,2,4
8
2,4
3,4
3
5
1,3,4
1
1
1,4
1
4,8
1,4
8
1,4
1,4
1
1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-20 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Distillates, petroleum, hydrotreated heavy
naphthenic
Distillates, petroleum, hydrotreated heavy
paraffinic
Distillates, petroleum, hydrotreated light
Distillates, petroleum, hydrotreated light
naphthenic
Distillates, petroleum, hydrotreated light
paraffinic
Distillates, petroleum, hydrotreated middle
Distillates, petroleum, light catalytic cracked
Distillates, petroleum, light hydrocracked
Distillates, petroleum, solvent-dewaxed heavy
paraffinic
Distillates, petroleum, solvent-refined heavy
naphthenic
Distillates, petroleum, steam-cracked
Distillates, petroleum, straight-run middle
Distillates, petroleum, sweetened middle
Ditallow alkyl ethoxylated amines
D-Lactic acid
D-Limonene
Docusate sodium
Dodecamethylcyclohexasiloxane
Dodecane
Dodecylbenzene
Dodecylbenzenesulfonic acid
Dodecylbenzenesulfonic acid,
monoethanolamine salt
Edifas B
EDTA, copper salt
Endo- 1,4-. beta. -mannanase
CASRN
64742-52-5
64742-54-7
64742-47-8
64742-53-6
64742-55-8
64742-46-7
64741-59-9
64741-77-1
64742-65-0
64741-96-4
64742-91-2
64741-44-2
64741-86-2
71011-04-6
10326-41-7
5989-27-5
577-11-7
540-97-6
112-40-3
123-01-3
27176-87-0
26836-07-7
9004-32-4
12276-01-6
37288-54-3
Physico-
chemical
properties
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
1, 2, 3, 4
1,2,4
1, 2, 3, 4, 5,
7,8
1,2,8
8
1, 2, 3, 4, 8
1,4
3
1
1,4
1,4
1,2,4
1,4
3
1,4
1, 3, 4, 5, 7, 8
1
8
8
3,4
2, 3, 4, 8
1,4
2,3,4
1,5,6
3,8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-21 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Epichlorohydrin
Epoxy resin
Erucic amidopropyl dimethyl betaine
Ethanaminium, N,N,N-trimethyl-2-[(l-oxo-2-
propenyl)oxy]-, chloride
Ethanaminium, N,N,N-trimethyl-2-[(l-oxo-2-
propenyl)oxy]-,chloride, polymer with 2-
propenamide
Ethanaminium, N,N,N-trimethyl-2-[(2-methyl-l-
oxo-2-propen-l-yl)oxy]-, chloride (1:1), polymer
with 2-propenamide
Ethanaminium, N,N,N-trimethyl-2-[(2-methyl-l-
oxo-2-propenyl)oxy]-, methyl sulfate,
homopolymer
Ethane
Ethanol
Ethanol, 2,2',2"-nitrilotris-, tris(dihydrogen
phosphate) (ester), sodium salt
Ethanol, 2,2'-iminobis-, N-coco alkyl derivs., N-
oxides
Ethanol, 2,2'-iminobis-, N-tallow alkyl derivs.
Ethanol, 2,2'-oxybis-, reaction products with
ammonia, morpholine derivs. residues
Ethanol, 2,2-oxybis-, reaction products with
ammonia, morpholine derivs. residues, acetates
(salts)
Ethanol, 2,2-oxybis-, reaction products with
ammonia, morpholine derivs. residues, reaction
products with sulfur dioxide
Ethanol, 2-[2-[2-(tridecyloxy)ethoxy]ethoxy]-,
hydrogen sulfate, sodium salt
Ethanol, 2-amino-, polymer with formaldehyde
Ethanol, 2-amino-, reaction products with
ammonia, by-products from,
phosphonomethylated
CASRN
106-89-8
25085-99-8
149879-98-1
44992-01-0
69418-26-4
35429-19-7
27103-90-8
74-84-0
64-17-5
68171-29-9
61791-47-7
61791-44-4
68909-77-3
68877-16-7
102424-23-7
25446-78-0
34411-42-2
68649-44-5
Physico-
chemical
properties
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
Reference
1,4,8
1,4,8
1,3
3
1,3,4
8
8
2,5
1, 2, 3, 4, 5,
6,8
4
1
1
4,8
4
4
1,4
4
4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-22 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Ethanolamine
Ethoxylated dodecyl alcohol
Ethoxylated hydrogenated tallow alkylamines
Ethoxylated, propoxylated trimethylolpropane
Ethyl acetate
Ethyl acetoacetate
Ethyl benzoate
Ethyl lactate
Ethyl salicylate
E thylbenzene
Ethylcellulose
Ethylene
Ethylene glycol
Ethylene oxide
Ethylenediamine
Ethylenediaminetetraacetic acid
Ethylenediaminetetraacetic acid tetrasodium
salt
Ethylenediaminetetraacetic acid, diammonium
copper salt
Ethylenediaminetetraacetic acid, disodium salt
Ethyne
Fats and Glyceridic oils, vegetable,
hydrogenated
Fatty acid, tall oil, hexa esters with sorbitol,
ethoxylated
Fatty acids, C 8-18 and C18-unsaturated
compounds with diethanolamine
Fatty acids, C14-18 and C16-18-unsatd., distn.
residues
Fatty acids, C18-unsatd., dimers
CASRN
141-43-5
9002-92-0
61790-82-7
52624-57-4
141-78-6
141-97-9
93-89-0
97-64-3
118-61-6
100-41-4
9004-57-3
74-85-1
107-21-1
75-21-8
107-15-3
60-00-4
64-02-8
67989-88-2
139-33-3
74-86-2
68334-28-1
61790-90-7
68604-35-3
70321-73-2
61788-89-4
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
Reference
1, 2, 3, 4, 6
4
4
3
1,4,7
1,4
3
3
3
1, 2, 3, 4, 7
2
8
1, 2, 3, 4, 6,
7,8
1, 2, 3, 4
2,4
1,2,4
1, 2, 3, 4
4
1, 3, 4, 8
7
8
1,4
3
2
2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-23 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Fatty acids, C18-unsatd., dimers, compds. with
ethoxylated tall-oil fatty acid-
polyethylenepolyamine reaction products
Fatty acids, C18-unsatd., dimers, ethoxylated
propoxylated
Fatty acids, coco, ethoxylated
Fatty acids, coco, reaction products with
diethylenetriamine and soya fatty acids,
ethoxylated, chloromethane-quaternized
Fatty acids, coco, reaction products with
ethanolamine, ethoxylated
Fatty acids, tall oil, reaction products with
acetophenone, formaldehyde and thiourea
Fatty acids, tall-oil
Fatty acids, tall-oil, reaction products with
diethylenetriamine
Fatty acids, tall-oil, reaction products with
diethylenetriamine, maleic anhydride,
tetraethylenepentamine and
triethylenetetramine
Fatty acids, tallow, sodium salts
Fatty acids, vegetable-oil, reaction products
with diethylenetriamine
Fatty quaternary ammonium chloride
FD&C Blue no. 1
FD&C Yellow 5
FD&C Yellow 6
Ferric chloride
Ferric sulfate
Ferrous sulfate monohydrate
Ferumoxytol
Fiberglass
Formaldehyde
CASRN
68132-59-2
68308-89-4
61791-29-5
68604-75-1
61791-08-0
68188-40-9
61790-12-3
61790-69-0
68990-47-6
8052-48-0
68153-72-0
61789-68-2
3844-45-9
1934-21-0
2783-94-0
7705-08-0
10028-22-5
17375-41-6
1309-38-2
65997-17-3
50-00-0
Physico-
chemical
properties
X
X
X
X
Selected
toxic ity
reference
value
X
Reference
8
8
3
8
3
3
1, 2, 3, 4
1,4
8
1,3
3
1,4
1,4
8
8
1,3,4
1,4
2
8
2,3,4
1, 2, 3, 4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-24 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Formaldehyde polymer with 4,1,1-
(dimethylethyl)phenol and methyloxirane
Formaldehyde polymer with methyl oxirane, 4-
nonylphenol and oxirane
Formaldehyde, polymer with 4-(l,l-
dimethylethyl)phenol, 2-methyloxirane and
oxirane
Formaldehyde, polymer with 4-(l,l-
dimethylethyl)phenol, 2-methyloxirane, 4-
nonylphenol and oxirane
Formaldehyde, polymer with 4-nonylphenol
and oxirane
Formaldehyde, polymer with 4-nonylphenol
and phenol
Formaldehyde, polymer with ammonia and
phenol
Formaldehyde, polymer with bisphenol A
Formaldehyde, polymer with Nl-(2-
aminoethyl)-l,2-ethanediamine, benzylated
Formaldehyde, polymer with nonylphenol and
oxirane
Formaldehyde, polymers with branched 4-
nonylphenol, oxirane and 2-methyloxirane
Formaldehyde/ amine
Formamide
Formic acid
Formic acid, potassium salt
Frits, chemicals
Fuel oil, no. 2
Fuels, diesel
Fuels, diesel, no. 2
Fuller's earth
Fumaric acid
Fumes, silica
CASRN
29316-47-0
63428-92-2
30704-64-4
68188-99-8
30846-35-6
40404-63-5
35297-54-2
25085-75-0
70750-07-1
55845-06-2
153795-76-7
50-00-0_3
75-12-7
64-18-6
590-29-4
65997-18-4
68476-30-2
68334-30-5
68476-34-6
8031-18-3
110-17-8
69012-64-2
Physico-
chemical
properties
X
X
X
X
Selected
toxic ity
reference
value
X
Reference
3
4,8
1, 2, 4, 8
8
1,4
8
1,4
4
8
4
13
1, 2, 3, 4
1, 2, 3, 4
1, 2, 3, 4, 6, 7
1,3,4
8
1,2
2
2,4,8
2
1, 2, 3, 4, 6
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-25 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Furfural
Furfuryl alcohol
Galantamine hydrobromide
Gas oils, petroleum, straight-run
Gelatin
Gilsonite
Gluconic acid
Glutaraldehyde
Glycerides, C14-18 and C16-18-unsatd. mono-
and di-
Glycerol
Glycine, N-(carboxymethyl)-N-(2-hydroxyethyl)-
, disodium salt
Glycine, N-(hydroxymethyl)-, monosodium salt
Glycine, N,N-bis(carboxymethyl)-, trisodium salt
Glycine, N-[2-[bis(carboxymethyl)amino]ethyl]-
N-(2-hydroxyethyl)-, trisodium salt
Glycolic acid
Glycolic acid sodium salt
Glyoxal
Glyoxylic acid
Goethite (Fe(OH)O)
Guar gum
Guargum, carboxymethyl 2-hydroxypropyl
ether, sodium salt
Gypsum (Ca(SO4).2H2O)
Hematite
Hemicellulase
Hemicellulase enzyme concentrate
Heptane
Heptene, hydroformylation products, high-
boiling
CASRN
98-01-1
98-00-0
69353-21-5
64741-43-1
9000-70-8
12002-43-6
133-42-6
111-30-8
67701-32-0
56-81-5
135-37-5
70161-44-3
5064-31-3
139-89-9
79-14-1
2836-32-0
107-22-2
298-12-4
1310-14-1
9000-30-0
68130-15-4
13397-24-5
1317-60-8
9012-54-8
9025-56-3
142-82-5
68526-88-5
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
1,4
1,4
8
1,4
1,4
1,2,4
7
1, 2, 3, 4, 7
8
1, 2, 3, 4, 5
1
8
1, 2, 3, 4
1
1,3,4
1,3,4
1,2,4
1
8
1, 2, 3, 4, 7, 8
1, 2, 3, 4, 7
2,4
1,2,4
1, 2, 3, 4, 5
3,4
1,2
1,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-26 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Hexadecyltrimethylammonium bromide
Hexane
Hexanedioic acid
Humic acids, commercial grade
Hydrazine
Hydrocarbons, terpene processing by-products
Hydrochloric acid
Hydrogen fluoride
Hydrogen peroxide
Hydrogen sulfide
Hydroxyethylcellulose
Hydroxylamine hydrochloride
Hydroxylamine sulfate (2:1)
Hydroxypropyl cellulose
Hydroxypropyl guar gum
Hydroxyvalerenic acid
Hypochlorous acid
Illite
llmenite (FeTiCh), cone.
Indole
Inulin, carboxymethyl ether, sodium salt
Iridium oxide
Iron
Iron oxide
Iron oxide (FesCU)
Iron(ll) sulfate
Iron(ll) sulfate heptahydrate
Iron(lll) oxide
Isoascorbic acid
CASRN
57-09-0
110-54-3
124-04-9
1415-93-6
302-01-2
68956-56-9
7647-01-0
7664-39-3
7722-84-1
7783-06-4
9004-62-0
5470-11-1
10039-54-0
9004-64-2
39421-75-5
1619-16-5
7790-92-3
12173-60-3
98072-94-7
120-72-9
430439-54-6
12030-49-8
7439-89-6
1332-37-2
1317-61-9
7720-78-7
7782-63-0
1309-37-1
89-65-6
Physico-
chemical
properties
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
Reference
1
5
1, 2, 4, 6
2
8
1,3,4
1, 2, 3, 4, 5,
6,7,8
1,2,4
1,3,4
1,2
1, 2, 3, 4
1,3,4
4
2,4
1, 3, 4, 5, 6, 8
8
8
8
8
2
1,4
8
2,4
1,4
4
2
1, 2, 3, 4
1,2,4
1,3,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-27 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Isobutane
Isobutene
Isooctanol
Isopentyl alcohol
Isopropanol
Isopropanolamine dodecylbenzene
Isopropylamine
Isoquinoline
Isoquinoline, reaction products with benzyl
chloride and quinoline
Isoquinolinium, 2-(phenylmethyl)-, chloride
Isotridecanol, ethoxylated
Kaolin
Kerosine, petroleum, hydrodesulfurized
Kieselguhr
Kyanite
Lactic acid
Lactose
Latex 2000 TM
Lauryl hydroxysultaine
Lavandula hybrida abrial herb oil
L-Dilactide
Lead
Lecithin
L-Glutamic acid
Lignite
Lignosulfuric acid
Ligroine
Limestone
Linseed oil
CASRN
75-28-5
115-11-7
26952-21-6
123-51-3
67-63-0
42504-46-1
75-31-0
119-65-3
68909-80-8
35674-56-7
9043-30-5
1332-58-7
64742-81-0
61790-53-2
1302-76-7
50-21-5
63-42-3
9003-55-8
13197-76-7
8022-15-9
4511-42-6
7439-92-1
8002-43-5
56-86-0
129521-66-0
8062-15-5
8032-32-4
1317-65-3
8001-26-1
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
Reference
2
8
1,4,5
1,4
1, 2, 3, 4, 6, 7
1,3,4
1,4
8
3
3
1, 3, 4, 8
1,2,4
1,2,4
1,2,4
1,2,4
1,4,8
3
2,4
1
3
1,4
1,4
4
8
2
2
8
1, 2, 3, 4
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-28 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
L-Lactic acid
Magnesium carbonate (1:1)
Magnesium carbonate (l:x)
Magnesium chloride
Magnesium chloride hexahydrate
Magnesium hydroxide
Magnesium iron silicate
Magnesium nitrate
Magnesium oxide
Magnesium peroxide
Magnesium phosphide
Magnesium silicate
Magnesium sulfate
Maleicacid homopolymer
Methanamine-N-methyl polymer with
chloromethyl oxirane
Methane
Methanol
Methenamine
Methoxyacetic acid
Methyl cellulose
Methyl salicylate
Methyl vinyl ketone
Methylcyclohexane
Methylene bis(thiocyanate)
Methylenebis(5-methyloxazolidine)
Methyloxirane polymer with oxirane, mono
(nonylphenol) ether, branched
Mica
Mineral oil - includes paraffin oil
CASRN
79-33-4
7757-69-9
546-93-0
7786-30-3
7791-18-6
1309-42-8
19086-72-7
10377-60-3
1309-48-4
14452-57-4
12057-74-8
1343-88-0
7487-88-9
26099-09-2
25988-97-0
74-82-8
67-56-1
100-97-0
625-45-6
9004-67-5
119-36-8
78-94-4
108-87-2
6317-18-6
66204-44-2
68891-11-2
12001-26-2
8012-95-1
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
1,4,8
8
1,3,4
1,2,4
4
1,4
1,4
1,2,4
1, 2, 3, 4
1,4
1
1,4
8
8
4
2,5
1, 2, 3, 4, 5,
6,7,8
1,2,4
8
8
1, 2, 3, 4, 7
1,4
1
2
2
3
1, 2, 4, 6
4,8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-29 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Mineral spirits
Mono- and di- potassium salts of phosphorous
acid
Montmorillonite
Morpholine
Morpholinium, 4-ethyl-4-hexadecyl-, ethyl
sulfate
MT6
Mullite
N-(2-Acryloyloxyethyl)-N-benzyl-N,N-
dimethylammonium chloride
N-(3-Chloroallyl)hexaminium chloride
N,N,N-Trimethyl-2[l-oxo-2-propenyl]oxy
ethanaminimum chloride, homopolymer
N,N,N-Trimethyl-3-((l-oxooctadecyl)amino)-l-
propanaminium methyl sulfate
N,N,N-Trimethyloctadecan-l-aminium chloride
N,N'-Dibutylthiourea
N,N-Dimethyldecylamine oxide
N,N-Dimethylformamide
N,N-Dimethylmethanamine hydrochloride
N,N-Dimethyl-methanamine-N-oxide
N,N-dimethyloctadecylamine hydrochloride
N,N'-Methylenebisacrylamide
Naphtha, petroleum, heavy catalytic reformed
Naphtha, petroleum, hydrotreated heavy
Naphthalene
Naphthalenesulfonic acid, bis(l-methylethyl)-
Naphthalenesulfonic acid, polymer with
formaldehyde, sodium salt
Naphthalenesulphonic acid, bis (1-methylethyl)-
methyl derivatives
CASRN
64475-85-0
13492-26-7
1318-93-0
110-91-8
78-21-7
76-31-3
1302-93-8
46830-22-2
4080-31-3
54076-97-0
19277-88-4
112-03-8
109-46-6
2605-79-0
68-12-2
593-81-7
1184-78-7
1613-17-8
110-26-9
64741-68-0
64742-48-9
91-20-3
28757-00-8
9084-06-4
99811-86-6
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
2
8
2
1,2,4
8
8
1,2, 4, 8
3
8
3
1
1,3,4
1,4
1,3,4
1, 2, 4, 5, 8
1, 4, 5, 7
3
1,4
1,4
1, 2, 3, 4
1, 2, 3, 4, 8
1, 2, 3, 4, 5, 7
1,3,4
2
1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-30 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Naphthenic acid ethoxylate
Navy fuels JP-5
Nickel sulfate
Nickel(ll) sulfate hexahydrate
Nitriles, tallow, hydrogenated
Nitrilotriacetamide
Nitrilotriacetic acid
Nitrilotriacetic acid trisodium monohydrate
Nitrogen
N-Methyl-2-pyrrolidone
N-Methyldiethanolamine
N-Methylethanolamine
N-Methyl-N-hydroxyethyl-N-
hydroxyethoxyethylamine
N-Oleyl diethanolamide
Nonyl nonoxynol-10
Nonylphenol (mixed)
Octamethylcyclotetrasiloxane
Octoxynol-9
Oil of eucalyptus
Oil of lemongrass
Oil of rosemary
Oleic acid
Olivine-group minerals
Orange terpenes
Oxirane, 2-methyl-, polymer with oxirane, ether
with (chloromethyl) oxirane polymer with 4,4'-
(1-methylidene) bis[phenol]
Oxirane, 2-methyl-, polymer with oxirane,
mono(2-ethylhexyl) ether
Oxirane, 2-methyl-, polymer with oxirane,
monodecyl ether
CASRN
68410-62-8
8008-20-6_2
7786-81-4
10101-97-0
61790-29-2
4862-18-4
139-13-9
18662-53-8
7727-37-9
872-50-4
105-59-9
109-83-1
68213-98-9
13127-82-7
9014-93-1
25154-52-3
556-67-2
9036-19-5
8000-48-4
8007-02-1
8000-25-7
112-80-1
1317-71-1
8028-48-6
68036-95-3
64366-70-7
37251-67-5
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
Reference
4
1, 2, 3, 4, 8
2
1,4
4
1,4,7
1,4
1,4
1, 2, 3, 4, 6
1,4
2,4,8
4
4
1,4
4
1,4
8
1, 2, 3, 4, 8
3
3
3
2,4
4
4
8
8
8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-31 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Oxirane, methyl-, polymer with oxirane, mono-
C10-16-alkyl ethers, phosphates
Oxygen
Ozone
Paraffin waxes and Hydrocarbon waxes
Paraformaldehyde
PEG- 10 Hydrogenated tallow amine
Pentaethylenehexamine
Pentane
Pentyl acetate
Pentyl butyrate
Peracetic acid
Perboric acid, sodium salt, monohydrate
Perlite
Petrolatum, petroleum, oxidized
Petroleum
Petroleum distillate hydrotreated light
Phenanthrene
Phenol
Phenol, 4,4'-(l-methylethylidene)bis-, polymer
with 2-(chloromethyl)oxirane, 2-methyloxirane
and oxirane
Phenol-formaldehyde resin
Phosphine
Phosphonic acid
Phosphonic acid (dimethylamino(methylene))
Phosphonic acid, (((2-[(2-
hydroxyethyl)(phosphonomethyl)amino)ethyl)i
mino]bis(methylene))bis-, compd. with 2-
aminoethanol
Phosphonic acid, (l-hydroxyethylidene)bis-,
potassium salt
CASRN
68649-29-6
7782-44-7
10028-15-6
8002-74-2
30525-89-4
61791-26-2
4067-16-7
109-66-0
628-63-7
540-18-1
79-21-0
10332-33-9
93763-70-3
64743-01-7
8002-05-9
6742-47-8
85-01-8
108-95-2
68123-18-2
9003-35-4
7803-51-2
13598-36-2
29712-30-9
129828-36-0
67953-76-8
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
1,4
4
8
1
2
1,3
4
2,5
3
3
8
1,8
4
3
1,2
8
6
1,2,4
8
1, 2, 4, 7
1,4
1,4
1
1
4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-32 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Phosphonic acid, (l-hydroxyethylidene)bis-,
tetrasodium salt
Phosphonic acid,
[[(phosphonomethyl)imino]bis[2,l-
ethanediylnitrilobis(methylene)]]tetrakis-
Phosphonicacid,
[[(phosphonomethyl)imino]bis[2,l-
ethanediylnitrilobis(methylene)]]tetrakis-,
ammonium salt (l:x)
Phosphonic acid,
[[(phosphonomethyl)imino]bis[2,l-
ethanediylnitrilobis(methylene)]]tetrakis-,
sodium salt
Phosphonic acid,
[[(phosphonomethyl)imino]bis[6,l-
hexanediylnitrilobis(methylene)]]tetrakis-
Phosphoric acid
Phosphoric acid, aluminium sodium salt
Phosphoric acid, ammonium salt (1:3)
Phosphoric acid, diammonium salt
Phosphoric acid, mixed decyl and Et and octyl
esters
Phosphorous acid
Phthalic anhydride
Pine oils
Pluronic F-127
Policapram (Nylon 6)
Poly (acrylamide-co-acrylic acid), partial sodium
salt
Poly(acrylamide-co-acrylic acid)
Poly(lactide)
Poly(oxy-l,2-ethanediyl), .alpha.-(nonylphenyl)-
. omega. -hydroxy-, phosphate
Poly(oxy-l,2-ethanediyl), .alpha.-(octylphenyl)-
. omega. -hydroxy-, branched
CASRN
3794-83-0
15827-60-8
70714-66-8
22042-96-2
34690-00-1
7664-38-2
7785-88-8
10361-65-6
7783-28-0
68412-60-2
10294-56-1
85-44-9
8002-09-3
9003-11-6
25038-54-4
62649-23-4
9003-06-9
26680-10-4
51811-79-1
68987-90-6
Physico-
chemical
properties
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
Reference
1,4
1,2,4
3
3
1,4,8
1,2,4
1,2
8
2
1
1
1,4
1,2,4
1, 3, 4, 8
1,4
3,4
4,8
1
1,4
1,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-33 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Poly(oxy-l,2-ethanediyl), .alpha.,. alpha. l-[[(9Z)-
9-octadecenylimino]di-2,l-
ethanediyl]bis[.omega.-hydroxy-
Poly(oxy-l,2-ethanediyl), .alpha.-[(9Z)-l-oxo-9-
octadecenyl]-.omega.-hydroxy-
Poly(oxy-l,2-ethanediyl), .alpha.-hydro-
.omega. -hydroxy-, mono-C10-14-alkyl ethers,
phosphates
Poly(oxy-l,2-ethanediyl), .alpha.-hydro-
. omega. -hydroxy-, mono-C8-10-alkyl ethers,
phosphates
Poly(oxy-l,2-ethanediyl), . alpha. -isodecyl-
. omega. -hydroxy-
Poly(oxy-l,2-ethanediyl), .alpha.-sulfo-.omega.-
hydroxy-, C10-16-alkyl ethers, sodium salts
Poly(oxy-l,2-ethanediyl), . alpha. -sulfo-. omega. -
hydroxy-, C12-14-alkyl ethers, sodium salts
Poly(oxy-l,2-ethanediyl), alpha-(2,3,4,5-
tetramethylnonyl)-omega-hydroxy
Poly(oxy-l,2-ethanediyl), alpha-(nonylphenyl)-
omega-hydroxy-,branched, phosphates
Poly(oxy-l,2-ethanediyl), alpha-hexyl-omega-
hydroxy
Poly(oxy-l,2-ethanediyl), alpha-hydro-omega-
hydroxy-, (9Z)-9-octadecenoate
Poly(oxy-l,2-ethanediyl), alpha-hydro-omega-
hydroxy-, ether with alpha-fluoro-omega-(2-
hydroxyethyl)poly(difluoromethylene) (1:1)
Poly(oxy-l,2-ethanediyl), alpha-hydro-omega-
hydroxy-, ether with D-glucitol (2:1), tetra-(9Z)-
9-octadecenoate
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-
(decyloxy)-, ammonium salt (1:1)
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-
(hexyloxy)-, ammonium salt (1:1)
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-
(hexyloxy)-, C6-10-alkyl ethers, ammonium salts
CASRN
26635-93-8
9004-96-0
68585-36-4
68130-47-2
61827-42-7
68585-34-2
68891-38-3
68015-67-8
68412-53-3
31726-34-8
56449-46-8
65545-80-4
61723-83-9
52286-19-8
63428-86-4
68037-05-8
Physico-
chemical
properties
Selected
toxic ity
reference
value
Reference
1,4
8
8
8
8
8
1,4
1
1
3,8
3
1
8
4
1,3,4
3,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-34 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega—
(nonylphenoxy)-
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-
(octyloxy)-, ammonium salt (1:1)
Poly(oxy-l,2-ethanediyl), alpha-sulfo-omega-
hydroxy-, C10-12-alkyl ethers, ammonium salts
Poly(oxy-l,2-ethanediyl), alpha-tridecyl-omega-
hydroxy-
Poly(oxy-l,2-ethanediyl), alpha-undecyl-omega-
hydroxy-, branched and linear
Poly-(oxy-l,2-ethanediyl)-alpha-undecyl-
omega-hydroxy
Poly(oxy-l,2-ethanediyl)-nonylphenyl-hydroxy
branched
Poly(sodium-p-styrenesulfonate)
Poly(tetrafluoroethylene)
Poly [imino(l,6-dioxo-l,6-hexanediyl)imino- 1,6-
hexanediyl]
Polyacrylamide
Polyacrylate/ polyacrylamide blend
Polyacrylic acid, sodium bisulfite terminated
Polyethylene glycol
Polyethylene glycol (9Z)-9-octadecenyl ether
Polyethylene glycol ester with tall oil fatty acid
Polyethylene glycol monobutyl ether
Polyethylene glycol mono-C8-10-alkyl ether
sulfate ammonium
Polyethylene glycol nonylphenyl ether
Polyethylene glycol tridecyl ether phosphate
Polyethyleneimine
Polyglycerol
Poly-L-aspartic acid sodium salt
Polyoxyethylene sorbitan trioleate
CASRN
9081-17-8
52286-18-7
68890-88-0
24938-91-8
127036-24-2
34398-01-1
127087-87-0
25704-18-1
9002-84-0
32131-17-2
9003-05-8
NOCAS_51256
66019-18-9
25322-68-3
9004-98-2
68187-85-9
9004-77-7
68891-29-2
9016-45-9
9046-01-9
9002-98-6
25618-55-7
34345-47-6
9005-70-3
Physico-
chemical
properties
Selected
toxic ity
reference
value
Reference
4
4
8
1,3,4
1
1, 3, 4, 8
1, 2, 3, 4
1,4
8
2
1, 2, 4, 6
2
3
1, 2, 3, 4, 7, 8
8
1
1,4
1,3,4
1, 2, 3, 4, 8
1,3,4
4
2
8
3
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-35 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Polyoxyethylene(10)nonylphenyl ether
Polyoxyl 15 hydroxystearate
Polyoxypropylenediamine
Polyphosphoric acids, esters with
triethanolamine, sodium salts
Polyphosphoric acids, sodium salts
Polypropylene glycol
Polypropylene glycol glycerol triether,
epichlorohydrin, bisphenol A polymer
Polyquaternium 5
Polysorbate 20
Polysorbate 60
Polysorbate 80
Polyvinyl acetate copolymer
Polyvinyl acetate, partially hydrolyzed
Polyvinyl alcohol
Polyvinyl alcohol/polyvinyl acetate copolymer
Polyvinylidene chloride
Polyvinylpyrrolidone
Portland cement
Potassium acetate
Potassium aluminum silicate
Potassium antimonate
Potassium bisulfate
Potassium borate
Potassium borate (l:x)
Potassium carbonate sesquihydrate
Potassium chloride
Potassium dichromate
Potassium hydroxide
CASRN
26027-38-3
70142-34-6
9046-10-0
68131-72-6
68915-31-1
25322-69-4
68683-13-6
26006-22-4
9005-64-5
9005-67-8
9005-65-6
9003-20-7
304443-60-5
9002-89-5
NOCAS_50147
9002-85-1
9003-39-8
65997-15-1
127-08-2
1327-44-2
29638-69-5
7646-93-7
12712-38-8
20786-60-1
6381-79-9
7447-40-7
7778-50-9
1310-58-3
Physico-
chemical
properties
X
Selected
toxic ity
reference
value
X
Reference
1, 2, 3, 4, 8
8
1
1
1,4
1,2,4
1
1,4
8
3,4
3,4
2
8
1,2,4
2
8
8
2,4
1,3,4
5
1,4
8
3
1,3
5
1, 2, 3, 4, 5,
6,7
4
1, 2, 3, 4, 6
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-36 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Potassium iodide
Potassium metaborate
Potassium oleate
Potassium oxide
Potassium persulfate
Potassium phosphate, tribasic
Potassium sulfate
Propane
Propanol, l(or 2)-(2-methoxymethylethoxy)-
Propargyl alcohol
Propylene carbonate
Propylene pentamer
p-Xylene
Pyridine, alkyl derivs.
Pyridinium, l-(phenylmethyl)-, alkyl derivs.,
chlorides
Pyridinium, l-(phenylmethyl)-, C7-8-alkyl
derivs., chlorides
Pyrimidine
Pyrrole
Quartz-alpha (SiO2)
Quaternary ammonium compounds (2-
ethylhexyl) hydrogenated tallow alkyl)dimethyl,
methyl sulfates
Quaternary ammonium compounds, (oxydi-2,1-
ethanediyl)bis[coco alkyldimethyl, dichlorides
Quaternary ammonium compounds,
benzyl(hydrogenated tallow alkyl)dimethyl,
bis(hydrogenated tallow
alkyl)dimethylammonium salt with bentonite
CASRN
7681-11-0
13709-94-9
143-18-0
12136-45-7
7727-21-1
7778-53-2
7778-80-5
74-98-6
34590-94-8
107-19-7
108-32-7
15220-87-8
106-42-3
68391-11-7
100765-57-9
70914-44-2
289-95-2
109-97-7
14808-60-7
308074-31-9
68607-28-3
71011-25-1
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
Reference
1,4
1, 2, 3, 4, 8
4
1,4
1,2,4
8
2
2,5
1, 2, 3, 4
1, 2, 3, 4, 5,
6,7,8
1,4
1
1,4
1,4
4,8
6
2
2
1, 2, 3, 4, 5,
6,8
8
2, 3, 4, 8
8
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Quaternary ammonium compounds,
benzylbis(hydrogenated tallow alkyl)methyl,
salts with bentonite
Quaternary ammonium compounds, benzyl-
C10-16-alkyldimethyl, chlorides
Quaternary ammonium compounds, benzyl-
C12-16-alkyldimethyl, chlorides
Quaternary ammonium compounds, benzyl-
C12-18-alkyldimethyl, chlorides
Quaternary ammonium compounds,
bis(hydrogenated tallow alkyl)dimethyl, salts
with bentonite
Quaternary ammonium compounds,
bis(hydrogenated tallow alkyl)dimethyl, salts
with hectorite
Quaternary ammonium compounds, di-C8-10-
alkyldimethyl, chlorides
Quaternary ammonium compounds, dicoco
alkyldimethyl, chlorides
Quaternary ammonium compounds,
pentamethyltallowalkyltrimethylenedi-,
dichlorides
Quaternary ammonium compounds,
trimethyltallow alkyl, chlorides
Quinaldine
Quinoline
Raffinates (petroleum)
Raffinates, petroleum, sorption process
Residual oils, petroleum, solvent-refined
Residues, petroleum, catalytic reformer
fractionator
Rhodamine B
Rosin
Rutile titanium dioxide
Sand
CASRN
68153-30-0
68989-00-4
68424-85-1
68391-01-5
68953-58-2
71011-27-3
68424-95-3
61789-77-3
68607-29-4
8030-78-2
91-63-4
91-22-5
68514-29-4
64741-85-1
64742-01-4
64741-67-9
81-88-9
8050-09-7
1317-80-2
308075-07-2
Physico-
chemical
properties
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
2,5,6
1,4
1, 2, 4, 8
8
2, 3, 4, 8
2
2
1
4
1,4
8
2,4
5
1, 2, 4, 8
5
1,4,8
4
1,4
8
8
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Scandium oxide
Sepiolite
Silane, dichlorodimethyl-, reaction products
with silica
Silica
silica gel, cryst. -free
Silica, amorphous, fumed, cryst.-free
Silica, vitreous
Silicic acid, aluminum potassium sodium salt
Siloxanes (Polysiloxane)
Siloxanes and Silicones, di-Me, 3-hydroxypropyl
Me, ethoxylated propoxylated
Siloxanes and Silicones, di-Me, Me hydrogen
Siloxanes and silicones, di-Me, polymers with
Me silsesquioxanes
Siloxanes and Silicones, di-Me, reaction
products with silica
Siloxanes and silicones, dimethyl,
Silwet 177
Sodium 1-octanesulfonate
Sodium 2-mercaptobenzothiolate
Sodium acetate
Sodium aluminate
Sodium benzoate
Sodium bicarbonate
Sodium bis(tridecyl) sulfobutanedioate
Sodium bisulfite
Sodium borate
Sodium bromate
Sodium bromide
Sodium bromosulfamate
CASRN
12060-08-1
63800-37-3
68611-44-9
7631-86-9
112926-00-8
112945-52-5
60676-86-0
12736-96-8
9011-19-2
68937-55-3
68037-59-2
68037-74-1
67762-90-7
63148-52-7
27306-78-1
5324-84-5
2492-26-4
127-09-3
1302-42-7
532-32-1
144-55-8
2673-22-5
7631-90-5
1333-73-9
7789-38-0
7647-15-6
1004542-84-0
Physico-
chemical
properties
X
X
X
X
X
X
Selected
toxic ity
reference
value
Reference
8
2
2,4
1, 2, 3, 4, 8
3,4
1,3,4
1,4,8
4
4
8
8
4
4
4
1
3
2
1,3,4
2,4
3
1, 2, 3, 4, 7
4
1,3,4
1, 4, 6, 7
1,2,4
1, 2, 3, 4, 7
8
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Sodium C14-16 alpha-olefin sulfonate
Sodium caprylamphopropionate
Sodium carbonate
Sodium chlorate
Sodium chloride
Sodium chlorite
Sodium chloroacetate
Sodium cocaminopropionate
Sodium decyl sulfate
Sodium D-gluconate
Sodium diacetate
Sodium dichloroisocyanurate
Sodium dl-lactate
Sodium dodecyl sulfate
Sodium erythorbate (1:1)
Sodium ethasulfate
Sodium formate
Sodium hydrogen sulfate
Sodium hydroxide
Sodium hydroxymethanesulfonate
Sodium hypochlorite
Sodium iodide
Sodium ligninsulfonate
Sodium l-lactate
Sodium maleate (l:x)
Sodium metabisulfite
Sodium metaborate
Sodium metaborate dihydrate
Sodium metaborate tetrahydrate
Sodium metasilicate
CASRN
68439-57-6
68610-44-6
497-19-8
7775-09-9
7647-14-5
7758-19-2
3926-62-3
68608-68-4
142-87-0
527-07-1
126-96-5
2893-78-9
72-17-3
151-21-3
6381-77-7
126-92-1
141-53-7
7681-38-1
1310-73-2
870-72-4
7681-52-9
7681-82-5
8061-51-6
867-56-1
18016-19-8
7681-57-4
7775-19-1
16800-11-6
10555-76-7
6834-92-0
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
Reference
1,3,4
4
1, 2, 3, 4, 8
1,4
1, 2, 3, 4, 5, 8
1, 2, 3, 4, 5, 8
3
1
1
4
1,4
2
8
8
1, 3, 4, 8
1
2,8
4
1, 2, 3, 4, 7, 8
8
1, 2, 3, 4, 8
4
2
8
8
1
3,4
1,4
1,4,8
1,2,4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-40 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Sodium molybdate(VI)
Sodium nitrate
Sodium nitrite
Sodium N-methyl-N-oleoyltaurate
Sodium octyl sulfate
Sodium oxide
Sodium perborate
Sodium perborate tetrahydrate
Sodium peroxoborate
Sodium persulfate
Sodium phosphate
Sodium polyacrylate
Sodium pyrophosphate
Sodium salicylate
Sodium sesquicarbonate
Sodium silicate
Sodium starch glycolate
Sodium sulfate
Sodium sulfite
Sodium thiocyanate
Sodium thiosulfate
Sodium thiosulfate, pentahydrate
Sodium trichloroacetate
Sodium trimetaphosphate
Sodium xylenesulfonate
Sodium zirconium lactate
Sodium zirconium lactic acid (4:4:1)
Solvent naphtha, petroleum, heavy aliph.
Solvent naphtha, petroleum, heavy arom.
Solvent naphtha, petroleum, light aliph.
CASRN
7631-95-0
7631-99-4
7632-00-0
137-20-2
142-31-4
1313-59-3
11138-47-9
10486-00-7
7632-04-4
7775-27-1
7632-05-5
9003-04-7
7758-16-9
54-21-7
533-96-0
1344-09-8
9063-38-1
7757-82-6
7757-83-7
540-72-7
7772-98-7
10102-17-7
650-51-1
7785-84-4
1300-72-7
15529-67-6
10377-98-7
64742-96-7
64742-94-5
64742-89-8
Physico-
chemical
properties
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
8
2
1,2,4
4
1
1
4
1, 4, 5, 8
1
1, 2, 3, 4, 7, 8
1,4
1, 2, 3, 4
1,2,4
1,4
1,2
1,2,4
2
1, 2, 3, 4
2,4,8
1,4
1, 2, 3, 4
1,4
1,4
8
1,3,4
8
1,4
2,4,8
1, 2, 4, 5, 8
8
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Solvent naphtha, petroleum, light arom.
Sorbic acid
Sorbitan sesquioleate
Sorbitan, mono-(9Z)-9-octadecenoate
Sorbitan, monooctadecanoate
Sorbitan, tri-(9Z)-9-octadecenoate
Spirit of ammonia, aromatic
Stannous chloride dihydrate
Starch
Steam cracked distillate, cyclodiene dimer,
dicyclopentadiene polymer
Stoddard solvent
Stoddard solvent IIC
Strontium chloride
Styrene
Subtilisin
Sucrose
Sulfamic acid
Sulfan blue
Sulfate
Sulfo NHS Biotin
Sulfomethylated quebracho
Sulfonic acids, C10-16-alkane, sodium salts
Sulfonic acids, petroleum
Sulfonic acids, petroleum, sodium salts
Sulfur dioxide
Sulfuric acid
Sulfuric acid, mono-C12-18-alkyl esters, sodium
salts
Sulfuric acid, mono-C6-10-alkyl esters,
ammonium salts
CASRN
64742-95-6
110-44-1
8007-43-0
1338-43-8
1338-41-6
26266-58-0
8013-59-0
10025-69-1
9005-25-8
68131-87-3
8052-41-3
64742-88-7
10476-85-4
100-42-5
9014-01-1
57-50-1
5329-14-6
129-17-9
14808-79-8
119616-38-5
68201-64-9
68608-21-9
61789-85-3
68608-26-4
7446-09-5
7664-93-9
68955-19-1
68187-17-7
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
1,2,4
8
4
1, 2, 3, 4
8
8
8
1,4
1,2,4
1
1,3,4
1,2,4
4
2
8
1, 2, 3, 4
1,4
8
1,4
8
2
6
1
3
2,4,8
1, 2, 4, 7
4
1,4,8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-42 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Symclosene
Talc
Tall oil
Tall oil imidazoline
Tall oil, compound with diethanolamine
Tall oil, ethoxylated
Tall-oil pitch
Tallow alkyl amines acetate
Tar bases, quinoline derivatives, benzyl
chloride-quaternized
Tegin M
Terpenes and Terpenoids, sweet orange-oil
Terpineol
tert-Butyl hydroperoxide
tert-Butyl perbenzoate
Tetra-calcium-alumino-ferrite
Tetradecane
Tetradecyldimethylbenzylammonium chloride
Tetraethylene glycol
Tetraethylenepentamine
Tetrakis(hydroxymethyl)phosphonium sulfate
Tetramethyl orthosilicate
Tetramethylammonium chloride
Tetrasodium pyrophosphate
Thiamine hydrochloride
Thiocyanic acid, ammonium salt
Thioglycolic acid
Thiourea
Thiourea, polymer with formaldehyde and 1-
phenylethanone
Thuja plicata donn ex. D. don leaf oil
CASRN
87-90-1
14807-96-6
8002-26-4
61791-36-4
68092-28-4
65071-95-6
8016-81-7
61790-60-1
72480-70-7
8043-29-6
68647-72-3
8000-41-7
75-91-2
614-45-9
12068-35-8
629-59-4
139-08-2
112-60-7
112-57-2
55566-30-8
681-84-5
75-57-0
7722-88-5
67-03-8
1762-95-4
68-11-1
62-56-6
68527-49-1
68917-35-1
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
Reference
2
1, 3, 4, 6, 7
4,8
4
1
4,8
4
8
1,3,4
8
1, 3, 4, 8
1,3
1,4
1
1,2,4
8
1,4,8
1,4
1,4
1, 2, 3, 4, 7
1
1, 2, 3, 4, 7, 8
8
8
2,3,4
1, 2, 3, 4
1, 2, 3, 4, 6
1,4,8
3
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-43 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Tin(ll) chloride
Titanium dioxide
Titanium(4+) 2-[bis(2-
hydroxyethyl)amino]ethanolate propan-2-olate
(1:2:2)
Titanium, isopropoxy (triethanolaminate)
Toluene
Tributyl phosphate
Tributyltetradecylphosphonium chloride
Tricalcium phosphate
Tricalcium silicate
Tridecane
Triethanolamine
Triethanolamine hydrochloride
Triethanolamine hydroxyacetate
Triethanolamine polyphosphate ester
Triethyl citrate
Triethyl phosphate
Triethylene glycol
Triethylenetetramine
Triisopropanolamine
Trimethanolamine
Trimethyl borate
Trimethylamine
Trimethylamine quaternized
polyepichlorohydrin
Trimethylbenzene
Triphosphoric acid, pentasodium salt
Tripoli
Tripotassium citrate monohydrate
Tripropylene glycol monomethyl ether
CASRN
7772-99-8
13463-67-7
36673-16-2
74665-17-1
108-88-3
126-73-8
81741-28-8
7758-87-4
12168-85-3
629-50-5
102-71-6
637-39-8
68299-02-5
68131-71-5
77-93-0
78-40-0
112-27-6
112-24-3
122-20-3
14002-32-5
121-43-7
75-50-3
51838-31-4
25551-13-7
7758-29-4
1317-95-9
6100-05-6
25498-49-1
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
Reference
1
1,2,4
1
1,4
1,3,4
1,2,4
1,3,4
1,4
1,2,4
8
1,2,4
8
3
1,4,8
1,4
1,4
1,2,3
4
1,4
3
8
8
1, 2, 3, 4, 5, 8
1,2,4
1,4
4
4
2
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Trisodium citrate
Trisodium citrate dihydrate
Trisodium ethylenediaminetetraacetate
Trisodium ethylenediaminetriacetate
Trisodium phosphate
Trisodium phosphate dodecahydrate
Tritan R (X-100)
Triton X-100
Tromethamine
Tryptone
Ulexite
Undecane
Undecanol, branched and linear
Urea
Vermiculite
Vinyl acetate ethylene copolymer
Vinylidene chloride/methylacrylate copolymer
Water
White mineral oil, petroleum
Xylenes
Yeast extract
Zeolites
Zinc
Zinc carbonate
Zinc chloride
Zinc oxide
Zinc sulfate monohydrate
Zirconium nitrate
Zirconium oxide sulfate
Zirconium oxychloride
CASRN
68-04-2
6132-04-3
150-38-9
19019-43-3
7601-54-9
10101-89-0
92046-34-9
9002-93-1
77-86-1
73049-73-7
1319-33-1
1120-21-4
128973-77-3
57-13-6
1318-00-9
24937-78-8
25038-72-6
7732-18-5
8042-47-5
1330-20-7
8013-01-2
1318-02-1
7440-66-6
3486-35-9
7646-85-7
1314-13-2
7446-19-7
13746-89-9
62010-10-0
7699-43-6
Physico-
chemical
properties
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
Reference
3
1,4
1,3
1,4,8
1,2,4
1
8
1,3,4
3,4
8
1, 2, 3, 8
3,8
8
1, 2, 4, 8
2
1,4
4
2,4,8
1,2,4
1,2,4
8
8
2
2
1,2
1,4
8
2,6
1,4
1,2,4
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Chemical name
Zirconium(IV) chloride tetrahydrofuran complex
Zirconium(IV) sulfate
Zirconium, l,l'-((2-((2-hydroxyethyl)(2-
hydroxypropyl)amino)ethyl)imino)bis(2-
propanol) complexes
Zirconium, acetate lactate oxo ammonium
complexes
Zirconium, chloro hydroxy lactate oxo sodium
complexes
Zirconium, hydroxylactate sodium complexes
Zirconium,tetrakis[2-[bis(2-
hydroxyethyl)amino-kN]ethanolato-kO]-
CASRN
21959-01-3
14644-61-2
197980-53-3
68909-34-2
174206-15-6
113184-20-6
101033-44-7
Physico-
chemical
properties
Selected
toxic ity
reference
value
Reference
5
2,6
4
4,8
4
1,4
1, 2, 4, 5
Table A-3. List of generic names of chemicals reportedly used in hydraulic fracturing fluids.
In some cases, the generic chemical name masks a specific chemical name and CASRN provided to the
EPA and claimed as CBI by one or more of the nine hydraulic fracturing service companies.
Generic chemical name
2-Substituted aromatic amine salt
Acetylenic alcohol
Acrylamide acrylate copolymer
Acrylamide copolymer
Acrylamide modified polymer
Acrylamide-sodium acrylate copolymer
Acrylate copolymer
Acrylic copolymer
Acrylic polymer
Acrylic resin
Acyclic hydrocarbon blend
Acylbenzylpyridinium choride
Alcohol alkoxylate
Alcohol and fatty acid blend
Reference
1,4
1
4
1,4
4
4
1
1
1,4
4
1,4
8
1,4
2
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Alcohol ethoxylates
Alcohols
Alcohols, C9-C22
Aldehydes
Alfa-alumina
Aliphatic acids
Aliphatic alcohol
Aliphatic alcohol glycol ether
Aliphatic alcohols, ethoxylated
Aliphatic amine derivative
Aliphatic carboxylic acid
Alkaline bromide salts
Alkaline metal oxide
Alkanes/alkenes
Alkanolamine derivative
Alkanolamine/aldehyde condensate
Alkenes
Alklaryl sulfonic acid
Alkoxylated alcohols
Alkoxylated amines
Alkyaryl sulfonate
Alkyl alkoxylate
Alkyl amide
Alkyl amine
Alkyl amine blend in a metal salt solution
Alkyl aryl amine sulfonate
Alkyl aryl polyethoxy ethanol
Alkyl dimethyl benzyl ammonium chloride
Alkyl esters
Alkyl ether phosphate
Alkyl hexanol
Alkyl ortho phosphate ester
Reference
4
1,4
1,4
1,4,5
1,4
1, 2, 3, 4
2
3,4
2
1
4
1,4
4
4
2
1,2,4
1,4
1,4
1
1,4
1, 2, 3, 4
1,4
4
1,4
1,4
4
3,4
4
1,4
4
1,4
1,4
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Alkyl phosphate ester
Alkyl phosphonate
Alkyl pyridines
Alkyl quaternary ammonium chlorides
Alkyl quaternary ammonium salt
Alkylamine alkylaryl sulfonate
Alkylamine salts
Alkylaryl sulfonate
Alkylated quaternary chloride
Alkylated sodium naphthalenesulphonate
Alkylbenzenesulfonate
Alkylbenzenesulfonic acid
Alkylethoammonium sulfates
Alkylphenol ethoxylates
Alkylpyridinium quaternary
Alphatic alcohol polyglycol ether
Aluminum oxide
Amide
Amidoamine
Amine
Amine compound
Amine oxides
Amine phosphonate
Amine salt
Amino compounds
Amino methylene phosphonic acid salt
Ammonium alcohol ether sulfate
Ammonium salt
Ammonium salt of ethoxylated alcohol sulfate
Amorphous silica
Amphoteric surfactant
Anionic acrylic polymer
Reference
1,4
4
2
1,4
4
4
2
1,4
1,2,4
2
2
1,4,5
1
1,4
4
2
1,4
4
1,4
1,4
4
1,4
1,4
1
1,4
1,4
1,4
1,4
1,4
4
2
2
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Anionic copolymer
Anionic polyacrylamide
Anionic polyacrylamide copolymer
Anionic polymer
Anionic surfactants
Antifoulant
Antimonate salt
Aqueous emulsion of diethylpolysiloxane
Aromatic alcohol glycol ether
Aromatic aldehyde
Aromatic hydrocarbons
Aromatic ketones
Aromatic polyglycol ether
Arsenic compounds
Ashes, residues
Bentone clay
Biocide
Biocide component
Bis-quaternary methacrylamide monomer
Blastfurnace slag
Borate salts
Cadmium compounds
Carbohydrates
Carboxylmethyl hydroxypropyl guar
Cationic polyacrylamide
Cationic polymer
Cedar fiber, processed
Cellulase enzyme
Cellulose derivative
Cellulose ether
Cellulosic polymer
Ceramic
Reference
1,4
1,2,4
1,4,6
1,3,4
2,4,6
1,4
1,4
2
1
1,4
3,4
1, 2, 3, 4
1
4
4
4
4
1,4
4
4
1,2,4
4
1,2,4
4
4
2,4
2
1
1,2,4
2
2
4
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Chlorous ion solution
Chromates
Chrome-free lignosulfonate compound
Citrus rutaceae extract
Common white
Complex alkylaryl polyo-ester
Complex aluminum salt
Complex carbohydrate
Complex organometallic salt
Complex polyamine salt
Complex substituted keto-amine
Complex substituted keto-amine hydrochloride
Copper compounds
Coric oxide
Cotton dust (raw)
Cottonseed hulls
Cured acrylic resin
Cured resin
Cured urethane resin
Cyclic alkanes
Defoamer
Dibasic ester
Dicarboxylic acid
Diesel
Dimethyl silicone
Dispersing agent
Emulsifier
Enzyme
Epoxy
Epoxy resin
Essential oils
Ester Salt
Reference
1
1,4
2
4
4
1
1,4
2
1
7
1
1
6
4
2
2
1,4
1,4,5
1,4
1,4
4
4
1,4
1,4,6
1,4
1
4
4
4
1,4
1,4
2,4
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Generic chemical name
Esters
Ether compound
Ether salt
Ethoxylated alcohol blend
Ethoxylated alcohol/ester mixture
Ethoxylated alcohols
Ethoxylated alkyl amines
Ethoxylated amine blend
Ethoxylated amines
Ethoxylated fatty acid
Ethoxylated fatty acid ester
Ethoxylated nonionic surfactant
Ethoxylated nonylphenol
Ethoxylated sorbitol esters
Ethylene oxide-nonylphenol polymer
Fatty acid amine salt mixture
Fatty acid ester
Fatty acid tall oil
Fatty acid, ethoxylate
Fatty acids
Fatty alcohol alkoxylate
Fatty alkyl amine salt
Fatty amine carboxylates
Fatty imidazoline
Fluoroaliphatic polymeric esters
Formaldehyde polymer
Glass fiber
Glyceride esters
Glycol
Glycol blend
Glycol ethers
Ground cedar
Reference
2,4
4
4
4
4
1, 2, 4, 5, 7
1,4
4
1,4
4
1,4
1,4
1,2,4
1,4
4
4
1,2,4
1,4
4
1
1,4
1,4
1,4
4
1,4
1
1,4
2
4
2
1,4,7
2
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Generic chemical name
Ground paper
Guar derivative
Guar gum
Haloalkyl heteropolycycle salt
Hexanes
High molecular weight polymer
High pH conventional enzymes
Hydrocarbons
Hydrogen solvent
Hydrotreated and hydrocracked base oil
Hydrotreated distillate, light C9-16
Hydrotreated heavy naphthalene
Hydrotreated light distillate
Hydrotreated light petroleum distillate
Hydroxyalkyl imino carboxylic sodium salt
Hydroxycellulose
Hydroxyethyl cellulose
Imidazolium compound
Inner salt of alkyl amines
Inorganic borate
Inorganic chemical
Inorganic particulate
Inorganic salt
Iso-alkanes/n-alkanes
Isomeric aromatic ammonium salt
Latex
Lead compounds
Low toxicity base oils
Lubra-Beads course
Maghemite
Magnetite
Metal salt
Reference
2
1,4
4
1,4
1
2
2
1
4
1,4
4
5
2,4
4
2
6
1,2,4
4
1,4
1,4
4
1,4
2,4
1,4
1,4
2,4
4
1,4
4
1,4
1,4
1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Metal salt solution
Mineral
Mineral fiber
Mineral filler
Mineral oil
Mixed titanium ortho ester complexes
Modified acrylamide copolymer
Modified acrylate polymer
Modified alkane
Modified bentonite
Modified cycloaliphatic amine adduct
Modified lignosulfonate
Naphthalene derivatives
Neutralized alkylated napthalene sulfonate
Nickel chelate catalyst
Nonionic surfactant
N-tallowalkyltrimethylenediamines
Nuisance particulates
Nylon
Olefinic sulfonate
Olefins
Organic acid salt
Organic acids
Organic alkyl amines
Organic chloride
Organic modified bentonite clay
Organic phosphonate
Organic phosphonate salts
Organic phosphonic acid salts
Organic polymer
Organic polyol
Organic salt
Reference
1
1,4
2
1
4
1,4
2,4
4
1,4
4
1,4
2,4
1,4
4
4
1
4
1,2,4
4
1,4
1,4
1,4
1,4
4
4
4
1,4
1,4
1,4
4
4
1,4
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Generic chemical name
Organic sulfur compound
Organic surfactants
Organic titanate
Organo amino silane
Organo phosphonic acid
Organo phosphonic acid salt
Organometallic ammonium complex
Organophilicclay
Oxidized tall oil
Oxoaliphaticacid
Oxyalkylated alcohol
Oxyalkylated alkyl alcohol
Oxyalkylated alkylphenol
Oxyalkylated fatty acid
Oxyalkylated fatty alcohol salt
Oxyalkylated phenol
Oxyalkylated phenolic resin
Oxyalkylated polyamine
Oxyalkylated tallow diamine
Oxyethylated alcohol
Oxylated alcohol
P/F resin
Paraffin inhibitor
Paraffinic naphthenic solvent
Paraffinic solvent
Paraffins
Pecan shell
Petroleum distallate blend
Petroleum gas oils
Petroleum hydrocarbons
Petroleum solvent
Phosphate ester
Reference
1,4
1
1,4
4
4
4
1
4
2
2
1,4
2,4
1, 2, 3, 4
1,4
2
1,4
4
1
2
2
1,4
4
4
1
1,4
1
2
2,3,4
1
4
2
1,4
77]/s document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Generic chemical name
Phosphonate
Phosphonic acid
Phosphoric acid, mixed polyoxyalkylene aryl and alkyl esters
Plasticizer
Polyacrylamide copolymer
Polyacrylamides
Polyacrylate
Polyactide resin
Polyalkylene esters
Polyaminated fatty acid
Polyaminated fatty acid surfactants
Polyamine
Polyamine polymer
Polyanionic cellulose
Polyaromatic hydrocarbons
Polycyclic organic matter
Polyelectrolyte
Polyether polyol
Polyethoxylated alkanol
Polyethylene copolymer
Polyethylene glycols
Polyethylene wax
Polyglycerols
Polyglycol
Polyglycol ether
Polylactide resin
Polymer
Polymeric hydrocarbons
Polymerized alcohol
Polymethacrylate polymer
Polyol phosphate ester
Polyoxyalkylene phosphate
Reference
2
1,4
4
1,2
4
1
1,4
4
4
2
2
1,4
4
1
6
6
4
2
2,3,4
4
4
4
2
2
6
4
2,4
3,4
4
4
2
2
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Polyoxyalkylene sulfate
Polyoxyalkylenes
Polyphenylene ether
Polyphosphate
Polypropylene glycols
Polyquaternary amine
Polysaccaride polymers in suspension
Polysaccharide
Polysaccharide blend
Polyvinylalcohol/polyvinylactetate copolymer
Potassium chloride substitute
Quarternized heterocyclic amines
Quaternary amine
Quaternary amine salt
Quaternary ammonium chloride
Quaternary ammonium compound
Quaternary ammonium salts
Quaternary compound
Quaternary salt
Quaternized alkyl nitrogenated compd
Red dye
Refined mineral oil
Resin
Salt of amine-carbonyl condensate
Salt of fatty acid/polyamine reaction product
Salt of phosphate ester
Salt of phosphono-methylated diamine
Salts
Salts of oxyalkylated fatty amines
Sand
Sand, AZ silica
Sand, brown
Reference
2
1,4,7
4
4
2
4
2
4
4
4
4
4
2,4
4
4
1,2,4
1,2,4
1,4
1,4
4
4
2
4
3,4
3,4
1
1,4
4
4
4
4
4
77]/s document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Generic chemical name
Sand, sacked
Sand, white
Secondary alcohol
Silica sand, 100 mesh, sacked
Silicone emulsion
Silicone ester
Sodium acid pyrophosphate
Sodium calcium magnesium polyphosphate
Sodium phosphate
Sodium salt of aliphatic amine acid
Sodium xylene sulfonate
Softwood dust
Starch blends
Substituted alcohol
Substituted alkene
Substituted alklyamine
Substituted alkyne
Sulfate
Sulfomethylated tannin
Sulfonate
Sulfonate acids
Sulfonate surfactants
Sulfonated asphalt
Sulfonicacid salts
Sulfur compound
Sulphonic amphoterics
Sulphonic amphoterics blend
Surfactant blend
Surfactants
Synthetic copolymer
Synthetic polymer
Tallow soap
Reference
4
4
1,4
4
1
4
4
4
4
2
4
2
6
1,2,4
1
1,4
4
4
2,5
4
1
1
2
1,4
1,4
4
4
3,4
1,2,4
2
4
4
77]/s document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix A
Generic chemical name
Telomer
Terpenes
Titanium complex
Triethanolamine zirconium chelate
Triterpanes
Vanadium compounds
Wall material
Walnut hulls
Zirconium complex
Zirconium salt
Reference
4
1,4
4
14
4
4
1
1,2,4
2,4
4
Table A-4. Chemicals detected in flowback or produced water.
An "X" indicates the availability of physicochemical properties from EPI Suite™ and selected toxicity
reference values (see Appendix G). An empty cell indicates no information was available from the
sources we consulted. Reference number corresponds to the citations in Table A-l. Italicized
chemicals are found in both fracturing fluids and flowback/produced water.
Chemical name
1,2,3-Trichlorobenzene
1,2,4-Trichlorobenzene
1, 2, 4- Trimethylbenzen e
1,2-Propylene glycol
1, 3, 5- Trimethylbenzen e
1,4-Dioxane
2,4-Dimethylphenol
2,6-Dichlorophenol
2-Methylnaphthalene
2-Methylpropanoic acid
2-Methylpyridine
7,12-Dimethylbenz(a)anthracene
Acetic acid
CASRN
87-61-6
120-82-1
95-63-6
57-55-6
108-67-8
123-91-1
105-67-9
87-65-0
91-57-6
79-31-2
109-06-8
57-97-6
64-19-7
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxicity
reference
value
X
X
X
X
X
X
X
Reference
3,9
9
3, 9, 10
3,9
3, 9, 10
9,10
3, 9, 10
3,9
3, 9, 10
10
3,9
3,9
3, 9, 10
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Chemical name
Acetone
Acetophenone
Acrolein
Acrylonitrile
Aldrin
Aluminum
Ammonia
Antimony
Aroclor 1248
Arsenic
Barium
Benzene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Benzyl alcohol
Beryllium
beta-Hexachlorocyclohexane
Bis(2-chloroethyl) ether
Boron
Bromide
Bromodichloromethane
Bromoform
Butanoicacid
Butylbenzene
Cadmium
Caesium-137
Calcium
Carbon dioxide
CASRN
67-64-1
98-86-2
107-02-8
107-13-1
309-00-2
7429-90-5
7664-41-7
7440-36-0
12672-29-6
7440-38-2
7440-39-3
71-43-2
50-32-8
205-99-2
191-24-2
207-08-9
100-51-6
7440-41-7
319-85-7
111-44-4
7440-42-8
24959-67-9
75-27-4
75-25-2
107-92-6
104-51-8
7440-43-9
10045-97-3
7440-70-2
124-38-9
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reference
3, 9, 10
3,9
9
3,9
3,9
3, 9, 10
3, 9, 10
3, 9, 10
3,9
3, 9, 10
3, 9, 10
3, 9, 10
3,9
3,9
3, 9, 10
3,9
3, 9, 10
3, 9, 10
3,9
3,9
3, 9, 10
3, 9, 10
3
3, 9, 10
9,10
9,10
3, 9, 10
3
3, 9, 10
3, 9, 10
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Chemical name
Carbon disulfide
Chloride
Chlorine
Chlorodibromomethane
Chloroform
Chloromethane
Chromium
Chromium (III)
Chromium (VI)
Cobalt
Copper
Cumene
Cyanide
delta-Hexachlorocyclohexane
Di(2-ethylhexyl) phthalate
Dibenz(a,h)anthracene
Dibutyl phthalate
Dichloromethane
Dieldrin
Diethyl phthalate
Dioctyl phthalate
Diphenylamine
Endosulfan 1
Endosulfan II
Endrin aldehyde
E thy 1 benzene
Ethylene glycol
Fluoranthene
Fluorene
Fluoride
CASRN
75-15-0
16887-00-6
7782-50-5
124-48-1
67-66-3
74-87-3
7440-47-3
16065-83-1
18540-29-9
7440-48-4
7440-50-8
98-82-8
57-12-5
319-86-8
117-81-7
53-70-3
84-74-2
75-09-2
60-57-1
84-66-2
117-84-0
122-39-4
959-98-8
33213-65-9
7421-93-4
100-41-4
107-21-1
206-44-0
86-73-7
16984-48-8
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reference
3,9
3, 9, 10
3,10
3
3, 9, 10
3,10
3, 9, 10
3
3,10
3, 9, 10
3, 9, 10
3,9
3, 9, 10
9
3, 9, 10
3,9
3, 9, 10
9,10
9
9
9,10
3,9
3,9
3,9
3,9
3, 9, 10
3,9
3,9
3, 9, 10
3, 9, 10
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Chemical name
Formic acid
Heptachlor
Heptachlor epoxide
Heptanoic acid
Hexanoic acid
lndeno(l,2,3-cd)pyrene
Iron
Isopropanol
Isovaleric acid
Lead
Lindane
Lithium
Magnesium
Manganese
m-Cresol
Mercury
Methanol
Methyl bromide
Methyl ethyl ketone
Molybdenum
Naphthalene
Nickel
Nitrate
Nitrite
N-Nitrosodiphenylamine
o-Cresol
p,p'-DDE
p-Cresol
p-Cymene
Pentanoicacid
CASRN
64-18-6
76-44-8
1024-57-3
111-14-8
142-62-1
193-39-5
7439-89-6
67-63-0
503-74-2
7439-92-1
58-89-9
7439-93-2
7439-95-4
7439-96-5
108-39-4
7439-97-6
67-56-1
74-83-9
78-93-3
7439-98-7
91-20-3
7440-02-0
14797-55-8
14797-65-0
86-30-6
95-48-7
72-55-9
106-44-5
99-87-6
109-52-4
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Reference
10
3,9
3,9
10
10
3,9
3, 9, 10
3,9
10
3, 9, 10
3,9
3, 9, 10
3, 9, 10
3, 9, 10
3, 9, 10
3, 9, 10
3,9
3,9
3, 9, 10
3, 9, 10
3, 9, 10
3, 9, 10
3, 9, 10
3, 9, 10
3,9
3, 9, 10
3,9
3, 9, 10
9,10
10
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Chemical name
Phenanthrene
Phenol
Phorate
Phosphorus
Potassium
Propionic acid
Propylbenzene
Pyrene
Pyridine
Radium
Radium-226
Radium-228
Safrole
sec-Butylbenzene
Selenium
Silica
Silicon
Silver
Sodium
Strontium
Sulfate
Sulfite
Tetrachloroethylene
Thallium
Tin
Titanium
Toluene
Vanadium
CASRN
85-01-8
108-95-2
298-02-2
7723-14-0
7440-09-7
79-09-4
103-65-1
129-00-0
110-86-1
7440-14-4
13982-63-3
15262-20-1
94-59-7
135-98-8
7782-49-2
7631-86-9
7440-21-3
7440-22-4
7440-23-5
7440-24-6
14808-79-8
14265-45-3
127-18-4
7440-28-0
7440-31-5
7440-32-6
108-88-3
7440-62-2
Physico-
chemical
properties
X
X
X
X
X
X
X
X
X
X
X
Selected
toxic ity
reference
value
X
X
X
X
X
X
X
X
X
X
X
X
X
Reference
3, 9, 10
3, 9, 10
9
3,9
3, 9, 10
10
9
9,10
3, 9, 10
3
3,10
3,10
3,9
9
3, 9, 10
10
10
3, 9, 10
3, 9, 10
3, 9, 10
3, 9, 10
3
3,9
3, 9, 10
9,10
3, 9, 10
3, 9, 10
3,10
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix A
Chemical name
Xylenes
Zinc
Zirconium
CASRN
1330-20-7
7440-66-6
7440-67-7
Physico-
chemical
properties
X
Selected
toxic ity
reference
value
X
X
Reference
3, 9, 10
3, 9, 10
3
A.2. References for Appendix A
Colborn. T: Kwiatkowski. C: Schultz. K: Bachran. M. (2011). Natural gas operations from a public health
perspective. Hum Ecol Risk Assess 17:1039-1056. http://dx.doi.org/10.1080/10807039.2011.605662
Hayes. T. (2009). Sampling and analysis of water streams associated with the development of Marcellus shale
gas. Des Plaines, IL: Marcellus Shale Coalition, http://eidmarcellus.org/wp-
content/uploads/2012/ll/MSCommission-Report.pdf
House of Representatives (U.S. House of Representatives). (2011). Chemicals used in hydraulic fracturing.
Washington, D.C.: U.S. House of Representatives, Committee on Energy and Commerce, Minority Staff.
http://democrats.energycommerce.house.gov/sites/default/files/documents/Hydraulic-Fracturing-
Chemicals-2011-4-18.pdf
NLM (National Institutes of Health, National Library of Medicine). (2014). ChemID plus advanced. Available
online at http://chem.sis.nlm.nih.gov/chemidplus/
NYSDEC (New York State Department of Environmental Conservation). (2011). Revised draft 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. Albany, NY: NY SDEC.
http://www.dec.ny.gov/energy/75370.html
OSHA. Title 29 - Department of Labor. Subpart z Toxic and hazardous substances, hazard communication. §
1910.1200 (2013). http://www.gpo.gov/fdsys/pkg/CFR-2013-title29-vol6/xml/CFR-2013-title29-vol6-
secl910-1200.xml
PA PEP (Pennsylvania Department of Environmental Protection). (2010). Chemicals used by hydraulic
fracturing companies in Pennsylvania for surface and hydraulic fracturing activities. Harrisburg, PA:
Pennsylvania Department of Environmental Protection (PADEP).
http://files.dep.state.pa.us/OilGas/BOGM/BOGMPortalFiles/MarcellusShale/Frac%201ist%206-30-
2010.pdf.
Sheets. MSP, (a) Encana/Halliburton Energy Services, Inc.: Duncan, Oklahoma. Provided by Halliburton
Energy Services during an onsite visit by the EPA on May 10, 2010; (b) Encana Oil and Gas (USA), Inc.:
Denver, Colorado. Provided to US EPA Region 8. Material Safety Data Sheets.
U.S. EPA (U.S. Environmental Protection Agency). (2004). Evaluation of impacts to underground sources of
drinking water by hydraulic fracturing of coalbed methane reservoirs. (EPA/816/R-04/003). Washington,
DC.: U.S. Environmental Protection Agency, Office of Solid Waste.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-63 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix A
U.S. EPA (U.S. Environmental Protection Agency). (2011b). Sampling data for flowback and produced water
provided to EPA by nine oil and gas well operators (non-confidential business information). US
Environmental Protection Agency.
http://www.regulations.gov/#!docketDetail:rpp=100:so=DESC:sb=docId:po=0:D=EPA-HQ-ORD-2010-
0674
U.S. EPA (U.S. Environmental Protection Agency). (2013a). Data received from oil and gas exploration and
production companies, including hydraulic fracturing service companies 2011 to 2013. Non-confidential
business information source documents are located in Federal Docket ID: EPA-HQ-ORD2010-0674.
Available at http://www.regulations.gov.
, (U.S. Environmental Protection Agency). (2013b). Distributed structure-searchable toxicity
(DSSTOX) database network. Available online at http://www.epa.gov/ncct/dsstox/index.html
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 A-64 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix B
Appendix B
Water Acquisition Tables
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Appendix B. Water Acquisition Tables
B.I. Supplemental Tables
Table B-l. Annual average hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010 by state.
Hydraulic fracturing water use data from the EPA's project database of disclosures to FracFocus 1.0
Sc)- Annual total water use data from the U.S. Geological Survey (USGS) Water Census
:)- Estimates of consumptions derived from hydraulic fracturing water use and total
water use data. States listed in descending order by the volume of hydraulic fracturing water use.
State
Texas
Pennsylvania
Arkansas
Colorado
Oklahoma
Louisiana
North Dakota
West Virginia
Wyoming
New Mexico
Ohio
Utah
Montana
Kansas
California
Michigan
Total annual water
use in 2010
(millions of gal)a'b
9,052,000
2,967,450
4,124,500
4,015,000
1,157,050
3,117,100
419,750
1,288,450
1,715,500
1,153,400
3,445,600
1,627,900
2,792,250
1,460,000
13,870,000
3,942,000
Annual average
hydraulic fracturing
water use in 2011
and 2012
(millions of gal)c
19,942
5,105
3,676
3,277
2,949
2,462
2,181
657
538
371
273
251
155
66
44
28
Hydraulic fracturing
water use compared
to total water use
(%)d
0.2
0.2
0.1
0.1
0.3
0.1
0.5
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Hydraulic fracturing
water consumption
com pa red to total
water consumption
(%)d'e
0.7
1.4
0.1
0.1
0.8
0.4
2.9
0.5
<0.1
<0.1
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Mississippi
Alaska'
Virginia
Alabama
TOTAL for all 20 states
Total annual water
use in 2010
(millions of gal)a'b
1,434,450
397,850
2,792,250
3,635,400
64,407,900
Annual average
hydraulic fracturing
water use in 2011
and 2012
(millions of gal)c
18
7
1
1
42,001
Hydraulic fracturing
water use compared
to total water use
(%)d
<0.1
<0.1
<0.1
<0.1
0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)d'e
<0.1
<0.1
<0.1
<0.1
0.2
a Texas, Colorado, Pennsylvania, North Dakota, Oklahoma, and Utah all made some degree of reporting to FracFocus
mandatory rather than voluntary during this time period analyzed, January 1, 2011, to February 28, 2013. Three other states
started requiring disclosure to either FracFocus or the state (Louisiana, Montana, and Ohio), and five states required or began
requiring disclosure to the state (Arkansas, Michigan, New Mexico, West Virginia, and Wyoming). Alabama, Alaska, California,
Kansas, Mississippi, and Virginia did not have reporting requirements during the period of time studied (U.S. EPA, 2015a).
b State-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on January 27, 2015. Total
water withdrawals per day (located in downloaded Table 1) were multiplied by 365 days to estimate total water use for the
year (Maupin et al., 2014).
c Average of water used for hydraulic fracturing in 2011 and 2012 as reported to FracFocus (U.S. EPA, 2015c).
d Percentages were calculated by averaging annual water use for hydraulic fracturing reported in FracFocus in 2011 and 2012
for a given state (U.S. EPA, 2015c), and then dividing by 2010 USGS hydraulic fracturing water use (Maupin et al., 2014) and
multiplying by 100. Note that the annual hydraulic fracturing water use reported in FracFocus (the numerator) was not added
to the 2010 total USGS water use value in the denominator, and the percentage is simply calculated as by dividing annual
hydraulic fracturing use by 2010 total water use or consumption. This was done because of the difference in years between
the two datasets, and because the USGS 2010 Census (Maupin et al., 2014) already included an estimate of hydraulic
fracturing water use in its mining category. This approach is also consistent with that of other literature on this topic; see
Nicot and Scanlon (2012).
e Consumption values were calculated with use-specific consumption rates predominantly from the USGS, including 19.2% for
public supply, 19.2% for domestic use, 60.7% for irrigation, 60.7% for livestock, 14.8% for industrial uses, 14.8% for mining
(Sollevetal.. 1998). and 2.7% for thermoelectric power (USGS. 2014). We used a rate of 71.6% for aquaculture (from
Verdegem and Bosma. 2009) (evaporation per kg fish + infiltration per kg)/(total water use per kg) *100. These rates were
multiplied by each USGS water use value (Maupin et al., 2014) to yield a total water consumption estimate. To calculate a
consumption amount for hydraulic fracturing, we used a consumption rate of 82.5%. This was calculated by taking the median
value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this assessment and then
subtracting from 100%. If a range of values was given, the midpoint was used. Note that this is likely a low estimate of
consumption since much of this return water is not subsequently treated and reused, but rather disposed of in underground
injection wells—see Chapter 8.
f All reported hydraulic fracturing disclosures for Alaska passed state locational quality assurance methods, but not county
methods (U.S. EPA, 2015c). Thus, only state-level cumulative values were reported here, and no county-level data are
provided in subsequent tables.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Table B-2. Annual average hydraulic fracturing water use and consumption in 2011 and 2012
compared to total annual water use and consumption in 2010 by county.
Counties listed contained wells used for hydraulic fracturing according to the EPA's project database of
disclosures to FracFocus 1.0 (UiSi_EPAt2015c). Annual total water use data from the USGS Water
Census (Mau|)in_et_ajil_2014). Estimates of consumption derived from hydraulic fracturing water use
and total water use data.
State
Alabama
Arkansas
California
Colorado
Cou nty
Jefferson
Tuscaloosa
Cleburne
Conway
Faulkner
Independence
Logan
Sebastian
Van Buren
White
Yell
Colusa
Glenn
Kern
Los Angeles
Sutter
Ventura
Adams
Arapahoe
Boulder
Total annual
water use in 2010
(millions of gal)a
29,685.5
14,319.0
9,471.8
10,643.4
3,204.7
57,195.5
1,525.7
1,365.1
1,587.8
32,131.0
1,507.5
304,782.3
221,420.0
788,359.9
1,118,363.7
263,511.8
262,610.2
84,285.8
68,255.0
84,537.7
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
0.6
0.5
740.9
798.1
284.0
80.3
2.4
0.6
899.6
869.8
<0.1
<0.1
<0.1
41.7
0.2
0.2
1.8
3.2
4.0
4.1
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
<0.1
7.8
7.5
8.9
0.1
0.2
<0.1
56.7
2.7
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
<0.1
32.9
21.2
13.7
0.3
0.3
<0.1
168.8
4.7
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Colorado,
cont.
Kansas
Cou nty
Broomfield
Delta
Dolores
El Paso
Elbert
Fremont
Garfield
Jackson
La Plata
Larimer
Las Animas
Mesa
Moffat
Morgan
Phillips
Rio Blanco
Routt
San Miguel
Weld
Yuma
Barber
Clark
Comanche
Finney
Grant
Total annual
water use in 2010
(millions of gal)a
2,336.0
131,221.2
2,040.4
42,380.2
5,040.7
53,366.7
95,436.6
126,968.9
122,873.6
150,690.3
26,911.5
275,476.5
62,093.8
67,901.0
21,509.5
97,513.4
74,460.0
13,848.1
168,677.5
80,595.7
2,164.5
1,898.0
3,011.3
102,685.5
47,128.8
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
4.5
0.5
0.1
<0.1
<0.1
0.6
1,804.2
1.0
3.5
5.4
7.9
122.1
14.5
3.9
0.2
147.3
0.1
0.3
1,149.4
0.4
9.9
0.8
25.6
2.4
0.2
Hydraulic
fracturing water
use compared to
total water use
(%)C
0.2
<0.1
<0.1
<0.1
<0.1
<0.1
1.9
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.2
<0.1
<0.1
0.7
<0.1
0.5
<0.1
0.9
<0.1
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.4
<0.1
<0.1
<0.1
<0.1
<0.1
2.7
<0.1
<0.1
<0.1
<0.1
0.1
<0.1
<0.1
<0.1
0.2
<0.1
<0.1
1.0
<0.1
0.7
0.1
1.2
<0.1
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Kansas, cont.
Louisiana
Cou nty
Gray
Harper
Haskell
Hodgeman
Kearny
Lane
Meade
Morton
Ness
Seward
Sheridan
Stanton
Stevens
Sumner
Allen
Beau regard
Bienville
Bossier
Caddo
Calcasieu
Caldwell
Claiborne
De Soto
East Feliciana
Jackson
Total annual
water use in 2010
(millions of gal)a
69,379.2
1,357.8
72,496.3
8,460.7
64,134.2
5,628.3
55,958.2
17,403.2
1,478.3
57,443.7
26,393.2
41,420.2
72,124.0
3,442.0
8,942.5
10,161.6
4,810.7
5,599.1
53,644.1
81,621.3
1,398.0
952.7
13,373.6
1,350.5
1,456.4
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
3.3
17.3
0.1
2.7
<0.1
0.8
<0.1
<0.1
1.6
<0.1
0.7
<0.1
0.1
0.2
0.1
2.3
108.9
110.1
153.6
0.1
<0.1
3.8
1,085.9
3.7
<0.1
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
1.3
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
2.3
2.0
0.3
<0.1
<0.1
0.4
8.1
0.3
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
2.0
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.2
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.1
10.0
4.9
1.7
<0.1
<0.1
1.1
47.4
0.7
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Louisiana,
cont.
Michigan
Mississippi
Montana
Cou nty
Lincoln
Natchitoches
Rapides
Red River
Sabine
Tangipahoa
Union
Webster
West Feliciana
Winn
Cheboygan
Gladwin
Kalkaska
Missaukee
Ogemaw
Roscommon
Amite
Wilkinson
Daniels
Garfield
Glacier
Musselshell
Richland
Total annual
water use in 2010
(millions of gal)a
3,000.3
12,530.5
199,976.2
1,606.0
1,522.1
7,329.2
1,481.9
2,664.5
15,191.3
846.8
2,777.7
850.5
1,233.7
1,423.5
1,179.0
1,000.1
792.1
1,270.2
1,408.9
1,631.6
46,760.2
26,827.5
94,797.8
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
3.3
12.7
1.7
569.6
395.2
1.9
4.9
1.2
2.3
1.1
<0.1
1.1
24.0
<0.1
<0.1
2.4
14.4
3.2
0.6
0.5
5.1
0.4
83.5
Hydraulic
fracturing water
use compared to
total water use
(%)C
0.1
0.1
<0.1
35.5
26.0
<0.1
0.3
<0.1
<0.1
0.1
<0.1
0.1
1.9
<0.1
<0.1
0.2
1.8
0.3
<0.1
<0.1
<0.1
<0.1
0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.3
0.2
<0.1
83.2
76.6
0.1
1.0
0.1
0.1
0.4
<0.1
0.4
3.7
<0.1
<0.1
0.9
3.8
0.4
0.1
<0.1
<0.1
<0.1
0.1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Montana,
cont.
New Mexico
North Dakota
Cou nty
Roosevelt
Rosebud
Sheridan
Chaves
Colfax
Eddy
Harding
Lea
Rio Arriba
Roosevelt
San Juan
Sandoval
Billings
Bottineau
Burke
Divide
Dunn
Golden Valley
Mckenzie
Mclean
Mountrail
Stark
Williams
Total annual
water use in 2010
(millions of gal)a
31,539.7
71,412.3
7,354.8
88,078.2
17,450.7
70,612.9
1,168.0
64,057.5
39,080.6
63,367.7
125,432.3
23,922.1
762.9
1,164.4
394.2
806.7
1,076.8
208.1
13,753.2
7,873.1
1,248.3
1,168.0
7,705.2
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
52.1
3.5
9.7
2.8
0.7
225.6
0.1
113.7
16.5
<0.1
11.6
0.4
44.4
0.1
63.6
102.2
309.5
4.6
588.4
12.2
449.4
48.0
558.5
Hydraulic
fracturing water
use compared to
total water use
(%)C
0.2
<0.1
0.1
<0.1
<0.1
0.3
<0.1
0.2
<0.1
<0.1
<0.1
<0.1
5.8
<0.1
16.1
12.7
28.7
2.2
4.3
0.2
36.0
4.1
7.2
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.2
<0.1
0.2
<0.1
<0.1
0.5
<0.1
0.3
0.1
<0.1
<0.1
<0.1
16.2
<0.1
40.8
18.6
43.1
3.8
6.2
0.4
98.3
8.5
11.3
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Ohio
Oklahoma
Cou nty
Ashland
Belmont
Carroll
Columbiana
Coshocton
Guernsey
Harrison
Jefferson
Knox
Medina
Muskingum
Noble
Portage
Stark
Tuscarawas
Wayne
Alfalfa
Beaver
Beckham
Blaine
Bryan
Caddo
Canadian
Carter
Coal
Total annual
water use in 2010
(millions of gal)a
2,033.1
65,528.5
1,127.9
3,763.2
53,775.5
2,379.8
481.8
632,917.3
3,270.4
3,540.5
6,018.9
478.2
18,414.3
16,479.8
14,165.7
6,051.7
2,996.7
15,341.0
4,099.0
3,763.2
5,062.6
24,064.5
5,584.5
159,906.5
1,193.6
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
1.5
1.9
152.7
30.7
5.4
8.4
16.5
26.2
1.1
1.3
5.1
8.3
3.2
2.4
6.7
1.7
182.7
23.1
108.0
203.3
10.3
25.4
441.9
161.9
85.9
Hydraulic
fracturing water
use compared to
total water use
(%)C
0.1
<0.1
13.5
0.8
<0.1
0.4
3.4
<0.1
<0.1
<0.1
0.1
1.7
<0.1
<0.1
<0.1
<0.1
6.1
0.2
2.6
5.4
0.2
0.1
7.9
0.1
7.2
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.2
0.1
37.3
2.2
0.1
0.7
7.3
0.1
0.1
0.1
0.3
3.4
0.1
<0.1
0.2
0.1
12.0
0.3
4.7
9.3
0.4
0.3
15.6
0.5
21.5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-8 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Oklahoma,
cont.
Cou nty
Custer
Dewey
Ellis
Garvin
Grady
Grant
Harper
Hughes
Jefferson
Johnston
Kay
Kingfisher
Kiowa
Latimer
Le Flore
Logan
Love
Major
Marshall
McClain
Noble
Oklahoma
Osage
Pawnee
Payne
Total annual
water use in 2010
(millions of gal)a
3,281.4
10,953.7
8,486.3
16,279.0
13,537.9
5,569.9
3,266.8
3,394.5
4,496.8
1,671.7
16,957.9
3,744.9
5,022.4
1,062.2
8,635.9
4,077.1
2,011.2
6,321.8
2,613.4
2,952.9
12,990.4
47,836.9
6,971.5
4,839.9
4,332.6
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
19.0
162.6
184.3
15.0
111.5
77.8
8.8
30.5
<0.1
32.9
17.3
10.2
0.1
0.6
0.3
4.2
4.4
1.2
98.4
2.1
25.3
1.2
3.8
15.7
9.9
Hydraulic
fracturing water
use compared to
total water use
(%)C
0.6
1.5
2.2
0.1
0.8
1.4
0.3
0.9
<0.1
2.0
0.1
0.3
<0.1
0.1
<0.1
0.1
0.2
<0.1
3.8
0.1
0.2
<0.1
0.1
0.3
0.2
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
1.2
6.2
3.2
0.4
2.3
5.2
0.4
2.2
<0.1
4.7
0.4
0.5
<0.1
0.1
<0.1
0.3
0.5
<0.1
7.2
0.2
1.8
<0.1
0.2
1.4
0.6
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-9 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Oklahoma,
cont.
Pennsylvania
Cou nty
Pittsburg
Roger Mills
Seminole
Stephens
Texas
Washita
Woods
Allegheny
Armstrong
Beaver
Blair
Bradford
Butler
Cameron
Centre
Clarion
Clearfield
Clinton
Columbia
Crawford
Elk
Fayette
Forest
Greene
Huntingdon
Total annual
water use in 2010
(millions of gal)a
6,314.5
2,847.0
124,837.3
49,990.4
110,208.1
3,310.6
4,139.1
234,140.2
65,853.3
157,793.2
8,303.8
4,354.5
5,730.5
292.0
16,560.1
1,843.3
111,051.3
6,161.2
3,810.6
5,091.8
7,876.7
16,465.2
744.6
13,023.2
5,121.0
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
349.0
235.5
0.1
27.7
0.1
102.1
155.1
13.6
55.7
30.5
5.9
1,059.4
121.8
6.6
38.5
8.1
111.5
94.4
5.6
2.4
37.5
120.2
7.7
359.0
2.7
Hydraulic
fracturing water
use compared to
total water use
(%)C
5.5
8.3
<0.1
0.1
<0.1
3.1
3.7
<0.1
0.1
<0.1
0.1
24.3
2.1
2.3
0.2
0.4
0.1
1.5
0.1
<0.1
0.5
0.7
1.0
2.8
0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
16.0
12.6
<0.1
0.3
<0.1
5.4
10.9
<0.1
1.8
0.2
0.2
78.2
6.0
4.1
0.5
1.4
2.3
3.0
0.4
0.1
1.9
2.7
1.6
24.7
0.2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-10 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Pennsylvania,
cont.
Texas
Cou nty
Indiana
Jefferson
Lawrence
Lycoming
McKean
Potter
Somerset
Sullivan
Susquehanna
Tioga
Venango
Warren
Washington
Westmoreland
Wyoming
Andrews
Angelina
Archer
Atascosa
Austin
Bee
Borden
Bosque
Brazos
Brooks
Total annual
water use in 2010
(millions of gal)a
21,819.7
1,730.1
36,598.6
5,854.6
4,723.1
2,281.3
10,833.2
222.7
1,617.0
2,909.1
2,989.4
5,099.1
130,535.0
14,607.3
4,788.8
23,363.7
5,540.7
2,536.8
15,038.0
2,555.0
3,087.9
2,427.3
3,544.2
24,790.8
1,204.5
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
16.2
13.8
27.0
704.6
60.5
16.5
5.8
66.5
751.3
566.3
2.4
2.3
433.7
207.0
150.0
236.2
0.8
0.1
327.3
2.1
20.0
8.0
0.7
7.7
1.5
Hydraulic
fracturing water
use compared to
total water use
(%)C
0.1
0.8
0.1
12.0
1.3
0.7
0.1
29.9
46.5
19.5
0.1
<0.1
0.3
1.4
3.1
1.0
<0.1
<0.1
2.2
0.1
0.6
0.3
<0.1
<0.1
0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.7
1.7
1.0
33.8
4.9
1.0
0.2
79.8
123.4
47.3
0.3
0.2
4.6
3.8
15.2
2.7
<0.1
<0.1
4.0
0.1
1.1
1.0
<0.1
0.1
0.3
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-ll DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Burleson
Cherokee
Clay
Cochran
Coke
Colorado
Concho
Cooke
Cottle
Crane
Crockett
Crosby
Culberson
Dallas
Dawson
DeWitt
Denton
Dimmit
Ector
Edwards
Ellis
Erath
Fayette
Fisher
Franklin
Total annual
water use in 2010
(millions of gal)a
10,694.5
24,845.6
1,963.7
24,035.3
12,713.0
52,465.1
2,832.4
4,533.3
733.7
8,566.6
4,281.5
27,261.9
14,311.7
112,204.7
28,842.3
2,394.4
60,684.9
4,073.4
21,958.4
332.2
8,530.1
5,876.5
9,008.2
2,854.3
1,956.4
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
3.0
0.5
<0.1
3.0
0.3
0.1
<0.1
454.3
0.3
92.3
279.0
1.3
37.7
5.6
17.5
546.6
455.0
1,794.2
226.5
<0.1
4.2
0.8
13.7
1.8
<0.1
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
10.0
<0.1
1.1
6.5
<0.1
0.3
<0.1
0.1
22.8
0.7
44.0
1.0
<0.1
<0.1
<0.1
0.2
0.1
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
29.9
0.1
5.7
29.5
<0.1
0.4
<0.1
0.1
48.6
2.3
81.3
4.6
<0.1
0.1
<0.1
1.2
0.1
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-12 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Freestone
Frio
Gaines
Garza
Glasscock
Goliad
Gonzales
Grayson
Gregg
Grimes
Hansford
Hardeman
Hardin
Harrison
Hartley
Haskell
Hemphill
Hidalgo
Hockley
Hood
Houston
Howard
Hutchinson
Irion
Jack
Total annual
water use in 2010
(millions of gal)a
297,861.9
20,589.7
121,778.6
5,234.1
20,680.9
142,963.2
7,121.2
8,143.2
33,010.6
112,500.3
43,643.1
2,230.2
2,376.2
11,869.8
113,555.2
12,143.6
3,150.0
171,630.3
46,314.9
9,351.3
3,686.5
10,811.3
34,437.8
1,335.9
2,241.1
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
53.9
127.5
21.6
0.6
598.1
<0.1
577.9
9.3
9.4
15.5
2.9
0.4
0.1
141.6
1.9
0.1
263.9
8.0
3.0
76.0
8.6
97.6
0.3
411.4
14.0
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
0.6
<0.1
<0.1
2.9
<0.1
8.1
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
1.2
<0.1
<0.1
8.4
<0.1
<0.1
0.8
0.2
0.9
<0.1
30.8
0.6
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.5
0.9
<0.1
<0.1
4.2
<0.1
17.6
0.3
0.2
0.3
<0.1
<0.1
<0.1
6.0
<0.1
<0.1
16.3
<0.1
<0.1
2.2
0.6
2.7
<0.1
74.5
2.2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-13 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Jefferson
Jim Hogg
Johnson
Jones
Karnes
Kenedy
Kent
King
Kleberg
Knox
La Salle
Lavaca
Lee
Leon
Liberty
Limestone
Lipscomb
Live Oak
Loving
Lynn
Madison
Marion
Martin
Maverick
McMullen
Total annual
water use in 2010
(millions of gal)a
88,585.5
306.6
9,241.8
5,679.4
1,861.5
456.3
6,132.0
1,485.6
1,171.7
9,800.3
2,474.7
3,763.2
3,120.8
2,171.8
20,662.7
11,158.1
11,015.7
1,916.3
781.1
19,892.5
1,554.9
3,606.2
14,063.5
20,498.4
657.0
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
<0.1
0.1
582.0
<0.1
1,055.2
0.2
0.4
<0.1
3.4
<0.1
1,288.7
45.0
1.2
56.2
<0.1
10.7
89.0
294.0
138.4
1.1
45.3
5.9
432.0
52.4
745.9
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
<0.1
6.3
<0.1
56.7
0.1
<0.1
<0.1
0.3
<0.1
52.1
1.2
<0.1
2.6
<0.1
0.1
0.8
15.3
17.7
<0.1
2.9
0.2
3.1
0.3
113.5
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
0.1
18.5
<0.1
120.1
0.1
<0.1
<0.1
0.5
<0.1
93.7
2.0
0.1
6.6
<0.1
0.9
1.1
40.1
94.1
<0.1
8.2
0.9
4.7
0.4
350.4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-14 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Medina
Menard
Midland
Milam
Mitchell
Montague
Montgomery
Moore
Nacogdoches
Navarro
Newton
Nolan
Nueces
Ochiltree
Oldham
Orange
Palo Pinto
Panola
Parker
Pecos
Polk
Potter
Reagan
Reeves
Roberts
Total annual
water use in 2010
(millions of gal)a
19,228.2
1,014.7
12,891.8
16,665.9
6,559.1
3,989.5
32,565.3
57,075.1
5,891.1
18,699.0
2,263.0
4,124.5
85,767.7
21,348.9
2,124.3
150,128.2
18,403.3
6,365.6
8,241.7
52,954.2
204,009.5
2,029.4
9,333.1
20,772.2
7,690.6
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
0.2
<0.1
307.4
4.9
11.0
925.3
0.2
<0.1
271.7
4.8
0.2
4.5
1.0
33.3
1.3
0.3
9.6
346.5
261.7
8.2
0.2
0.4
410.5
164.2
38.2
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
<0.1
2.4
<0.1
0.2
23.2
<0.1
<0.1
4.6
<0.1
<0.1
0.1
<0.1
0.2
0.1
<0.1
0.1
5.4
3.2
<0.1
<0.1
<0.1
4.4
0.8
0.5
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
<0.1
3.7
0.1
0.3
77.8
<0.1
<0.1
12.5
0.1
<0.1
0.2
<0.1
0.2
0.1
<0.1
0.3
20.7
9.8
<0.1
<0.1
<0.1
7.8
1.1
1.2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-15 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Robertson
Runnels
Rusk
Sabine
San Augustine
San Patricio
Schleicher
Scurry
Shelby
Sherman
Smith
Somervell
Starr
Stephens
Sterling
Stonewall
Sutton
Tarrant
Terrell
Terry
Tyler
Upshur
Upton
Van Zandt
Walker
Total annual
water use in 2010
(millions of gal)a
158,344.3
2,847.0
582,134.9
799.4
1,131.5
4,172.0
967.3
14,187.6
4,920.2
78,073.5
11,231.1
746,005.3
9,552.1
13,446.6
719.1
923.5
1,153.4
104,430.2
543.9
48,362.5
1,872.5
8,610.4
7,975.3
4,139.1
4,478.6
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
45.4
<0.1
65.8
31.1
182.1
1.1
27.0
1.1
133.6
<0.1
0.2
4.8
5.0
2.6
36.6
0.9
1.6
1,443.0
0.1
7.5
0.1
0.2
462.6
0.1
3.4
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
<0.1
<0.1
3.9
16.1
<0.1
2.8
<0.1
2.7
<0.1
<0.1
<0.1
0.1
<0.1
5.1
0.1
0.1
1.4
<0.1
<0.1
<0.1
<0.1
5.8
<0.1
0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
0.2
<0.1
0.3
13.9
50.8
<0.1
5.0
<0.1
8.2
<0.1
<0.1
<0.1
0.1
0.1
11.9
0.3
0.3
3.9
<0.1
<0.1
<0.1
<0.1
14.2
<0.1
0.2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-16 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Utah
Virginia
Cou nty
Waller
Ward
Washington
Webb
Wharton
Wheeler
Wichita
Wilbarger
Willacy
Wilson
Winkler
Wise
Wood
Yoakum
Young
Zapata
Zavala
Carbon
Duchesne
San Juan
Sevier
Uintah
Buchanan
Dickenson
Wise
Total annual
water use in 2010
(millions of gal)a
9,829.5
6,909.5
2,430.9
15,862.9
81,606.7
6,522.6
25,936.9
12,683.8
15,209.6
7,843.9
5,274.3
24,966.0
19,334.1
77,325.3
21,162.7
2,697.4
14,410.2
15,067.2
119,811.3
10,632.5
52,512.6
100,229.0
313.9
1,741.1
1,927.2
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
0.1
107.3
2.2
1,117.8
<0.1
858.0
0.1
0.2
0.1
84.5
7.7
529.7
0.2
7.5
0.1
1.1
130.0
7.3
85.5
0.3
<0.1
157.5
0.6
0.8
0.1
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
1.6
0.1
7.0
<0.1
13.2
<0.1
<0.1
<0.1
1.1
0.1
2.1
<0.1
<0.1
<0.1
<0.1
0.9
<0.1
0.1
<0.1
<0.1
0.2
0.2
<0.1
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
4.6
0.2
18.2
<0.1
21.5
<0.1
<0.1
<0.1
1.7
0.5
8.9
<0.1
<0.1
<0.1
0.1
1.3
0.1
0.1
<0.1
<0.1
0.2
0.3
0.2
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-17 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
West Virginia
Wyoming
Cou nty
Barbour
Brooke
Doddridge
Hancock
Harrison
Lewis
Marion
Marshall
Monongalia
Ohio
Pleasants
Preston
Ritchie
Taylor
Tyler
Upshur
Webster
Wetzel
Big Horn
Campbell
Carbon
Converse
Fremont
Goshen
Hot Springs
Total annual
water use in 2010
(millions of gal)a
773.8
4,551.6
405.2
28,718.2
20,232.0
901.6
5,982.4
158,358.9
42,102.8
3,825.2
24,703.2
2,890.8
587.7
824.9
4,934.8
1,814.1
1,292.1
1,467.3
143,368.4
44,318.3
137,130.5
56,972.9
186,150.0
144,248.0
28,572.2
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
19.9
54.8
78.5
1.2
40.2
2.4
70.1
84.5
6.8
116.5
<0.1
8.4
2.8
52.9
2.1
34.9
2.3
78.2
2.9
11.7
4.5
106.8
28.2
5.8
0.3
Hydraulic
fracturing water
use compared to
total water use
(%)C
2.6
1.2
19.4
<0.1
0.2
0.3
1.2
0.1
<0.1
3.0
<0.1
0.3
0.5
6.4
<0.1
1.9
0.2
5.3
<0.1
<0.1
<0.1
0.2
<0.1
<0.1
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
6.9
5.1
69.4
<0.1
1.9
0.8
4.9
0.7
0.1
10.4
<0.1
1.4
1.7
17.6
0.2
6.8
0.3
11.9
<0.1
0.1
<0.1
0.3
<0.1
<0.1
<0.1
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Wyoming,
cont.
Cou nty
Johnson
Laramie
Lincoln
Natrona
Niobrara
Park
Sublette
Sweetwater
Uinta
Washakie
Total annual
water use in 2010
(millions of gal)a
43,205.1
86,297.0
74,562.2
62,885.9
25,148.5
111,317.7
61,006.1
61,699.6
79,518.9
60,400.2
Annual average
hydraulic
fracturing water
use in 2011 and
2012 (millions of
gal)b
<0.1
18.3
0.8
1.8
0.1
0.9
314.8
39.4
0.6
1.1
Hydraulic
fracturing water
use compared to
total water use
(%)C
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.5
0.1
<0.1
<0.1
Hydraulic fracturing
water consumption
compared to total
water consumption
(%)c'd
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.7
0.1
<0.1
<0.1
a County-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on November 11, 2014. Total
daily water withdrawals were multiplied by 365 days to estimate total water use for the year (Maupin et al., 2014).
b Average of water used for hydraulic fracturing in 2011 and 2012, as reported to FracFocus (U.S. EPA, 2015c).
c Percentages were calculated by averaging annual water use for hydraulic fracturing reported in FracFocus in 2011 and 2012
for a given county (U.S. EPA. 2015c). and then dividing by 2010 USGS total water use for that county (Maupin etal.. 2014) and
multiplying by 100.
d Consumption values were calculated with use-specific consumption rates predominantly from the USGS, including 19.2% for
public supply, 19.2% for domestic use, 60.7% for irrigation, 60.7% for livestock, 14.8% for industrial uses, 14.8% for mining
(Sollevet al.. 1998). and 2.7% for thermoelectric power (USGS. 2014). We used a rate of 71.6% for aquaculture (from
Verdegem and Bosma, 2009) (evaporation per kg fish + infiltration per kg)/(total water use per kg)*100. These rates were
multiplied by each USGS water use value (Maupin etal., 2014) to yield a total water consumption estimate. To calculate a
consumption amount for hydraulic fracturing, we used a consumption rate of 82.5%. This was calculated by taking the median
value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this assessment and then
subtracting from 100%. If a range of values was given, the midpoint was used. Note that this is likely a low estimate of
consumption since much of this return water is not subsequently treated and reused, but rather disposed of in underground
injection wells—see Chapter 8.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Table B-3. Comparison of water use per well estimates from the EPA's project database of
disclosures to FracFocus 1.0 (U.S. EPA, 2015c) and literature sources.
Source: (U.S. EPA, 2015c)
State
Colorado
North Dakota
Oklahoma
Pennsylvaniad
Texas
Texas
Texas
Average6
Median6
Basin3
Denver
Fort Worth
Salt
Western Gulf
Water use per well (gal) -
FracFocus estimate13
403,686
2,140,842
2,591,778
4,301,701
3,881,220
3,139,980
3,777,648
Water use per well (gal) -
Literature estimateb'c
2,900,000
2,200,000
3,000,000
4,450,000
4,500,000
4,000,000
4,600,000
FracFocus estimate as
a percentage of
literature estimate (%)
14
97
86
97
86
78
82
77
86
a In cases where a basin is not specified, estimates were for the entire state and not specific to a particular basin. Basin
boundaries for the FracFocus estimates were determined from data from the U.S. EIA (see U.S. EPA, 2015b).
bThe type of literature estimate determined the specific comparison with FracFocus. If averages were given in the literature
(as for North Dakota and Pennsylvania), those values were compared with FracFocus averages; where medians were given in
the literature (as for Colorado, Oklahoma, and Texas), they were compared with FracFocus medians.
c Literature estimates were from the following sources: Colorado (Goodwin et al.. 2014). North Dakota (North Dakota State
Water Commission. 2014). Pennsylvania (Mitchell et al.. 2013). and Texas (Nicot et al.. 2012)—see far right-column and
footnotes in Table B-5 for details on literature estimates. Where the literature provided a range, the mid-point was used. Only
literature estimates that were not directly derived from FracFocus were included.
d The results from Mitchell et al. (2013) were used for Pennsylvania since they were derived from Pennsylvania Department of
Environment Protection records. Estimates from Hansen et al. (2013) were not included here because they were based on
FracFocus.
e Average and median percentage calculations were not weighted by the number of wells for a given estimate.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Table B-4. Comparison of well counts from the EPA's project database of disclosures to FracFocus 1.0 (U.S. EPA, 2015c) and state
databases for North Dakota, Pennsylvania, and West Virginia.
State
North Dakota"
Pennsylvania0
WestVirginiad
Average
FracFocus well counts3
2011
613
1,137
93
2012
1,458
1,257
176
Total
2,071
2,394
269
State database well counts
2011
1,225
1,963
214
2012
1,740
1,347
251
Total
2,965
3,310
465
FracFocus counts as a percentage
of state database counts
2011
50%
58%
43%
50%
2012
84%
93%
70%
82%
Total
70%
72%
58%
67%
a FracFocus disclosures from U.S. EPA (2015c).
b For North Dakota state well counts, we used a North Dakota Department of Mineral Resources online database containing a list of horizontal wells completed in the Bakken
Formation. Data for North Dakota were accessed on July 9, 2014 at https://www.dmr.nd.gov/oilgas/bakkenwells.asp.
c For Pennsylvania state well counts, we used completed horizontal wells as a proxy for hydraulically fractured wells in the state. The Pennsylvania Department of
Environmental Protection has online databases of permitted and spudded wells, which differentiate between conventional and unconventional wells and can generate
summary statistics at both the county and state scale. The number of spudded wells (i.e., wells drilled) provided a better comparison with the number of hydraulically
fractured wells in FracFocus than that of permitted wells. The number of permitted wells was nearly double that of spudded in 2011 and 2012, indicating that almost half of
the wells permitted were not drilled in that same year. Therefore, we used spudded wells here. Data for Pennsylvania were accessed on February 11, 2014 from
http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx7/Oil Gas/Spud External Data.
d For West Virginia state well counts, data on the number of hydraulically fractured wells per year were received from the West Virginia Department of Environmental
Protection on February 25, 2014.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Table B-5. Water use per hydraulically fractured well as reported in the EPA's project database of disclosures to FracFocus 1.0
(U.S. EPA, 2015c) by state and basin.
Souce:
Other literature estimates are also included where available. NA indicates other literature estimates were not available. All FracFocus estimates
were limited to disclosures with valid state, county, and volume information. States listed in order addressed in Chapter 4.
State
Texas
Colorado
Basin/total3
Permian
Western Gulf
Fort Worth
TX-LA-MS Salt
Anadarko
Other
Total
Denver
Uinta-Piceance
Raton
Other
Total
Number of
disclosures
8,419
4,549
2,564
626
604
120
16,882
3,166
1,520
146
66
4,898
Mean
(gal)
1,068,511
3,915,540
3,880,724
4,261,363
4,128,702
1,601,897
2,494,452
753,887
2,739,523
108,003
605,740
1,348,842
Median
(gal)
841,134
3,777,648
3,881,220
3,139,980
3,341,310
184,239
1,420,613
403,686
1,798,414
95,974
183,408
463,462
10th percentile
(gal)
40,090
173,832
923,381
193,768
492,421
21,470
58,709
143,715
840,778
24,917
34,412
147,353
90th percentile
(gal)
1,814,633
6,786,052
6,649,406
10,010,707
8,292,996
5,678,588
6,115,195
2,588,946
5,066,380
211,526
601,816
3,092,024
Literature estimates
Many formations reported15
4.5-4.7 million gal (median, Eagle
Ford play)b
4.5 million gal (median, Barnett play)b
6-7.5 million gal (median, Texas-
Haynesville play) and 0.5-1 million
gallons (median, Cotton Valley play)b
Many formations reported15
NA
Not reported by stateb
2.9 million gal (median, Wattenberg
field of Niobrara play)0
NA
NA
NA
NA
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Wyoming
Pennsylvania
West Virginia
Ohio
North Dakota
Montana
Oklahoma
Basin/total3
Greater Green River
Powder River
Other
Total
Appalachian
Total
Appalachian
Total
Appalachian
Total
Williston
Total
Williston
Other
Total
Anadarko
Arkoma
Ardmore
Other
Total
Number of
disclosures
861
351
193
1,405
2,445
2,445
273
273
146
146
2,109
2,109
187
20
207
935
158
98
592
1,783
Mean
(gal)
841,702
739,129
613,618
784,746
4,301,701
4,301,701
5,034,217
5,034,217
4,206,955
4,206,955
2,140,842
2,140,842
1,640,085
945,541
1,572,979
3,742,703
6,323,750
6,637,332
1,963,480
3,539,775
Median
(gal)
752,979
5,927
41,664
322,793
4,184,936
4,184,936
5,012,238
5,012,238
3,887,499
3,887,499
2,022,380
2,022,380
1,552,596
1,017,701
1,455,757
3,259,774
6,655,929
8,021,559
1,866,144
2,591,778
10th percentile
(gal)
147,020
5,353
22,105
5,727
2,313,649
2,313,649
3,170,210
3,170,210
2,885,568
2,885,568
969,380
969,380
375,864
157,639
367,326
1,211,700
172,375
81,894
1,319,247
1,260,906
90th percentile
(gal)
1,493,266
2,863,182
1,818,606
1,837,602
6,615,981
6,615,981
7,297,080
7,297,080
5,571,027
5,571,027
3,313,482
3,313,482
3,037,398
1,575,197
2,997,552
6,972,652
9,589,554
8,835,842
2,785,352
7,402,230
Literature estimates
NA
NA
NA
NA
4.2-4.6 million gal (average, Marcellus
play, Susquehanna River Basin)d
4.1-4.5d and 4.3-4.6e million gal
(average)
NA
4.7-6 million gal (average)d
NA
NA
NA
2.2 million gal (average)'
NA
NA
NA
Many formations reported8
Many formations reported8
Many formations reported8
NA
3 million gal (median)8
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Kansas
Arkansas
Louisiana
Utah
New Mexico
Basin/total3
Total
Arkoma
Total
TX-LA-MS Salt
Other
Total
Uinta-Piceance
Other
Total
Permian
San Juan
Other
Total
Number of
disclosures
121
1,423
1,423
939
27
966
1,396
10
1,406
732
363
50
1,145
Mean
(gal)
1,135,973
5,190,254
5,190,254
5,289,100
896,899
5,166,337
375,852
58,874
373,597
991,369
159,680
33,787
685,882
Median
(gal)
1,453,788
5,259,965
5,259,965
5,116,650
232,464
5,077,863
304,105
56,245
302,075
426,258
97,734
8,358
175,241
10th percentile
(gal)
10,836
3,234,963
3,234,963
2,851,654
87,003
1,812,099
77,166
28,745
76,286
89,895
27,217
1,100
35,638
90th percentile
(gal)
2,227,926
7,121,249
7,121,249
7,984,838
3,562,400
7,945,630
770,699
97,871
769,360
2,502,923
313,919
98,841
1,871,666
Literature estimates
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
California
Basin/total3
San Joaquin
Other
Total
Number of
disclosures
677
34
711
Mean
(gal)
131,653
132,391
131,689
Median
(gal)
77,238
36,099
76,818
10th percentile
(gal)
22,100
13,768
21,462
90th percentile
(gal)
285,029
361,192
285,306
Literature estimates
NA
NA
130,000 gallon
(average) h
a Basin boundaries for the FracFocus estimates were determined from data from the U.S. EIA (see U.S. EPA, 2015b).
b Literature estimates for Texas were from Nicot et al. (2012), using proprietary data from IMS. In most cases, Nicot et al. reported at the play scale or smaller, rather than the
EIA basin scale used for FracFocus. We reference 2011 and 2012 (partial year) for Nicot et al. where possible to overlap with the period of study for FracFocus, though more
years were available for most formations. A range is reported for some medians because median water use was different for the two years. There were five formations
reported for the Permian Basin (Wolfberry, Wolfcamp, Canyon, Clearfork, and San Andres-Greyburg). The most active area in the Permian Basin in 2011-2012 was the
Wolfberry, which reported a median of 1 to 1.1 million gallons per well—these were mostly vertical wells. For the TX-LA-MS Salt Basin, Nicot et al. reported two formations
(TX-Haynesville and Cotton Valley), with similar levels of activity in 2011-2012. Wells in TX-Haynesville were predominantly horizontal, while those in Cotton Valley were
predominantly vertical (though horizontal wells in Cotton Valley were also reported). There were three fields reported in the Anadarko Basin (Granite Wash, Cleveland, and
Marmaton). The most active area in the Anadarko Basin in 2011-2012 was the Granite Wash, which reported a median of 3.3 to 5.2 million gallons per well and where wells
were mostly horizontal.
c Literature estimates for the Denver Basin were from Goodwin et al. (2014). Goodwin et al. assessed 200 randomly sampled wells in the Wattenberg Field of the Denver Basin
(Niobrara Play), using industry data for wells operated by Noble Energy, drilled between January 1, 2010, and July 1, 2013. Water consumption is reported rather than water
use, but Goodwin et al. assume, based on Noble Energy practices, that water use and water consumption were identical because none of the flowback or produced water is
reused for hydraulic fracturing. Goodwin et al. reported drilling water consumed, hydraulic fracturing water consumed, and total water consumed. We present hydraulic
fracturing water consumption here (hydraulic fracturing water consumption was approximately 95% of the total).
d Hansen et al. (2013), using data from FracFocus via Skytruth. For the Susquehanna River Basin portion of the Marcellus play, and for Pennsylvania as a whole, the range of
annual averages is reported for 2011 and 2012. Similarly, for West Virginia, the range of annual averages is reported for 2011 and 2012 (partial year).
e Mitchell et al. (2013), using data reported to the Pennsylvania Department of Environmental Protection. Mitchell et al. reported water use in the Ohio River Basin for 2011
and 2012 (partial year) for horizontal and vertical wells. Here we report results for horizontal wells, which made up the majority of wells over the two-year period (i.e., 93%,
1,191 horizontal wells versus 96 vertical wells). A range is reported as before because the average water use differed between the two years.
f Literature estimates for North Dakota were from an informational bulletin from the North Dakota State Water Commission (2014). No further information was available.
g Murray (2013), who assessed water use for oil and gas operations from 2000-2010 for eight formations in Oklahoma using data from the Oklahoma Corporation Commission.
It is not possible to extract an estimate corresponding to 2011-2012 from Murray without the raw data, because medians were presented for the 10-year period rather than
separated by year.
h Literature estimates for California were from a California Council on Science and Technology report using data from FracFocus (CCST, 2014).
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Table B-6. Estimated percent domestic use water from ground water and self-supplied by
county.
Counties listed contained hyd rau I ica My fractured wells with valid state, county, and volume
information (lI
Data estimated from the USGS Water Census (MaufilrLetj|^2014).
State
Alabama
Arkansas
California
Colorado
County
Jefferson
Tuscaloosa
Cleburne
Conway
Faulkner
Independence
Logan
Sebastian
Van Buren
White
Yell
Colusa
Glenn
Kern
Los Angeles
Sutter
Ventura
Adams
Arapahoe
Boulder
Broomfield
Delta
Dolores
El Paso
Elbert
Fremont
Percent domestic use water
from ground watera'b
11.9
10.7
0.0
8.6
48.0
20.5
0.0
0.0
6.4
0.4
1.8
97.9
96.5
74.5
45.0
19.4
30.9
18.1
19.3
1.7
0.0
59.6
55.2
19.6
100.0
15.6
Percent domestic use
water self supplieda'c
0.8
6.1
0.0
8.6
3.5
9.4
0.0
0.0
6.4
0.0
1.8
10.3
21.6
1.7
4.2
4.6
3.9
2.8
1.3
1.5
0.0
28.4
51.4
5.1
75.2
15.6
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Colorado, cont.
Kansas
Cou nty
Garfield
Jackson
La Plata
Larimer
Las Animas
Mesa
Moffat
Morgan
Phillips
Rio Blanco
Routt
San Miguel
Weld
Yuma
Barber
Clark
Comanche
Finney
Grant
Gray
Harper
Haskell
Hodgeman
Kearny
Lane
Meade
Morton
Ness
Seward
Percent domestic use water
from ground watera'b
36.7
84.4
24.4
2.3
26.3
7.3
36.4
57.9
100.0
60.2
22.6
71.4
4.7
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Percent domestic use
water self supplied3'0
28.5
40.7
11.3
0.8
16.0
6.2
25.8
4.9
25.3
32.5
5.9
32.5
0.7
38.1
19.0
24.2
19.2
2.1
23.8
36.4
10.3
35.2
42.3
14.6
24.1
25.4
21.7
24.2
15.7
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Kansas, cont.
Louisiana
Michigan
Cou nty
Sheridan
Stanton
Stevens
Sumner
Allen
Beau regard
Bienville
Bossier
Caddo
Calcasieu
Caldwell
Claiborne
De Soto
East Feliciana
Jackson
Lincoln
Natchitoches
Rapides
Red River
Sabine
Tangipahoa
Union
Webster
West Feliciana
Winn
Cheboygan
Gladwin
Kalkaska
Missaukee
Ogemaw
Roscommon
Percent domestic use water
from ground watera'b
100.0
100.0
100.0
51.3
100.0
100.0
100.0
29.4
12.2
98.3
100.0
100.0
55.8
100.0
100.0
100.0
23.2
100.0
83.2
67.5
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Percent domestic use
water self supplied3'0
44.9
29.8
25.9
0.0
7.5
20.6
16.8
14.6
8.8
12.7
6.5
10.4
21.8
11.8
13.8
4.2
11.4
3.3
27.6
36.2
26.9
11.2
11.3
2.4
16.4
76.4
84.5
89.0
90.6
90.8
91.9
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Mississippi
Montana
New Mexico
North Dakota
Cou nty
Amite
Wilkinson
Daniels
Garfield
Glacier
Musselshell
Richland
Roosevelt
Rosebud
Sheridan
Chaves
Colfax
Eddy
Harding
Lea
Rio Arriba
Roosevelt
San Juan
Sandoval
Billings
Bottineau
Burke
Divide
Dunn
Golden Valley
Mckenzie
Mclean
Mountrail
Stark
Williams
Percent domestic use water
from ground watera'b
100.0
100.0
100.0
100.0
62.1
89.9
100.0
84.2
51.3
100.0
100.0
30.7
100.0
100.0
100.0
84.0
100.0
14.6
98.9
NA
100.0
100.0
100.0
100.0
100.0
75.8
12.5
65.7
NA
27.4
Percent domestic use
water self supplied3'0
26.0
11.1
29.4
70.0
17.7
54.5
30.8
20.9
10.3
31.0
11.8
2.6
2.2
25.0
17.4
42.3
8.9
12.9
23.2
33.3
13.7
12.5
12.5
21.4
7.7
15.7
9.9
11.5
5.7
7.3
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Ohio
Oklahoma
Cou nty
Ashland
Belmont
Carroll
Columbiana
Coshocton
Guernsey
Harrison
Jefferson
Knox
Medina
Muskingum
Noble
Portage
Stark
Tuscarawas
Wayne
Alfalfa
Beaver
Beckham
Blaine
Bryan
Caddo
Canadian
Carter
Coal
Custer
Dewey
Ellis
Garvin
Grady
Grant
Harper
Percent domestic use water
from ground watera'b
98.8
76.4
96.4
63.2
99.3
37.6
65.6
33.1
99.2
98.4
93.4
8.0
32.6
91.2
94.0
99.1
100.0
100.0
100.0
100.0
26.0
45.4
100.0
17.5
31.5
70.8
100.0
100.0
41.3
100.0
100.0
100.0
Percent domestic use
water self supplied3'0
57.4
8.9
76.4
43.2
34.9
9.5
45.9
10.2
41.1
83.1
17.0
8.0
18.3
30.9
23.5
49.0
14.6
47.9
10.6
8.8
7.8
35.1
0.0
0.5
27.5
13.2
22.5
31.4
15.8
34.2
13.2
22.6
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-30 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Oklahoma, cont.
Pennsylvania
Cou nty
Hughes
Jefferson
Johnston
Kay
Kingfisher
Kiowa
Latimer
Le Flore
Logan
Love
Major
Marshall
Mcclain
Noble
Oklahoma
Osage
Pawnee
Payne
Pittsburg
Roger Mills
Seminole
Stephens
Texas
Washita
Woods
Allegheny
Armstrong
Beaver
Blair
Bradford
Butler
Cameron
Percent domestic use water
from ground watera'b
23.6
13.5
53.4
39.2
100.0
10.3
12.6
14.3
61.1
100.0
100.0
20.1
95.9
23.3
22.0
18.0
38.2
47.9
0.6
80.1
78.8
99.2
100.0
53.9
100.0
15.7
45.3
54.7
34.9
100.0
51.8
29.0
Percent domestic use
water self supplied3'0
6.7
1.8
1.1
4.6
28.3
0.0
12.6
13.1
34.6
3.8
28.1
4.4
23.9
14.3
2.5
14.9
27.7
12.6
0.0
19.4
16.1
14.9
10.9
18.2
14.7
15.3
36.8
26.8
24.0
65.2
42.8
29.0
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-31 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Pennsylvania, cont.
Texas
Cou nty
Centre
Clarion
Clearfield
Clinton
Columbia
Crawford
Elk
Fayette
Forest
Greene
Huntingdon
Indiana
Jefferson
Lawrence
Lycoming
McKean
Potter
Somerset
Sullivan
Susquehanna
Tioga
Venango
Warren
Washington
Westmoreland
Wyoming
Andrews
Angelina
Archer
Atascosa
Austin
Bee
Percent domestic use water
from ground watera'b
93.1
61.5
38.4
48.4
77.5
97.7
25.3
19.2
100.0
31.9
73.2
52.2
60.7
40.5
60.0
56.6
93.7
42.6
100.0
79.9
81.3
95.9
96.9
21.6
21.3
100.0
100.0
100.0
16.9
100.0
100.0
100.0
Percent domestic use
water self supplied3'0
21.3
55.8
22.7
38.1
56.7
66.0
15.6
16.1
78.3
31.9
57.8
49.1
46.1
38.8
29.3
33.3
58.1
33.5
76.9
74.7
58.3
32.7
49.4
21.5
19.8
70.6
23.4
9.8
16.9
16.3
55.6
52.5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-32 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Borden
Bosque
Brazos
Brooks
Burleson
Cherokee
Clay
Cochran
Coke
Colorado
Concho
Cooke
Cottle
Crane
Crockett
Crosby
Culberson
Dallas
Dawson
DeWitt
Denton
Dimmit
Ector
Edwards
Ellis
Erath
Fayette
Fisher
Franklin
Freestone
Frio
Gaines
Percent domestic use water
from ground watera'b
100.0
88.7
100.0
100.0
100.0
87.5
44.6
100.0
29.0
100.0
96.8
75.5
100.0
100.0
100.0
35.6
100.0
1.0
100.0
100.0
9.0
100.0
100.0
100.0
32.2
100.0
100.0
NA
0.9
100.0
100.0
100.0
Percent domestic use
water self supplied3'0
71.4
30.3
2.1
35.3
42.9
26.1
36.7
23.3
28.9
45.4
5.0
8.9
21.4
14.3
42.5
19.0
13.8
0.7
33.8
42.3
3.6
30.5
28.3
42.1
7.9
43.3
27.6
36.8
0.0
31.2
20.4
45.5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-33 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Garza
Glasscock
Goliad
Gonzales
Grayson
Gregg
Grimes
Hansford
Hardeman
Hardin
Harrison
Hartley
Haskell
Hemphill
Hidalgo
Hockley
Hood
Houston
Howard
Hutchinson
Irion
Jack
Jefferson
Jim Hogg
Johnson
Jones
Karnes
Kenedy
Kent
King
Kleberg
Knox
Percent domestic use water
from ground watera'b
20.1
NA
NA
96.8
56.0
20.8
100.0
100.0
87.6
100.0
43.8
100.0
100.0
100.0
9.2
100.0
70.8
79.7
100.0
27.3
100.0
46.7
25.0
NA
34.9
60.5
100.0
100.0
100.0
100.0
100.0
86.2
Percent domestic use
water self supplied3'0
17.2
100.0
66.7
15.9
4.2
14.1
26.0
16.4
13.3
29.5
24.8
39.7
15.7
27.5
1.6
27.4
39.8
36.6
19.8
14.9
50.0
43.8
5.8
25.0
6.8
60.5
17.6
25.0
37.5
33.3
1.9
24.2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-34 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
La Salle
Lavaca
Lee
Leon
Liberty
Limestone
Lipscomb
Live Oak
Loving
Lynn
Madison
Marion
Martin
Maverick
McMullen
Medina
Menard
Midland
Milam
Mitchell
Montague
Montgomery
Moore
Nacogdoches
Navarro
Newton
Nolan
Nueces
Ochiltree
Oldham
Orange
Palo Pinto
Percent domestic use water
from ground watera'b
100.0
100.0
100.0
100.0
98.5
46.5
100.0
32.8
NA
64.1
100.0
13.7
100.0
27.6
100.0
98.0
36.4
100.0
82.5
100.0
57.1
100.0
100.0
55.6
22.0
100.0
100.0
5.6
100.0
100.0
99.1
11.7
Percent domestic use
water self supplied3'0
43.3
56.0
15.9
41.4
42.5
32.5
23.5
32.1
0.0
32.2
66.9
8.4
48.9
27.6
40.0
23.6
36.4
22.1
41.1
14.7
49.7
26.6
8.1
21.6
22.0
63.7
17.6
5.6
16.8
58.8
41.2
11.7
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-35 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Cou nty
Panola
Parker
Pecos
Polk
Potter
Reagan
Reeves
Roberts
Robertson
Runnels
Rusk
Sabine
San Augustine
San Patricio
Schleicher
Scurry
Shelby
Sherman
Smith
Somervell
Starr
Stephens
Sterling
Stonewall
Sutton
Tarrant
Terrell
Terry
Tyler
Upshur
Upton
Van Zandt
Percent domestic use water
from ground watera'b
96.6
63.5
100.0
41.9
100.0
100.0
100.0
100.0
97.1
13.5
90.7
76.2
78.0
88.8
100.0
32.5
66.2
100.0
48.0
87.7
23.2
13.5
NA
NA
100.0
3.7
100.0
100.0
100.0
54.1
100.0
65.7
Percent domestic use
water self supplied3'0
58.7
41.1
31.3
41.7
12.6
16.2
31.1
33.3
22.5
13.5
41.8
69.0
74.4
21.8
40.0
27.7
58.2
33.3
13.7
69.3
23.2
13.5
18.8
40.0
26.7
1.3
25.0
16.7
73.6
23.2
15.2
39.0
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-36 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Texas, cont.
Utah
Virginia
West Virginia
Cou nty
Walker
Waller
Ward
Washington
Webb
Wharton
Wheeler
Wichita
Wilbarger
Willacy
Wilson
Winkler
Wise
Wood
Yoakum
Young
Zapata
Zavala
Carbon
Duchesne
San Juan
Sevier
Uintah
Buchanan
Dickenson
Wise
Barbour
Brooke
Doddridge
Hancock
Harrison
Lewis
Percent domestic use water
from ground watera'b
57.7
100.0
100.0
48.2
99.4
100.0
100.0
8.8
100.0
28.4
100.0
100.0
51.3
21.3
100.0
19.3
13.9
100.0
50.0
57.1
68.3
100.0
87.7
NA
2.5
5.9
24.1
33.4
60.6
67.7
8.8
29.5
Percent domestic use
water self supplied3'0
30.6
37.2
4.5
36.0
0.5
45.9
31.3
2.9
11.5
28.4
6.9
3.8
50.4
12.9
36.0
18.9
13.9
15.2
1.2
10.4
47.5
10.0
3.1
27.6
2.5
2.3
24.8
6.8
62.1
6.9
8.9
30.3
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-37 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
West Virginia, cont.
Wyoming
Cou nty
Marion
Marshall
Monongalia
Ohio
Pleasants
Preston
Ritchie
Taylor
Tyler
Upshur
Webster
Wetzel
Big Horn
Campbell
Carbon
Converse
Fremont
Goshen
Hot Springs
Johnson
Laramie
Lincoln
Natrona
Niobrara
Park
Percent domestic use water
from ground watera'b
5.8
96.5
5.3
5.4
100.0
66.1
45.2
14.9
44.4
27.3
41.9
96.3
79.4
100.0
63.8
96.5
49.3
100.0
31.9
40.8
38.1
82.4
69.0
100.0
18.9
Percent domestic use
water self supplied3'0
4.9
12.0
5.5
3.4
27.9
41.0
46.4
14.9
39.2
27.8
43.2
28.6
11.3
0.6
6.7
17.0
23.7
21.1
8.2
35.4
13.0
9.0
6.6
16.3
13.7
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-38 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
State
Wyoming, cont.
Cou nty
Sublette
Sweetwater
Uinta
Washakie
Percent domestic use water
from ground watera'b
54.6
3.5
19.5
100.0
Percent domestic use
water self supplied3'0
22.1
0.4
11.5
16.0
a Data accessed from the USGS website (httg^/waterusgsj5oy/watuse/data/2010/) on November 11, 2014. Domestic water
use is water used for indoor household purposes such as drinking, food preparation, bathing, washing clothes and dishes,
flushing toilets, and outdoor purposes such as watering lawns and gardens (
b Percent domestic water use from ground water estimated with the following equation: (Domestic public supply volume from
ground water + Domestic self-supplied volume from ground water)/ Domestic total water use volume * 100. Domestic public
supply volume from ground water was estimated by multiplying the volume of domestic water from public supply by the ratio
of public supply volume from ground water to total public supply volume.
c Percent domestic water use self-supplied estimated by dividing the volume of domestic water self-supplied by total domestic
water use volume.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-39 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Table B-7. Projected hydraulic fracturing water use by Texas counties between 2015 and 2060, expressed as a percentage of 2010
total county water use.
Hydraulic fracturing water use data from Nicot_et_aL_(20121. Total water use data from 2010 from the USGS Water Census (Mauein_et_aL-2Q14). All
254 Texas counties are listed by descending order of percentages in 2030.
Texas county
McMullen
Irion
LaSalle
San Augustine
Sterling
Dimmit
Sabine
Leon
Karnes
Loving
Shackelford
Madison
Schleicher
Sutton
Shelby
DeWitt
Hemphill
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
126.2
36.1
58.4
60.2
12.0
38.2
9.6
9.9
48.1
13.1
0.0
5.5
10.5
0.0
11.0
26.9
25.7
2020
137.0
59.2
58.3
56.2
32.0
38.1
19.2
19.3
43.0
17.4
7.9
11.8
15.8
11.0
20.4
24.1
23.1
2025
152.1
70.5
59.7
52.2
39.9
38.9
28.7
27.0
37.9
23.4
15.7
15.7
19.1
15.1
19.4
21.4
20.5
2030
165.1
63.7
60.8
48.2
40.5
39.0
38.3
34.6
32.6
29.4
23.6
19.7
19.7
19.1
18.4
18.4
17.8
2035
176.7
53.4
61.9
44.2
41.0
38.7
35.1
32.9
27.2
28.8
21.2
17.4
17.1
23.2
17.4
15.4
15.2
2040
164.0
43.1
54.6
40.2
34.7
33.9
31.9
29.0
21.8
26.2
18.9
15.2
14.5
20.6
15.7
12.3
12.6
2045
145.3
32.8
45.3
36.2
28.3
27.9
28.7
25.1
16.4
23.6
16.5
13.0
11.9
18.1
14.1
9.3
10.0
2050
126.6
22.4
36.0
32.1
21.9
22.0
25.6
21.2
11.0
20.9
14.1
10.9
9.3
15.5
12.5
6.3
7.3
2055
108.0
12.1
26.7
28.1
15.6
16.0
22.3
17.3
5.6
18.3
11.8
8.7
6.7
12.9
10.9
3.2
4.7
2060
89.3
5.4
17.4
24.1
10.7
10.1
19.2
13.5
0.2
15.7
9.4
6.5
4.7
10.3
9.3
0.2
2.1
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-40 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Terrell
Coryell
Montague
Crockett
Upton
Borden
Live Oak
Reagan
Clay
Wheeler
Lavaca
Washington
Nacogdoches
Hill
Jack
Panola
Jim Hogg
Howard
Parker
Hamilton
Johnson
Midland
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
7.0
28.6
7.6
12.1
3.1
13.3
11.2
3.2
17.6
7.9
0.0
7.9
17.1
3.5
7.2
4.8
4.4
3.7
8.8
14.2
6.7
2020
9.7
24.4
24.5
12.5
15.2
8.6
12.4
14.0
5.9
15.3
13.2
6.7
11.4
14.7
5.3
10.2
6.4
7.1
5.0
10.7
11.9
8.3
2025
13.2
22.8
20.4
14.8
14.1
12.0
11.5
12.7
8.6
13.1
12.0
11.8
10.7
12.2
7.1
9.2
8.0
8.5
6.3
8.9
9.5
7.7
2030
16.8
16.5
16.3
13.4
12.9
12.1
11.8
11.3
11.3
10.8
10.7
10.7
10.0
9.8
8.8
8.5
8.0
8.0
7.6
7.1
7.1
7.1
2035
20.4
10.1
12.2
11.2
11.7
12.2
12.2
9.9
10.3
8.6
9.4
9.6
9.2
7.3
7.9
7.7
6.9
6.8
6.8
5.3
4.7
6.2
2040
18.2
3.8
8.2
9.1
9.8
10.3
12.7
8.1
9.4
6.3
8.1
8.6
8.3
4.9
7.1
7.0
6.0
5.6
6.1
3.5
2.4
5.2
2045
15.9
0.0
4.1
6.9
7.9
8.4
13.2
6.4
8.4
4.1
6.7
7.5
7.5
2.4
6.2
6.3
4.9
4.4
5.3
1.8
0.0
4.1
2050
13.6
0.0
0.0
4.7
5.9
6.4
11.7
4.6
7.5
1.8
5.4
6.4
6.6
0.0
5.3
5.5
3.9
3.2
4.5
0.0
0.0
3.0
2055
11.3
0.0
0.0
2.5
4.0
4.5
9.8
2.8
6.6
0.0
4.0
5.3
5.7
0.0
4.4
4.8
2.9
2.1
3.8
0.0
0.0
2.0
2060
9.0
0.0
0.0
1.1
2.7
3.1
7.8
1.6
5.6
0.0
2.7
4.3
4.9
0.0
3.5
4.0
1.8
1.3
3.0
0.0
0.0
1.2
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-41 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Kenedy
Fayette
Lee
Winkler
Wilson
Martin
Burleson
Atascosa
Bosque
Webb
Gonzales
Marion
Harrison
Eastland
Archer
Zavala
Roberts
Maverick
Cooke
Ward
Austin
Reeves
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
4.1
3.9
2.1
2.9
6.7
5.7
1.0
6.3
1.8
7.5
8.0
1.1
4.3
0.0
1.0
4.7
6.9
2.5
11.9
2.7
0.0
1.4
2020
5.4
8.4
4.1
3.8
7.7
7.1
2.9
5.7
3.0
7.1
7.1
2.4
6.1
3.9
2.4
5.5
6.0
3.0
9.3
3.2
1.2
1.8
2025
6.8
7.6
5.3
5.1
7.0
6.5
4.3
5.6
4.3
6.3
6.2
3.8
5.5
5.9
3.6
5.2
5.1
3.6
6.7
4.2
2.5
2.7
2030
6.8
6.6
6.5
6.3
6.2
6.0
5.7
5.6
5.5
5.4
5.3
5.1
5.1
5.0
4.9
4.9
4.2
4.2
4.1
4.1
3.7
3.7
2035
5.9
5.5
5.8
6.0
5.4
5.3
5.1
5.6
5.1
4.6
4.4
5.2
4.6
4.2
4.5
4.6
3.4
4.8
1.5
4.0
3.4
3.9
2040
5.1
4.4
5.1
5.4
4.6
4.4
4.5
5.6
4.6
3.8
3.6
4.7
4.2
3.3
4.1
4.3
2.5
4.5
0.0
3.6
3.0
3.6
2045
4.1
3.4
4.3
4.7
3.9
3.5
3.9
5.0
4.2
3.1
2.7
4.2
3.7
2.5
3.7
4.0
1.6
4.0
0.0
3.2
2.6
3.3
2050
3.3
2.3
3.6
4.1
3.1
2.6
3.3
4.2
3.7
2.3
1.8
3.7
3.3
1.7
3.3
3.4
0.7
3.6
0.0
2.7
2.2
3.0
2055
2.4
1.2
2.9
3.4
2.3
1.8
2.6
3.4
3.2
1.4
0.9
3.2
2.9
0.8
2.9
2.7
0.0
3.1
0.0
2.3
1.9
2.6
2060
1.6
0.2
2.1
2.8
1.5
1.2
2.0
2.7
2.8
0.5
0.0
2.7
2.4
0.0
2.5
2.0
0.0
2.6
0.0
1.9
1.5
2.3
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-42 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Glasscock
Tyler
Hood
Garza
Andrews
Crane
Erath
Wise
Upshur
Mitchell
Ector
Culberson
Lipscomb
Angelina
Houston
Frio
Newton
Kleberg
Brooks
Brazos
Comanche
Ochiltree
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
3.1
1.9
1.4
1.5
2.3
1.3
0.9
3.6
0.2
1.2
1.5
0.3
1.7
0.4
2.1
1.8
1.8
1.0
1.0
0.4
0.4
0.6
2020
4.1
2.6
2.0
2.0
3.0
1.7
1.4
3.2
0.9
1.6
2.0
0.4
3.0
0.9
2.7
1.8
2.3
1.4
1.3
0.9
0.7
1.1
2025
3.9
3.2
2.6
2.5
2.9
2.1
1.9
2.8
1.7
2.0
2.1
1.3
2.6
1.5
2.4
1.9
2.1
1.7
1.7
1.2
1.0
1.5
2030
3.6
3.2
3.2
2.9
2.7
2.6
2.4
2.4
2.4
2.4
2.3
2.2
2.1
2.1
2.1
1.9
1.8
1.7
1.7
1.5
1.4
1.2
2035
3.1
2.8
2.9
2.7
2.6
3.1
2.2
2.0
2.9
2.1
2.2
2.9
1.7
2.2
1.8
1.8
1.6
1.5
1.5
1.4
1.2
1.0
2040
2.6
2.4
2.6
2.4
2.3
2.8
2.0
1.6
2.6
1.9
1.9
2.6
1.3
2.0
1.5
1.8
1.3
1.3
1.2
1.2
1.1
0.7
2045
2.1
2.0
2.2
2.1
2.0
2.5
1.8
1.2
2.3
1.7
1.7
2.4
0.8
1.8
1.2
1.7
1.0
1.1
1.0
1.0
1.0
0.5
2050
1.5
1.6
1.9
1.8
1.7
2.2
1.6
0.8
2.1
1.4
1.4
2.1
0.4
1.6
0.9
1.5
0.8
0.8
0.8
0.8
0.8
0.2
2055
1.0
1.1
1.6
1.5
1.4
1.9
1.4
0.4
1.8
1.2
1.2
1.9
0.0
1.4
0.6
1.2
0.5
0.6
0.6
0.7
0.7
0.0
2060
0.7
0.7
1.3
1.2
1.1
1.7
1.2
0.0
1.5
0.9
1.0
1.6
0.0
1.2
0.3
0.9
0.3
0.4
0.4
0.5
0.5
0.0
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-43 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Palo Pinto
Limestone
Duval
Stephens
Dawson
Scurry
Bee
Val Verde
Colorado
Tarrant
Zapata
Ellis
Jim Wells
Lynn
Henderson
Hansford
Gaines
Gregg
Refugio
Caldwell
Pecos
Anderson
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.3
0.9
0.7
0.1
0.5
0.0
0.8
0.0
<0.1
2.1
0.5
0.3
0.4
0.0
0.1
0.0
0.2
0.1
0.2
0.4
0.1
0.1
2020
0.6
1.0
0.9
0.4
0.8
0.6
1.1
0.5
0.3
1.7
0.7
0.5
0.6
0.4
0.3
0.4
0.3
0.2
0.3
0.5
0.1
0.2
2025
0.9
1.1
1.1
0.8
1.0
0.8
1.1
0.8
0.6
1.3
0.8
0.6
0.7
0.6
0.5
0.8
0.5
0.3
0.4
0.4
0.2
0.3
2030
1.2
1.2
1.1
1.1
1.1
1.0
1.0
0.9
0.9
0.9
0.8
0.8
0.7
0.7
0.7
0.7
0.5
0.4
0.4
0.4
0.4
0.4
2035
1.1
1.1
1.0
1.0
1.1
1.2
0.9
1.1
0.8
0.4
0.7
0.7
0.6
0.8
0.8
0.5
0.5
0.4
0.3
0.3
0.5
0.4
2040
1.0
1.0
0.8
0.9
1.0
1.1
0.7
1.0
0.7
0.0
0.6
0.6
0.5
0.8
0.7
0.4
0.4
0.4
0.3
0.3
0.4
0.4
2045
0.8
0.8
0.7
0.8
0.8
0.9
0.6
0.9
0.6
0.0
0.5
0.6
0.4
0.7
0.6
0.3
0.4
0.4
0.2
0.2
0.4
0.4
2050
0.7
0.7
0.5
0.6
0.6
0.8
0.4
0.8
0.5
0.0
0.4
0.5
0.4
0.6
0.5
0.2
0.3
0.3
0.2
0.2
0.3
0.3
2055
0.6
0.6
0.4
0.5
0.5
0.7
0.3
0.6
0.4
0.0
0.3
0.4
0.3
0.5
0.4
0.1
0.2
0.3
0.1
0.1
0.3
0.3
2060
0.5
0.4
0.3
0.4
0.3
0.5
0.1
0.5
0.4
0.0
0.2
0.3
0.2
0.4
0.4
0
0.2
0.2
0.1
0.1
0.2
0.2
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-44 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Young
San Patricio
Smith
Cherokee
McLennan
Terry
Starr
Cochran
Jasper
Dallas
Robertson
Grimes
Yoakum
Freestone
Cass
Hutchinson
Rusk
Willacy
Victoria
Sherman
Calhoun
Lubbock
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
0.2
0.1
0.1
0.1
0.0
0.2
0.1
0.2
0.2
0.1
<0.1
0.1
0.1
<0.1
0.0
<0.1
<0.1
<0.1
0.0
<0.1
0.0
2020
0.1
0.3
0.1
0.2
0.1
0.2
0.2
0.2
0.3
0.3
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.0
0.1
0.0
2025
0.2
0.4
0.2
0.2
0.2
0.2
0.3
0.2
0.2
0.2
0.2
0.1
0.2
0.1
0.1
0.2
0.1
0.1
0.1
<0.1
0.1
<0.1
2030
0.4
0.4
0.3
0.3
0.3
0.3
0.3
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
2035
0.3
0.3
0.4
0.4
0.3
0.3
0.2
0.3
0.2
0.1
0.2
0.1
0.1
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
2040
0.3
0.3
0.3
0.3
0.2
0.3
0.2
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
2045
0.3
0.2
0.3
0.3
0.2
0.3
0.2
0.2
0.1
<0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
<0.1
<0.1
<0.1
0.1
2050
0.2
0.2
0.3
0.2
0.2
0.2
0.1
0.2
0.1
0.0
0.1
0.1
0.1
0.1
0.1
<0.1
0.1
<0.1
<0.1
<0.1
<0.1
0.1
2055
0.2
0.1
0.2
0.2
0.2
0.2
0.1
0.2
0.1
0.0
0.1
0.1
0.1
0.1
0.1
<0.1
0.1
<0.1
<0.1
<0.1
<0.1
0.1
2060
0.1
0.1
0.2
0.2
0.1
0.2
0.1
0.1
<0.1
0.0
0.1
0.1
0.1
0.1
0.1
0.0
<0.1
<0.1
<0.1
<0.1
<0.1
0.1
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-45 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Jackson
Matagorda
Polk
Wharton
Nueces
Hidalgo
Cameron
Somervell
Goliad
Brazoria
Fort Bend
Aransas
Armstrong
Bailey
Bandera
Bastrop
Baylor
Bell
Bexar
Blanco
Bowie
Brewster
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2020
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2025
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2030
0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2035
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2040
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2045
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2050
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2055
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2060
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
<0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-46 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Briscoe
Brown
Burnet
Callahan
Camp
Carson
Castro
Chambers
Childress
Coke
Coleman
Collin
Collingsworth
Comal
Concho
Cottle
Crosby
Dallam
Deaf Smith
Delta
Denton
Dickens
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.7
0.0
2020
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
1.1
0.0
2025
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.6
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2035
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2040
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2045
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2050
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2055
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2060
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-47 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Donley
Edwards
El Paso
Falls
Fannin
Fisher
Floyd
Foard
Franklin
Galveston
Gillespie
Gray
Grayson
Guadalupe
Hale
Hall
Hardeman
Hardin
Harris
Hartley
Haskell
Hays
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2020
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2025
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2035
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2040
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2045
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2050
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2055
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2060
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-48 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Hockley
Hopkins
Hudspeth
Hunt
Jeff Davis
Jefferson
Jones
Kaufman
Kendall
Kent
Kerr
Kimble
King
Kinney
Knox
Lamar
Lamb
Lampasas
Liberty
Llano
McCulloch
Mason
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2020
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2025
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2035
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2040
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2045
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2050
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2055
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2060
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-49 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
Medina
Menard
Milam
Mills
Montgomery
Moore
Morris
Motley
Navarro
Nolan
Oldham
Orange
Parmer
Potter
Presidio
Rains
Randall
Real
Red River
Rockwall
Runnels
San Jacinto
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2020
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2025
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2035
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2040
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2045
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2050
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2055
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2060
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-50 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix B
Texas county
San Saba
Stonewall
Swisher
Taylor
Throckmorton
Titus
Tom Green
Travis
Trinity
Uvalde
Van Zandt
Walker
Waller
Wichita
Wilbarger
Williamson
Wood
Projected hydraulic fracturing water use as a percentage of 2010 total water usea'b
2015
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2020
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2025
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2030
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2035
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2040
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2045
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2050
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2055
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
2060
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
a Total water use data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on April 21, 2015. Data from Nicotetal. 12012) transcribed.
b Percentages calculated by dividing projected hydraulic fracturing water use volumes from Nicot et al. 12012) by 2010 total water use from the USGS and multiplying by 100.
Percentages less than 0.1 were not rounded and simply noted as "<0.1", but where the percentage was actually zero because there was no projected hydraulic fracturing
water use we noted that as "0.0".
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
B-51 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix B
B.2. References for Appendix B
CCST (California Council on Science and Technology). (2014). Advanced well stimulation technologies in
California: An independent review of scientific and technical information. Sacramento, CA.
http://ccst.us/publications/2014/2014wst.pdf
Goodwin, S: Carlson, K: Knox, K: Douglas, C: Rein, L. (2014). Water intensity assessment of shale gas resources
in the Wallenberg field in norlheaslern Colorado. Environ Sci Technol 48: 5991-5995.
hllp://dx.doi.org/10.1021/es404675h
Hansen. E: Mulvaney. D: Belcher. M. (2013). Waler resource reporting and water foolprinl from Marcellus
Shale developmenl in Wesl Virginia and Pennsylvania. Durango, CO: Earlhworks Oil & Gas Accountability
Project hllp://www.downslreamslralegies.com/documenls/reporls publicalion/marcellus wv pa.pdf
Maupin. MA: Kenny. IF: Hulson. SS: Lovelace. IK: Barber. NL: Linsey. KS. (2014). Estimated use of water in Ihe
United Stales in 2010. (USGS Circular 1405). Reslon, VA: U.S. Geological Survey.
hllp://dx.doi.org/10.3133/cirl405
Milchell. AL: Small. M: Gasman. EA. (2013). Surface water wilhdrawals for Marcellus Shale gas developmenl:
performance of alternative regulatory approaches in Ihe Upper Ohio River Basin. Environ Sci Technol 47:
12669-12678. hllp://dx.doi.org/10.1021/es403537z
Murray. KE. (2013). Stale-scale perspective on water use and production associated wilh oil and gas
operations, Oklahoma, U.S. Environ Sci Technol 47: 4918-4925. hllp://dx.doi.org/10.1021/es4000593
Nicol. IP: Reedy. RC: Coslley. RA: Huang. Y. (2012). Oil & gas water use in Texas: Update to Ihe 2011 mining
water use report Nicol, JP; Reedy, RC; Coslley, RA; Huang, Y.
hllp://www.lwdb.slale.lx.us/publicalions/reporls/conlracled reporls/doc/0904830939 2012Updale M
iningWalerUse.pdf
Nicol, IP: Scanlon, BR. (2012). Waler use for shale-gas production in Texas, U.S. Environ Sci Technol 46: 3580-
3586. hllp://dx.doi.org/10.1021/es204602l
Norlh Dakota Slate Waler Commission. (2014). Facls aboul Norlh Dakota (racking and water use. Bismarck,
ND. hllp://www.swc.nd.gov/4dlink9/4dcgi/GelConlenlPDF/PB-2419/Facl%20Sheetpdf
Solley. WB: Pierce. RR: Perlman. HA. (1998). Estimated use of water in Ihe United Slates in 1995. (USGS
Circular: 1200). U.S. Geological Survey, http://pubs.er.usgs.gov/publicalion/cirl200
U.S. EPA (U.S. Environmental Protection Agency). (2015a). Analysis of hydraulic fracluring fluid data from Ihe
FracFocus chemical disclosure regislry 1.0 [EPA Report]. (EPA/601/R-14/003). Washington, D.C.: Office
of Research and Developmenl, U.S. Environmental Protection Agency.
http://www2.epa.gov/hfsludy/analysis-hydraulic-fracluring-fluid-dala-fracfocus-chemical-disclosure-
regislry-1-pdf
U.S. EPA (U.S. Environmental Protection Agency). (2015b). Analysis of hydraulic fracluring fluid data from Ihe
FracFocus chemical disclosure regislry 1.0: Data managemenl and quality assessmenl report [EPA
Report]. (EPA/601/R-14/006). Washington, D.C.: U.S. Environmental Protection Agency, Office of
Research and Developmenl. http://www2.epa.gov/siles/produclion/files/2015-
03/documenls/fracfocus date managemenl report final 032015 508.pdf
U.S. EPA (U.S. Environmental Protection Agency). (2015c). Analysis of hydraulic fracluring fluid data from Ihe
FracFocus chemical disclosure regislry 1.0: Projecl database [EPA Report]. (EPA/601/R-14/003).
Washington, D.C.: U.S. Environmental Protection Agency, Office of Research and Developmenl.
http://www2.epa.gov/hfsludy/epa-projecl-dalabase-developed-fracfocus-l-disclosures
USGS (U.S. Geological Survey). (2014). Wilhdrawal and consumption of water by Ihermoeleclric power planls
in Ihe United Stales, 2010. (Scientific Investigations Report 20145184). Reslon, VA.
http://dx.doi.org/10.3133/sir20145184
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-52 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix B
HL (2009). Water withdrawal for brackish and inland aquaculture, and options to
produce more fish in ponds with present water use. Water Policy 11: 52-68.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 B-53 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix C
Appendix C
Chemical Mixing Supplemental Tables and
Information
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Appendix C. Chemical Mixing Supplemental Tables and
Information
C.I. Supplemental Tables and Information
Table C-l. Chemicals reported to FracFocus in 10% or more of disclosures for gas-producing
wells, with the number of disclosures where chemical is reported, percentage of
disclosures, and the median maximum concentration (% by mass) of that chemical
in hydraulic fracturing fluid.
Chemicals ranked by frequency of occurrence (y^
Chemical name
Hydrochloric acid
Methanol
Distillates, petroleum, hydrotreated light
Isopropanol
Water
Ethanol
Propargyl alcohol
Glutaraldehyde
Ethylene glycol
Citric acid
Sodium hydroxide
Peroxydisulfuric acid, diammonium salt
Quartz
2,2-Dibromo-3-nitrilopropionamide
Sodium chloride
Guargum
Acetic acid
2-Butoxyethanol
Naphthalene
Solvent naphtha, petroleum, heavy arom.
Quaternary ammonium compounds,
benzyl-C12-16-alkyldimethyl, chlorides
Potassium hydroxide
Ammonium chloride
Choline chloride
CASRN
7647-01-0
67-56-1
64742-47-8
67-63-0
7732-18-5
64-17-5
107-19-7
111-30-8
107-21-1
77-92-9
1310-73-2
7727-54-0
14808-60-7
10222-01-2
7647-14-5
9000-30-0
64-19-7
111-76-2
91-20-3
64742-94-5
68424-85-1
1310-58-3
12125-02-9
67-48-1
Number of
disclosures
12,351
12,269
11,897
8,008
7,998
6,325
5,811
5,635
5,493
4,832
4,656
4,618
3,758
3,668
3,608
3,586
3,563
3,325
3,294
3,287
3,259
2,843
2,483
2,477
Percentage of
disclosures
72.8%
72.3%
70.1%
47.2%
47.1%
37.3%
34.2%
33.2%
32.4%
28.5%
27.4%
27.2%
22.1%
21.6%
21.3%
21.1%
21.0%
19.6%
19.4%
19.4%
19.2%
16.8%
14.6%
14.6%
Median maximum
concentration in
hydraulic fracturing
fluid (% by mass)
15%
30%
30%
30%
63%
5%
10%
30%
35%
60%
5%
100%
10%
100%
30%
60%
50%
10%
5%
30%
7%
15%
10%
75%
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-l DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Poly(oxy-l,2-ethanediyl)-nonylphenyl-
hydroxy (mixture)
Sodium chlorite
1,2,4-Trimethylbenzene
Carbonic acid, dipotassium salt
Methenamine
Formic acid
Didecyl dimethyl ammonium chloride
N,N-Dimethylformamide
Phenolic resin
Thiourea polymer
Polyethylene glycol
CASRN
127087-87-0
7758-19-2
95-63-6
584-08-7
100-97-0
64-18-6
7173-51-5
68-12-2
9003-35-4
68527-49-1
25322-68-3
Number of
disclosures
2,455
2,372
2,229
2,154
2,134
2,118
2,063
1,892
1,852
1,702
1,696
Percentage of
disclosures
14.5%
14.0%
13.1%
12.7%
12.6%
12.5%
12.2%
11.2%
10.9%
10.0%
10.0%
Median maximum
concentration in
hydraulic fracturing
fluid (% by mass)
5%
10%
1%
60%
1%
60%
10%
13%
5%
30%
60%
Note: Analysis considered 17,035 disclosures and 291,363 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet quality assurance criteria
(1,587) or other, query-specific criteria were excluded from analysis.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-2 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-2. Chemicals reported to FracFocus in 10% or more of disclosures for oil-producing
wells, with the number of disclosures where chemical is reported, percentage of
disclosures, and the median maximum concentration (% by mass) of that chemical
in hydraulic fracturing fluid.
Chemicals ranked by frequency of occurrence (LLS._EPAI_2015c).
Chemical name
Methanol
Distillates, petroleum, hydrotreated light
Peroxydisulfuric acid, diammonium salt
Ethylene glycol
Hydrochloric acid
Guar gum
Sodium hydroxide
Quartz
Water
Isopropanol
Potassium hydroxide
Glutaraldehyde
Propargyl alcohol
Acetic acid
2-Butoxyethanol
Solvent naphtha, petroleum, heavy arom.
Sodium chloride
Ethanol
Citric acid
Phenolic resin
Naphthalene
Nonyl phenol ethoxylate
Diatomaceous earth, calcined
Methenamine
Tetramethylammonium chloride
Carbonic acid, dipotassium salt
Ethoxylated propoxylated C12-14 alcohols
Choline chloride
Boron sodium oxide
Tetrakis(hydroxymethyl)phosphonium sulfate
1,2,4-Trimethylbenzene
CASRN
67-56-1
64742-47-8
7727-54-0
107-21-1
7647-01-0
9000-30-0
1310-73-2
14808-60-7
7732-18-5
67-63-0
1310-58-3
111-30-8
107-19-7
64-19-7
111-76-2
64742-94-5
7647-14-5
64-17-5
77-92-9
9003-35-4
91-20-3
9016-45-9
91053-39-3
100-97-0
75-57-0
584-08-7
68439-51-0
67-48-1
1330-43-4
55566-30-8
95-63-6
Number of
disclosures
12,484
10,566
10,350
10,307
10,029
9,110
8,609
8,577
8,538
8,031
7,206
5,927
5,599
4,623
4,022
3,821
3,692
3,536
3,310
3,109
3,060
2,829
2,655
2,559
2,428
2,402
2,342
2,264
2,228
2,130
2,118
Percentage of
disclosures
71.8%
60.8%
59.6%
59.3%
57.7%
52.4%
49.5%
49.4%
49.1%
46.2%
41.5%
34.1%
32.2%
26.6%
23.1%
22.0%
21.2%
20.3%
19.0%
17.9%
17.6%
16.3%
15.3%
14.7%
14.0%
13.8%
13.5%
13.0%
12.8%
12.3%
12.2%
Median maximum
concentration in
hydraulic fracturing
fluid (% by mass)
30%
40%
100%
30%
15%
50%
10%
2%
67%
15%
15%
15%
5%
30%
10%
5%
25%
45%
60%
5%
5%
20%
100%
1%
1%
60%
2%
75%
30%
50%
1%
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-3 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Boric acid
Polyethylene glycol
2-Mercaptoethanol
2,2-Dibromo-3-nitrilopropionamide
Formic acid
Sodium persulfate
Phosphonicacid
Sodium tetraborate decahydrate
Potassium metaborate
Ethylenediaminetetraacetic acid tetrasodium
salt hydrate
Poly(oxy-l,2-ethanediyl)-nonylphenyl-hydroxy
(mixture)
CASRN
10043-35-3
25322-68-3
60-24-2
10222-01-2
64-18-6
7775-27-1
13598-36-2
1303-96-4
13709-94-9
64-02-8
127087-87-0
Number of
disclosures
2,070
2,025
2,012
1,988
1,948
1,914
1,865
1,862
1,682
1,676
1,668
Percentage of
disclosures
11.9%
11.7%
11.6%
11.4%
11.2%
11.0%
10.7%
10.7%
9.7%
9.6%
9.6%
Median maximum
concentration in
hydraulic fracturing
fluid (% by mass)
25%
5%
100%
98%
60%
100%
1%
30%
60%
0%
5%
Note: Analysis considered 17,640 disclosures and 385,013 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures that did not meet quality assurance criteria
(2,268) or other, query-specific criteria were excluded from analysis.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-4 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-3a. Top chemicals reported to FracFocus for each state and number (and percentage) of disclosures where a chemical is
reported for that state, Alabama to Montana (U.S. EPA, 2015c).
Source: (U1S._EPAt_2015c). The top 20 most frequent chemicals were identified for the 20 states that reported to FracFocus, resulting in a total of
93 chemicals. The chemicals were ranked by counting the number of states where that chemical was in the top 20; chemicals used most widely
among the most states come first. For example, methanol is reported in 19 of 20 states, so methanol is ranked first.
Chemical name
Methanol
Distillates, petroleum,
hydrotreated light
Ethylene glycol
Isopropanol
Quartz
Sodium hydroxide
Ethanol
Guargum
Hydrochloric acid
Peroxydisulfuric acid,
diammonium salt
CASRN
67-56-1
64742-47-8
107-21-1
67-63-0
14808-60-7
1310-73-2
64-17-5
9000-30-0
7647-01-0
7727-54-0
Alabama
55
(100%)
55
(100%)
55
(100%)
55
(100%)
Alaska
9
(45%)
20
(100%)
13
(65%)
20
(100%)
20
(100%)
10
(50%)
10
(50%)
Arkansas
1333
(99.7%)
743
(55.6%)
291
(21.8%)
586
(43.9%)
285
(21.3%)
603
(45.1%)
1330
(99.5%)
California
228
(39.0%)
322
(55.0%)
350
(59.8%)
519
(88.7%)
403
(68.9%)
545
(93.2%)
484
(82.7%)
Colorado
2883
(63.3%)
3358
(73.7%)
2586
(56.8%)
1048
(23.0%)
996
(21.9%)
2258
(49.6%)
2408
(52.9%)
Kansas
77
(79.4%)
87
(89.7%)
61
(62.9%)
24
(24.7%)
22
(22.7%)
27
(27.8%)
78
(80.4%)
82
(84.5%)
21
(21.6%)
Louisiana
596
(59.2%)
844
(83.9%)
341
(33.9%)
515
(51.2%)
377
(37.5%)
535
(53.2%)
420
(41.7%)
494
(49.1%)
569
(56.6%)
273
(27.2%)
Michigan
13
(92.9%)
14
(100%)
10
(71.4%)
11
(78.6%)
8
(57.1%)
Mississippi Montana
3
(75%)
4
(100%)
3
(75%)
2
(50%)
2
(50%)
4
(100%)
2
(50%)
121
(62.7%)
115
(59.6%)
95
(49.2%)
123
(63.7%)
124
(64.2%)
105
(54.4%)
83
(43.0%)
45
(23.3%)
119
(61.7%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-5 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Propargyl alcohol
Glutaraldehyde
Naphthalene
2-Butoxyethanol
Citric acid
Saline
Solvent naphtha,
petroleum, heavy arom.
Quaternary ammonium
compounds, benzyl-C12-
16-alkyldimethyl, chlorides
2,2-Dibromo-3-
nitrilopropionamide
Potassium hydroxide
Choline chloride
Polyethylene glycol
1,2,4-Trimethylbenzene
CASRN
107-19-7
111-30-8
91-20-3
111-76-2
77-92-9
7647-14-5
64742-94-5
68424-85-1
10222-01-2
1310-58-3
67-48-1
25322-68-3
95-63-6
Alabama
55
(100%)
55
(100%)
55
(100%)
55
(100%)
Alaska
20
(100%)
Arkansas
813
(60.8%)
737
(55.1%)
375
(28.0%)
California
Colorado
1363
(29.9%)
1574
(34.5%)
1507
(33.1%)
2215
(48.6%)
1235
(27.1%)
1211
(26.63%)
Kansas
69
(71.1%)
73
(75.3%)
41
(42.3%)
45
(46.4%)
42
(43.3%)
52
(53.6%)
39
(40.2%)
Louisiana
299
(29.7%)
364
(36.3%)
293
(29.2%)
408
(40.6%)
340
(33.8%)
Michigan
5
(35.7%)
12
(85.7%)
11
(78.6%)
10
(71.4%)
7
(50%)
Mississippi Montana
2
(50%)
2
(50%)
2
(50%)
4
(100%)
95
(49.2%)
135
(70.0%)
70
(36.3%)
115
(59.6%)
69
(35.8%)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-6 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Ammonium chloride
Diatomaceous earth,
calcined
Didecyl dimethyl
ammonium chloride
Sodium chlorite
Sodium erythorbate
N,N-Dimethylformamide
Nonyl phenol ethoxylate
Poly(oxy-l,2-
ethanediyl)-
nonylphenyl-hydroxy
(mixture)
Sodium persulfate
Tetramethylammonium
chloride
1,2-Propylene glycol
5-Chloro-2-methyl-3(2H)-
isothiazolone
Acetic acid
Ammonium acetate
CASRN
12125-02-9
91053-39-3
7173-51-5
7758-19-2
6381-77-7
68-12-2
9016-45-9
127087-87-
0
7775-27-1
75-57-0
57-55-6
26172-55-4
64-19-7
631-61-8
Alabama
Alaska
20
(100%)
20
(100%)
Arkansas
277
(20.7%)
317
(23.7%)
435
(32.5%)
California
417
(71.3%)
1150
(25.2%)
389
(66.5%)
Colorado
1280
(28.0%)
39
(40.2%)
959
(21.0%)
Kansas
29
(29.9%)
Louisiana
352
(35.0%)
284
(28.2%)
Michigan
10
(71.4%)
Mississippi Montana
2
(50%)
4
(100%)
4
(100%)
2
(50%)
85
(44.0%)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-7 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Boric acid
Carbonic acid, dipotassium
salt
Cristobalite
Formic acid
Hemicellulase enzyme
Hemicellulase enzyme
concentrate
Iron(ll) sulfate
heptahydrate
Magnesium chloride
Magnesium nitrate
Phenolic resin
Sodium hypochlorite
Sodium tetraborate
decahydrate
Solvent naphtha,
petroleum, heavy aliph.
l-Butoxy-2-propanol
CASRN
10043-35-3
584-08-7
14464-46-1
64-18-6
9012-54-8
9025-56-3
7782-63-0
7786-30-3
10377-60-3
9003-35-4
7681-52-9
1303-96-4
64742-96-7
5131-66-8
Alabama
55
(100%)
Alaska
3
(15%)
20
(100%)
20
(100%)
20
(100%)
14
(70%)
Arkansas
California
389
(66.5%)
395
(67.5%)
389
(66.5%)
389
(66.5%)
315
(53.8%)
Colorado
1159
(25.4%)
1046
(23.0%)
Kansas
Louisiana
293
(29.1%)
Michigan
7 (50%)
7
(50%)
Mississippi Montana
2
(50%)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-8 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
1-Propanol
1,2-Ethanediaminium, N,
N'-bis[2-[bis(2-hydroxyeth
yl)methylammonio]ethyl]-
N,N'bis(2-hydroxyethyl)-
N,N'-dimethyl-,tetrachl
oride
2-bromo-3-
nitrilopropionamide
2-Ethylhexanol
2-Methyl-3(2H)-
isothiazolone
2-Propenoic acid, polymer
with 2-propenamide
Alkenes, C>10 .alpha. -
Benzene, l,l'-oxybis-,
tetrapropylene derivs.,
sulfonated
Benzenesulfonic acid,
dodecyl-, compd. with Nl-
(2-aminoethyl)-l,2-
ethanediamine (1:?)
Benzyldimethyldodecylam
monium chloride
CASRN
71-23-8
138879-94-4
1113-55-9
104-76-7
2682-20-4
9003-06-9
64743-02-8
119345-03-8
40139-72-8
139-07-1
Alabama
Alaska
20
(100%)
Arkansas
343
(58.6%)
241
(18.0%)
268
(20.0%)
California
389
(66.5%)
Colorado
1232
(27.0%)
Kansas
Louisiana
Michigan
Mississippi Montana
83
(43.0052%
)
50
(25.9%)
48
(24.9%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-9 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Benzylhexadecyldimethyla
mmonium chloride
Boron sodium oxide
C10-C16 ethoxylated
alcohol
Calcium chloride
Carbon dioxide
Cinnamaldehyde (3-
phenyl-2-propenal)
Diethylene glycol
Diethylene glycol
monobutyl ether
Diethylenetriamine
Distillates, petroleum,
hydrotreated light
paraffinic
Distillates, petroleum,
hydrotreated middle
Ethoxylated C12-16
alcohols
Ethoxylated C14-15
alcohols
Formic acid, potassium
salt
CASRN
122-18-9
1330-43-4
68002-97-1
10043-52-4
124-38-9
104-55-2
111-46-6
112-34-5
111-40-0
64742-55-8
64742-46-7
68551-12-2
68951-67-7
590-29-4
Alabama
55
(100%)
Alaska
3
(15%)
20
(100%)
3
(15%)
Arkansas
268
(20.0%)
241
(18.0%)
California
361
(61.7%)
314
(53.7%)
Colorado
Kansas
Louisiana
Michigan
7
(50%)
7
(50%)
Mississippi Montana
55
(28.5%)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-10 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Glycerin, natural
Isotridecanol, ethoxylated
Methenamine
Naphtha, petroleum,
hydrotreated heavy
Poly(oxy-l,2-ethanediyl),
.alpha.,.alpha.'-[[(9Z)-9-
octadecenylimino]di-2,l-
ethanediyl]bis[. omega. -
hydroxy-
Potassium chloride
Sodium bromate
Sodium perborate
tetrahydrate
Sulfamicacid
Terpenes and Terpenoids,
sweet orange-oil
Tetradecyl dimethyl
benzyl ammonium
chloride
Tetrakis(hydroxymethyl)p
hosphonium sulfate
CASRN
56-81-5
9043-30-5
100-97-0
64742-48-9
26635-93-8
7447-40-7
7789-38-0
10486-00-7
5329-14-6
68647-72-3
139-08-2
55566-30-8
Alabama
Alaska
Arkansas
268
(20.0%)
California
312
(53.3%)
Colorado
Kansas
Louisiana
298
(29.6%)
Michigan
7
(50%)
9
(64.3%)
7
(50%)
7
(50%)
Mississippi Montana
2
(50%)
2
(50%)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-ll DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Thiourea polymer
Tri-n-butyl tetradecyl
phosphonium chloride
Trisodium phosphate
CASRN
68527-49-1
81741-28-8
7601-54-9
Alabama
Alaska
Arkansas
384
(28.7%)
California
Colorado
Kansas
19
(19.6%)
Louisiana
Michigan
Mississippi Montana
Note for Table C-3a and C-3b: Analysis considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria, including: completely parsed;
unique combination of fracture date and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures
that did not meet quality assurance criteria (3,855) or other, query-specific criteria were excluded from analysis.
Table C-3b. Top chemicals reported to FracFocus for each state and number (and percentage) of disclosures where a chemical is
reported for that state, New Mexico to Wyoming (U.S. EPA, 2015c).
Source: The top 20 most frequent chemicals were identified for the 20 states that reported to FracFocus, resulting in a total of
93 chemicals. The chemicals were ranked by counting the number of states where that chemical was in the top 20; chemicals used most widely
among the most states come first. For example, methanol is reported in 19 of 20 states, so methanol is ranked first.
Chemical name
Methanol
Distillates, petroleum,
hydrotreated light
Ethylene glycol
Isopropanol
CASRN
67-56-1
64742-47-8
107-21-1
67-63-0
New
Mexico
1012
(90.8%)
699
(62.7%)
503
(45.1%)
695
(62.3%)
North
Dakota
1059
(53.3%)
943
(47.5%)
724
(36.4%)
739
(37.2%)
Ohio
76
(52.1%)
122
(83.6%)
83
(56.8%)
71
(48.6%)
Oklahoma
1270
(70.3%)
1270
(70.3%)
843
(46.7%)
764
(42.28%)
Pennsylvania
1633
(68.6%)
1434
(60.2%)
807
(33.9%)
735
(30.9%)
Texas
12664
(78.5%)
10677
(66.1%)
9591
(59.4%)
7731
(47.9%)
Utah
984
(78.5%)
934
(74.5%)
1065
(85.0%)
661
(52.8%)
Virginia
48
(60.8%)
22
(27.8%)
43 (54.4%)
West
Virginia
153
(64.0%)
196
(82.0%)
141
(59.0%)
74
(31.0%)
Wyoming
460
(38.4%)
612
(51.1%)
516
(43.1%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-12 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Quartz
Sodium hydroxide
Ethanol
Guargum
Hydrochloric acid
Peroxydisulfuric acid,
diammonium salt
Propargyl alcohol
Glutaraldehyde
Naphthalene
2-Butoxyethanol
Citric acid
Saline
Solvent naphtha,
petroleum, heavy arom.
CASRN
14808-60-7
1310-73-2
64-17-5
9000-30-0
7647-01-0
7727-54-0
107-19-7
111-30-8
91-20-3
111-76-2
77-92-9
7647-14-5
64742-94-5
New
Mexico
762
(68.3%)
329
(29.5%)
529
(47.4%)
702
(63.0%)
880
(78.9%)
836
(75.0%)
760
(68.2%)
632
(56.7%)
412
(37.0%)
447
(40.1%)
North
Dakota
920
(46.3%)
1028
(51.7%)
545
(27.4%)
1094
(55.1%)
1089
(54.8%)
864
(43.5%)
491
(24.7%)
981
(49.4%)
Ohio
66
(45.2%)
87
(59.6%)
74
(50.7%)
145
(99.3%)
93
(63.7%)
72
(49.3%)
105
(71.9%)
96
(65.8%)
Oklahoma
491
(27.2%)
490
(27.1%)
838
(46.4%)
457
(25.3%)
1372
(75.9%)
713
(39.5%)
732
(40.5%)
989
(54.7%)
448
(24.8%)
644
(35.6%)
557
(30.8%)
Pennsylvania
406
(17.0%)
388
(16.3%)
538
(22.6%)
2279
(95.7%)
1371
(57.6%)
819
(34.4%)
498
(20.9%)
701
(29.4%)
Texas
6869
(42.6%)
7371
(45.7%)
3439
(21.3%)
6863
(42.5%)
11424
(70.8%)
8666
(53.7%)
6269
(38.8%)
6470
(40.1%)
3898
(24.1%)
3820
(23.7%)
3462
(21.4%)
2751
(17.0%)
Utah
503
(40.1%)
466
(37.2%)
538
(42.9%)
1064
(84.9%)
483
(38.5%)
456
(36.4%)
478
(38.1%)
663
(52.9%)
992
(79.2%)
Virginia
50
(63.3%)
68
(86.1%)
22
(27.8%)
7
(8.9%)
70
(88.6%)
63
(79.8%)
7
(8.9%)
7
(8.9%)
West
Virginia
53
(22.2%)
130
(54.3%)
55
(23.0%)
229
(95.8%)
128
(53.6%)
138
(57.7%)
169
(70.7%)
62
(25.9%)
98
(41.0%)
53
(22.2%)
Wyoming
356
(29.7%)
688
(57.4%)
298
(24.9%)
823
(68.7%)
771
(64.4%)
260
(21.7%)
274
(22.9%)
415
(34.6%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-13 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Quaternary ammonium
compounds, benzyl-C12-
16-alkyldimethyl, chlorides
2,2-Dibromo-3-
nitrilopropionamide
Potassium hydroxide
Choline chloride
Polyethylene glycol
1,2,4-Trimethylbenzene
Ammonium chloride
Diatomaceous earth,
calcined
Didecyl dimethyl
ammonium chloride
Sodium chlorite
Sodium erythorbate
N,N-Dimethylformamide
Nonyl phenol ethoxylate
CASRN
68424-85-1
10222-01-2
1310-58-3
67-48-1
25322-68-3
95-63-6
12125-02-9
91053-39-3
7173-51-5
7758-19-2
6381-77-7
68-12-2
9016-45-9
New
Mexico
384
(34.4%)
419
(37.6%)
333
(29.9%)
North
Dakota
1176
(59.2%)
567
(28.5%)
496
(25.0%)
482
(24.3%)
Ohio
54
(37.0%)
106
(72.6%)
55
(37.7%)
46
(31.6%)
68
(46.6%)
Oklahoma
597
(33.0%)
355
(19.6%)
Pennsylvania
373
(15.7%)
804
(33.8%)
688
(28.9%)
732
(30.7%)
Texas
6369
(39.5%)
Utah
649
(51.8%)
435
(34.7%)
410
(32.7%)
447
(35.7%)
Virginia
22
(27.8%)
45
(57.0%)
7
(8.9%)
10
(12.7%)
25
(31.6%)
West
Virginia
53
(22.2%)
50
(20.9%)
49
(20.5%)
76
(31.8%)
Wyoming
271
(22.6%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-14 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Poly(oxy-l,2-ethanediyl)-
nonylphenyl-hydroxy
(mixture)
Sodium persulfate
Tetramethylammonium
chloride
1,2-Propylene glycol
5-Chloro-2-methyl-3(2H)-
isothiazolone
Acetic acid
Ammonium acetate
Boric acid
Carbonic acid, dipotassium
salt
Cristobalite
Formic acid
Hemicellulase enzyme
Hemicellulase enzyme
concentrate
Iron(ll) sulfate
heptahydrate
Magnesium chloride
CASRN
127087-87-0
7775-27-1
75-57-0
57-55-6
26172-55-4
64-19-7
631-61-8
10043-35-3
584-08-7
14464-46-1
64-18-6
9012-54-8
9025-56-3
7782-63-0
7786-30-3
New
Mexico
331
(29.7%)
North
Dakota
579
(29.1%)
482
(24.2%)
Ohio
82
(56.2%)
Oklahoma
Pennsylvania
373
(15.7%)
367
(15.4%)
Texas
Utah
Virginia
7
(8.9%)
22
(27.8%)
11
(13.9%)
22
(27.8%)
West
Virginia
Wyoming
308
(25.7%)
315
(26.3%)
323
(27.0%)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-15 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Magnesium nitrate
Phenolic resin
Sodium hypochlorite
Sodium tetraborate
decahydrate
Solvent naphtha,
petroleum, heavy aliph.
l-Butoxy-2-propanol
1-Propanol
1,2-Ethanediaminium, N,
N'-bis[2-[bis(2-hydroxy
ethyl) methylammonio]
ethyl]-N,N'bis(2-
hydroxyethyl)-N,N'-
dimethyl-, tetrachloride
2-Bromo-3-
nitrilopropionamide
2-Ethylhexanol
2-Methyl-3(2H)-
isothiazolone
2-Propenoic acid, polymer
with 2-propenamide
Alkenes, C>10 .alpha. -
CASRN
10377-60-3
9003-35-4
7681-52-9
1303-96-4
64742-96-7
5131-66-8
71-23-8
138879-94-4
1113-55-9
104-76-7
2682-20-4
9003-06-9
64743-02-8
New
Mexico
419
(37.6%)
North
Dakota
Ohio
Oklahoma
Pennsylvania
Texas
2903
(18.0%)
Utah
486
(38.8%)
Virginia
11
(13.9%)
West
Virginia
Wyoming
282
(23.5%)
265
(22.1%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-16 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Benzene, l,l'-oxybis-,
tetrapropylene derivs.,
sulfonated
Benzenesulfonic acid,
dodecyl-, compd. with Nl-
(2-aminoethyl)-l,2-
ethanediamine (1:?)
Benzyldimethyldodecylam
monium chloride
Benzylhexadecyldimethyla
mmonium chloride
Boron sodium oxide
C10-C16 ethoxylated
alcohol
Calcium chloride
Carbon dioxide
Cinnamaldehyde (3-
phenyl-2-propenal)
Diethylene glycol
Diethylene glycol
monobutyl ether
Diethylenetriamine
Distillates, petroleum,
hydrotreated light
paraffinic
CASRN
119345-03-8
40139-72-8
139-07-1
122-18-9
1330-43-4
68002-97-1
10043-52-4
124-38-9
104-55-2
111-46-6
112-34-5
111-40-0
64742-55-8
New
Mexico
North
Dakota
Ohio
45
(30.8%)
Oklahoma
Pennsylvania
Texas
Utah
Virginia
West
Virginia
Wyoming
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-17 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Distillates, petroleum,
hydrotreated middle
Ethoxylated C12-16
alcohols
Ethoxylated C14-15
alcohols
Formic acid, potassium
salt
Glycerin, natural
Isotridecanol, ethoxylated
Methenamine
Naphtha, petroleum,
hydrotreated heavy
Poly(oxy-l,2-ethanediyl),
.alpha.,.alpha.'-[[(9Z)-9-
octadecenylimino]di-2,l-
ethanediyl]bis[. omega. -
hydroxy-
Potassium chloride
Sodium bromate
Sodium perborate
tetrahydrate
Sulfamicacid
Terpenes and terpenoids,
sweet orange-oil
CASRN
64742-46-7
68551-12-2
68951-67-7
590-29-4
56-81-5
9043-30-5
100-97-0
64742-48-9
26635-93-8
7447-40-7
7789-38-0
10486-00-7
5329-14-6
68647-72-3
New
Mexico
North
Dakota
Ohio
Oklahoma
351
(19.4%)
Pennsylvania
Texas
Utah
Virginia
West
Virginia
57
(23.8%)
Wyoming
361
(30.1%)
384
(32.1%)
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-18 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Tetradecyl dimethyl
benzyl ammonium
chloride
Tetrakis(hydroxymethyl)p
hosphonium sulfate
Thiourea polymer
Tri-n-butyl tetradecyl
phosphonium chloride
Trisodium phosphate
CASRN
139-08-2
55566-30-8
68527-49-1
81741-28-8
7601-54-9
New
Mexico
North
Dakota
Ohio
Oklahoma
Pennsylvania
350
(14.7%)
Texas
Utah
945
(75.4%)
Virginia
West
Virginia
Wyoming
Note for Table C-3a and C-3b: Analysis considered 34,675 disclosures and 676,376 ingredient records that met selected quality assurance criteria, including: completely parsed;
unique combination of fracture date and API well number; fracture date between January 1, 2011, and February 28, 2013; valid CASRN; and valid concentrations. Disclosures
that did not meet quality assurance criteria (3,855) or other, query-specific criteria were excluded from analysis.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-19 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-4. Estimated mean, median, 5th percentile, and 95th percentile volumes in gallons for
chemicals reported to FracFocus in 100 or more disclosures, where density
information was available.
Chemicals are listed in alphabetical order. Density information came from Reaxys® and other sources.
All density sources are referenced in Table C-7.
Name
(4R)-l-methyl-4-(prop-l-en-2-
yl)cyclohexene
l-Butoxy-2-propanol
1-Decanol
1-Octanol
1-Propanol
1,2-Propylene glycol
1,2,4-Trimethylbenzene
2-Butoxyethanol
2-Ethylhexanol
2-Mercaptoethanol
2,2-Dibromo-3-nitrilopropionamide
Acetic acid
Acetic anhydride
Acrylamide
Adipicacid
Aluminum chloride
Ammonia
Ammonium acetate
Ammonium chloride
Ammonium hydroxide
Benzyl chloride
Carbonic acid, dipotassium salt
Chlorine dioxide
Choline chloride
Cinnamaldehyde (3-phenyl-2-propenal)
CASRN
5989-27-5
5131-66-8
112-30-1
111-87-5
71-23-8
57-55-6
95-63-6
111-76-2
104-76-7
60-24-2
10222-01-2
64-19-7
108-24-7
79-06-1
124-04-9
7446-70-0
7664-41-7
631-61-8
12125-02-9
1336-21-6
100-44-7
584-08-7
10049-04-4
67-48-1
104-55-2
Volume (gallons)
Mean
2,702
167
28
5
128
13,105
38
385
100
1,175
183
646
239
95
153
2
44
839
440
7
52
467
31
2,131
68
Median
406
21
4
4
55
72
6
26
11
445
5
47
50
3
0
0
35
117
48
2
0
113
11
290
3
5th
Percentile
0
5
0
0
6
4
0
0
0
0
0
0
3
0
0
0
2
0
3
0
0
0
0
28
0
95th
Percentile
19,741
654
33
10
367
61,071
43
1,811
292
4,194
341
1,042
722
57
109
0
138
1,384
458
14
40
1,729
28
4,364
697
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-20 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Citric acid
Dibromoacetonitrile
Diethylene glycol
Diethylenetriamine
Dodecane
Ethanol
Ethanolamine
Ethyl acetate
Ethylene glycol
Ferric chloride
Formalin
Formic acid
Fumaric acid
Glutaraldehyde
Glycerin, natural
Glycolicacid
Hydrochloric acid
Isopropanol
Isopropylamine
Magnesium chloride
Methanol
Methenamine
Methoxyacetic acid
N,N-Dimethylformamide
Naphthalene
Nitrogen, liquid
Ozone
Peracetic acid
Phosphonic acid
Phosphoric acid Divosan X-Tend
formulation
Potassium acetate
CASRN
77-92-9
3252-43-5
111-46-6
111-40-0
112-40-3
64-17-5
141-43-5
141-78-6
107-21-1
7705-08-0
50-00-0
64-18-6
110-17-8
111-30-8
56-81-5
79-14-1
7647-01-0
67-63-0
75-31-0
7786-30-3
67-56-1
100-97-0
625-45-6
68-12-2
91-20-3
7727-37-9
10028-15-6
79-21-0
13598-36-2
7664-38-2
127-08-2
Volume (gallons)
Mean
163
22
168
92
190
831
70
0
614
0
200
501
2
1,313
413
38
28,320
2,095
83
14
1,218
3,386
36
119
72
41,841
15,844
300
1,201
13
204
Median
20
13
16
21
31
121
30
0
184
0
0
38
0
122
109
10
3,110
55
121
0
110
100
4
10
12
26,610
15,473
268
0
4
1
5th
Percentile
1
1
0
0
0
1
0
0
4
0
0
1
0
2
10
4
96
0
0
0
2
0
2
0
0
3,091
8,785
50
0
0
0
95th
Percentile
269
45
102
207
151
2,645
283
0
2,470
0
8
1,229
12
1,165
911
94
26,877
1,264
172
2
3,731
3,648
115
216
204
108,200
26,063
663
3
15
974
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-21 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Propargyl alcohol
Saline
Saturated sucrose
Silica, amorphous
Sodium carbonate
Sodium formate
Sodium hydroxide
Sulfur dioxide
Sulfuricacid
tert-Butyl hydroperoxide (70% solution in
Water)
Tetramethylammonium chloride
Thioglycolic acid
Toluene
Tridecane
Triethanolamine
Triethyl phosphate
Triethylene glycol
Triisopropanolamine
Trimethyl borate
Undecane
CASRN
107-19-7
7647-14-5
57-50-1
7631-86-9
497-19-8
141-53-7
1310-73-2
7446-09-5
7664-93-9
75-91-2
75-57-0
68-11-1
108-88-3
629-50-5
102-71-6
78-40-0
112-27-6
122-20-3
121-43-7
1120-21-4
Volume (gallons)
Mean
183
876
1
6,877
228
0
551
0
3
156
970
55
18
190
846
55
5,198
46
83
273
Median
2
85
1
8
16
0
38
0
0
64
483
7
0
31
60
1
116
4
40
29
5th
Percentile
0
0
0
0
0
0
0
0
0
0
2
2
0
0
0
0
28
1
4
0
95th
Percentile
51
1,544
2
38,371
1,319
0
1,327
0
3
557
3,508
229
11
190
2,264
533
945
330
283
1,641
Note: Analysis considered 34,495 disclosures and 672,358 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; criteria for water volumes; valid CASRN; and valid concentrations. Disclosures that did not meet
quality assurance criteria (4,035) or other, query-specific criteria were excluded from analysis.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-22 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-5. Estimated mean, median, 5th percentile, and 95th percentile volumes in liters for
chemicals reported to FracFocus in 100 or more disclosures, where density
information was available.
Chemicals are listed in alphabetical order. Density information came from Reaxys® and other sources.
All density sources are referenced in Table C-7.
Name
(4R)-l-methyl-4-(prop-l-en-2-
yl)cyclohexene
l-Butoxy-2-propanol
1-Decanol
1-Octanol
1-Propanol
1,2-Propylene glycol
1,2,4-Trimethylbenzene
2-Butoxyethanol
2-Ethylhexanol
2-Mercaptoethanol
2,2-Dibromo-3-nitrilopropionamide
Acetic acid
Acetic anhydride
Acrylamide
Adipicacid
Aluminum chloride
Ammonia
Ammonium acetate
Ammonium chloride
Ammonium hydroxide
Benzyl chloride
Carbonic acid, dipotassium salt
Chlorine dioxide
Choline chloride
Cinnamaldehyde (3-phenyl-2-propenal)
Citric acid
CASRN
5989-27-5
5131-66-8
112-30-1
111-87-5
71-23-8
57-55-6
95-63-6
111-76-2
104-76-7
60-24-2
10222-01-2
64-19-7
108-24-7
79-06-1
124-04-9
7446-70-0
7664-41-7
631-61-8
12125-02-9
1336-21-6
100-44-7
584-08-7
10049-04-4
67-48-1
104-55-2
77-92-9
Volume (L)
Mean
10,229
631
107
21
483
49,607
145
1,459
377
4,449
692
2,446
906
361
578
6
166
3,177
1,666
27
196
1,769
117
8,068
258
618
Median
1,536
80
14
14
208
274
24
98
40
1,685
18
176
189
10
0
0
134
444
182
6
1
429
43
1,096
12
77
5th
Percentile
0
18
1
1
22
15
0
0
1
0
0
0
12
0
0
0
7
0
11
1
0
0
1
107
0
5
95th
Percentile
74,729
2,475
123
39
1,391
231,179
165
6,856
1,106
15,878
1,292
3,945
2,734
216
414
0
523
5,238
1,733
52
151
6,544
106
16,521
2,638
1,019
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-23 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Dibromoacetonitrile
Diethylene glycol
Diethylenetriamine
Dodecane
Ethanol
Ethanolamine
Ethyl acetate
Ethylene glycol
Ferric chloride
Formalin
Formic acid
Fumaricacid
Glutaraldehyde
Glycerin, natural
Glycolic acid
Hydrochloric acid
Isopropanol
Isopropylamine
Magnesium chloride
Methanol
Methenamine
Methoxyacetic acid
N,N-Dimethylformamide
Naphthalene
Nitrogen, liquid
Ozone
Peracetic acid
Phosphonicacid
Phosphoric acid Divosan X-Tend
formulation
Potassium acetate
Propargyl alcohol
CASRN
3252-43-5
111-46-6
111-40-0
112-40-3
64-17-5
141-43-5
141-78-6
107-21-1
7705-08-0
50-00-0
64-18-6
110-17-8
111-30-8
56-81-5
79-14-1
7647-01-0
67-63-0
75-31-0
7786-30-3
67-56-1
100-97-0
625-45-6
68-12-2
91-20-3
7727-37-9
10028-15-6
79-21-0
13598-36-2
7664-38-2
127-08-2
107-19-7
Volume (L)
Mean
82
636
347
719
3,144
264
0
2,324
0
756
1,896
9
4,972
1,565
146
107,204
7,932
314
52
4,609
12,817
136
449
271
158,384
59,976
1,137
4,547
51
775
693
Median
50
61
80
117
458
112
0
697
0
2
144
0
462
412
39
11,772
210
458
0
416
378
17
38
44
100,731
58,570
1,016
2
15
3
9
5th
Percentile
4
1
0
0
6
0
0
14
0
0
2
0
6
38
14
362
1
0
0
6
0
8
2
0
11,700
33,254
190
0
0
0
0
95th
Percentile
170
384
785
572
10,011
1,070
0
9,349
0
31
4,653
46
4,409
3,447
356
101,741
4,786
652
8
14,125
13,810
436
819
774
409,583
98,658
2,511
11
57
3,690
193
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-24 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Saline
Saturated sucrose
Silica, amorphous
Sodium carbonate
Sodium formate
Sodium hydroxide
Sulfur dioxide
Sulfuric acid
tert-Butyl hydroperoxide (70% solution in
Water)
Tetramethylammonium chloride
Thioglycolicacid
Toluene
Tridecane
Triethanolamine
Triethyl phosphate
Triethylene glycol
Triisopropanolamine
Trimethyl borate
Undecane
CASRN
7647-14-5
57-50-1
7631-86-9
497-19-8
141-53-7
1310-73-2
7446-09-5
7664-93-9
75-91-2
75-57-0
68-11-1
108-88-3
629-50-5
102-71-6
78-40-0
112-27-6
122-20-3
121-43-7
1120-21-4
Volume (L)
Mean
3,317
5
26,031
862
1
2,087
2
10
591
3,672
208
69
721
3,203
209
19,676
174
314
1,035
Median
321
2
32
62
1
144
0
0
242
1,830
28
0
118
228
6
439
16
152
111
5th
Percentile
0
0
0
0
0
1
0
0
0
8
6
0
0
0
0
106
4
16
0
95th
Percentile
5,844
6
145,251
4,991
1
5,024
0
12
2,109
13,279
868
41
721
8,570
2,019
3,579
1,249
1,072
6,212
Note: Analysis considered 34,495 disclosures and 672,358 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; criteria for water volumes; valid CASRN; and valid concentrations. Disclosures that did not meet
quality assurance criteria (4,035) or other, query-specific criteria were excluded from analysis.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-25 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-6. Calculated mean, median, 5th percentile, and 95th percentile chemical masses
reported to FracFocus in 100 or more disclosures, where density information was
available.
Density information came from Reaxys® and other sources. All density sources are referenced in Table
C-7. Number of disclosures reported for each chemical is also included.
Name
(4R)-l-methyl-4-(prop-l-en-2-
yl)cyclohexene
l-Butoxy-2-propanol
1-Decanol
1-Octanol
1-Propanol
1,2-Propylene glycol
1,2,4-Trimethylbenzene
2-Butoxyethanol
2-Ethylhexanol
2-Mercaptoethanol
2,2-Dibromo-3-
nitrilopropionamide
Acetic acid
Acetic anhydride
Acrylamide
Adipic acid
Aluminum chloride
Ammonia
Ammonium acetate
Ammonium chloride
Ammonium hydroxide
Benzyl chloride
Carbonic acid, dipotassium salt
Chlorine dioxide
Choline chloride
Cinnamaldehyde (3-phenyl-2-
propenal)
CASRN
5989-27-5
5131-66-8
112-30-1
111-87-5
71-23-8
57-55-6
95-63-6
111-76-2
104-76-7
60-24-2
10222-01-2
64-19-7
108-24-7
79-06-1
124-04-9
7446-70-0
7664-41-7
631-61-8
12125-02-9
1336-21-6
100-44-7
584-08-7
10049-04-4
67-48-1
104-55-2
Mass (kg)
Mean
8,593
555
89
17
386
51,095
126
1,313
313
489
1,660
2,544
969
408
785
15
111
3,718
2,530
48
214
4,298
321
9,440
284
Median
1,290
71
12
12
167
282
21
88
34
185
44
183
203
11
0
0
90
520
277
11
1
1,042
117
1,282
13
5th
Percentile
0
16
1
1
18
15
0
0
0
0
0
0
12
0
0
0
4
0
16
2
0
0
3
125
0
95th
Percentile
62,772
2,178
102
32
1,113
238,114
143
6,170
918
1,747
3,102
4,103
2,925
244
564
0
351
6,129
2,633
94
165
15,902
291
19,329
2,902
Disclosures
578
773
434
434
1,481
1,023
3,976
6,778
1,291
2,051
4,927
7,643
1,377
251
233
122
398
1,504
3,288
1,173
1,833
4,093
331
4,241
1,377
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-26 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Citric acid
Dibromoacetonitrile
Diethylene glycol
Diethylenetriamine
Dodecane
Ethanol
Ethanolamine
Ethyl acetate
Ethylene glycol
Ferric chloride
Formalin
Formic acid
Fumaricacid
Glutaraldehyde
Glycerin, natural
Glycolic acid
Hydrochloric acid
Isopropanol
Isopropylamine
Magnesium chloride
Methanol
Methenamine
Methoxyacetic acid
N,N-Dimethylformamide
Naphthalene
Nitrogen, liquid
Ozone
Peracetic acid
Phosphonicacid
Phosphoric acid Divosan X-Tend
formulation
Potassium acetate
CASRN
77-92-9
3252-43-5
111-46-6
111-40-0
112-40-3
64-17-5
141-43-5
141-78-6
107-21-1
7705-08-0
50-00-0
64-18-6
110-17-8
111-30-8
56-81-5
79-14-1
7647-01-0
67-63-0
75-31-0
7786-30-3
67-56-1
100-97-0
625-45-6
68-12-2
91-20-3
7727-37-9
10028-15-6
79-21-0
13598-36-2
7664-38-2
127-08-2
Mass (kg)
Mean
989
193
712
330
539
2,484
267
0
2,557
0
816
2,313
15
4,972
1,972
217
107,204
6,187
213
120
3,641
15,380
161
422
220
129,875
129
1,251
7,730
48
1,216
Median
123
118
68
76
88
361
113
0
767
0
2
176
0
462
519
58
11,772
163
311
1
329
454
20
36
35
82,599
126
1,117
3
14
5
5th
Percentile
8
11
1
0
0
4
0
0
15
0
0
2
0
6
47
21
362
1
0
0
5
0
9
2
0
9,594
71
209
0
0
0
95th
Percentile
1,630
403
430
746
429
7,908
1,081
0
10,283
0
34
5,677
75
4,409
4,343
530
101,741
3,733
444
18
11,159
16,572
514
770
627
335,858
212
2,762
18
54
5,793
Disclosures
7,503
272
1,732
784
131
9,233
585
110
14,767
118
456
3,781
224
10,963
1,829
595
20,996
15,058
255
1,113
23,225
4,412
584
2,972
5,945
713
209
221
2,216
315
325
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Propargyl alcohol
Saline
Saturated sucrose
Silica, amorphous
Sodium carbonate
Sodium formate
Sodium hydroxide
Sulfur dioxide
Sulfuric acid
tert-Butyl hydroperoxide
(70% solution in water)
Tetramethylammonium chloride
Thioglycolicacid
Toluene
Tridecane
Triethanolamine
Triethyl phosphate
Triethylene glycol
Triisopropanolamine
Trimethyl borate
Undecane
CASRN
107-19-7
7647-14-5
57-50-1
7631-86-9
497-19-8
141-53-7
1310-73-2
7446-09-5
7664-93-9
75-91-2
75-57-0
68-11-1
108-88-3
629-50-5
102-71-6
78-40-0
112-27-6
122-20-3
121-43-7
1120-21-4
Mass (kg)
Mean
658
7,197
6
57,267
2,191
2
4,445
2
18
532
4,296
277
59
541
3,588
222
22,038
177
292
766
Median
9
696
2
71
158
1
306
0
0
218
2,141
37
0
88
255
6
491
17
141
82
5th
Percentile
0
0
0
0
0
1
2
0
0
0
10
8
0
0
0
0
119
4
14
0
95th
Percentile
183
12,682
7
319,553
12,678
2
10,701
0
22
1,898
15,537
1,155
35
541
9,599
2,140
4,008
1,274
997
4,597
Disclosures
10,771
6,673
125
2,423
396
204
12,585
224
402
814
3,162
156
214
132
1,498
991
528
251
294
241
Note: Analysis considered 34,495 disclosures and 672,358 ingredient records that met selected quality assurance criteria,
including: completely parsed; unique combination of fracture date and API well number; fracture date between January 1,
2011, and February 28, 2013; criteria for water volumes; valid CASRN; and valid concentrations. Disclosures that did not meet
quality assurance criteria (4,035) or other, query-specific criteria were excluded from analysis.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-7. Associated chemical densities and references used to calculate chemical mass and
estimate chemical volume.
Name
(4R)-l-methyl-4-(prop-l-en-2-yl)cyclohexene
l-Butoxy-2-propanol
1-Decanol
1-Octanol
1-Propanol
1,2-Propylene glycol
1,2,4-Trimethylbenzene
2-Butoxyethanol
2-Ethylhexanol
2-Mercaptoethanol
2,2-Dibromo-3-nitrilopropionamide
Acetic acid
Acetic anhydride
Acrylamide
Adipicacid
Aluminum chloride
Ammonia
Ammonium acetate
Ammonium chloride
Ammonium hydroxide
Benzyl chloride
Carbonic acid, dipotassium salt
Chlorine dioxide
Choline chloride
Cinnamaldehyde (3-phenyl-2-propenal)
Citric acid
Dibromoacetonitrile
Diethylene glycol
Diethylenetriamine
Dodecane
CASRN
5989-27-5
5131-66-8
112-30-1
111-87-5
71-23-8
57-55-6
95-63-6
111-76-2
104-76-7
60-24-2
10222-01-2
64-19-7
108-24-7
79-06-1
124-04-9
7446-70-0
7664-41-7
631-61-8
12125-02-9
1336-21-6
100-44-7
584-08-7
10049-04-4
67-48-1
104-55-2
77-92-9
3252-43-5
111-46-6
111-40-0
112-40-3
Density
(g/mL)
0.84
0.88
0.83
0.82
0.8
1.03
0.87
0.9
0.83
0.11
2.4
1.04
1.07
1.13
1.36
2.44
0.67
1.17
1.519
1.8
1.09
2.43
2.757
1.17
1.1
1.6
2.37
1.12
0.95
0.75
Reference
DejoyeTanzi et al. (2012)
Pal etal. (2013)
Faria et al. (2013)
Dubey and Kumar (2013)
Rani and Maken (2013)
Moosavi etal. (2013)
He etal. (2008)
Dhondgeetal. (2010)
Laavi et al. (2012)
Rawatetal. (1976)
Pels (1900)
Chafer et al. (2010)
Radwan and Hanna (1976)
Carpenter and Davis (1957)
Thalladi etal. (2000)
Sigma-Aldrich (2015a)
Harlow etal. (1997)
Biltz and Balz (1928)
Haynes (2014)
Xiao et al. (2013)
Sarkar etal. (2012)
Sigma-Aldrich (2014b)
Haynes (2014)
Shanley and Collin (1961)
Masood etal. (1976)
Bennett and Yuill (1935)
Wilt (1956)
Chasib (2013)
Dubey and Kumar (2011)
Baragietal. (2013)
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Ethanol
Ethanolamine
Ethyl acetate
Ethylene glycol
Ferric chloride
Formalin
Formic acid
Fumaric acid
Glutaraldehyde
Glycerin, natural
Glycolicacid
Hydrochloric acid
Isopropanol
Isopropylamine
Magnesium chloride
Methanol
Methenamine
Methoxyacetic acid
N,N-Dimethylformamide
Naphthalene
Nitrogen, liquid
Ozone
Peracetic acid
Phosphonic acid
Phosphoric acid Divosan X-Tend formulation
Potassium acetate
Propargyl alcohol
Saline
Saturated sucrose
Silica, amorphous
Sodium carbonate
Sodium formate
CASRN
64-17-5
141-43-5
141-78-6
107-21-1
7705-08-0
50-00-0
64-18-6
110-17-8
111-30-8
56-81-5
79-14-1
7647-01-0
67-63-0
75-31-0
7786-30-3
67-56-1
100-97-0
625-45-6
68-12-2
91-20-3
7727-37-9
10028-15-6
79-21-0
13598-36-2
7664-38-2
127-08-2
107-19-7
7647-14-5
57-50-1
7631-86-9
497-19-8
141-53-7
Density
(g/mL)
0.79
1.01
0.89
1.1
2.9
1.08
1.22
1.64
1
1.26
1.49
1
0.78
0.68
2.32
0.79
1.2
1.18
0.94
0.81
0.8
0.002144
1.1
1.7
0.94
1.57
0.95
2.17
1.13
2.2
2.54
1.97
Reference
Kiselevetal. (2012)
Blanco et al. (2013)
Laavi et al. (2013)
Rodnikova et al. (2012)
Haynes (2014)
Alfa Aesar (2015)
Casanova etal. (1981)
Huffman and Fox (1938)
Oka (1962)
Egorovetal. (2013)
Pijper(1971)
Steinhauseretal. (1990)
Zhang etal. (2013)
Sarkar and Roy (2009)
Haynes (2014)
Kiselevetal. (2012)
Mak(1965)
Haynes (2014)
Smirnovand Badelin (2013)
Dyshin et al. (2008)
finemech (2012)
Haynes (2014)
Sigma-Aldrich (2015b)
Sigma-Aldrich (2014a)
Fadeeva et al. (2004)
Haynes (2014)
Vijaya Kumar etal. (1996)
Sigma-Aldrich (2010)
Hagen and Kaatze (2004)
Fuiinoetal. (2004)
Haynes (2014)
Fuess etal. (1982)
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Name
Sodium hydroxide
Sulfur dioxide
Sulfuric acid
tert-Butyl hydroperoxide
(70% solution in water)
Tetramethylammonium chloride
Thioglycolicacid
Toluene
Tridecane
Triethanolamine
Triethyl phosphate
Triethylene glycol
Triisopropanolamine
Trimethyl borate
Undecane
CASRN
1310-73-2
7446-09-5
7664-93-9
75-91-2
75-57-0
68-11-1
108-88-3
629-50-5
102-71-6
78-40-0
112-27-6
122-20-3
121-43-7
1120-21-4
Density
(g/mL)
2.13
1.3
1.83
0.9
1.17
1.33
0.86
0.75
1.12
1.06
1.12
1.02
0.93
0.74
Reference
Haynes (2014)
Sigma-Aldrich (2015c)
Sigma-Aldrich (2015d)
Sigma-Aldrich (2007)
Haynes (2014)
Biilmann (1906)
Martinez-Reina et al. (2012)
Zhang etal. (2011)
Blanco et al. (2013)
Krakowiak et al. (2001)
Afzal et al. (2009)
IUPAC(2014)
Sigma-Aldrich (2015e)
deOliveiraetal. (2011)
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Table C-8. Selected physicochemical properties of chemicals reported as used in hydraulic fracturing fluids.
Properties are provided for chemicals, where available from EPI Suite™ version 4.1 (UA
Chemical name
(13Z)-N,N-bis(2-hydroxyethyl)-N-
methyldocos-13-en-l-a minium chloride
(2,3-Dihydroxypropyl)trimethyl
ammonium chloride
(E)-Crotonaldehyde
[Nitrilotris(methylene)]tris-phosphonic
acid pentasodium salt
l-(l-Naphthylmethyl)quinolinium
chloride
l-(Alkyl* amino)-3-aminopropane
*(42%C12, 26%C18, 15%C14, 8%C16,
5%C10, 4%C8)
l-(Phenylmethyl)pyridinium Et Me
derivatives, chlorides
CASRN
120086-58-0
34004-36-9
123-73-9
2235-43-0
65322-65-8
68155-37-3
68909-18-2
Log Kow
Estimated
4.38
-5.8
0.6
-5.45
5.57
4.74
4.1
Measured
-
-
-
-3.53
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
0.3827
1.00 x 10s
4.15xl04
1.00 x 10s
0.02454
23.71
14.13
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
3.32 x ID"15
9.84 x 1Q-18
5.61 x 1Q-5
1.65 x 1Q-34
1.16xlQ-7
6.81 x 1Q-8
1.78 x 1Q-5
Group
method 25
-
-
1.90 x ID"5
-
-
2.39 x ID"8
-
Measured
-
-
1.94 x ID"5
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-32 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
1,2,3-Trimethylbenzene
1,2,4-Trimethylbenzene
l,2-Benzisothiazolin-3-one
l,2-Dibromo-2,4-dicyanobutane
1,2-Dimethylbenzene
1,2-Ethanediaminium, N,N'-bis[2-[bis(2-
hydroxyethyl)methylammonio]ethyl]-
N,N'-bis(2-hydroxyethyl)-N,N'-dimethyl-,
tetrachloride
1,2-Propylene glycol
1,2-Propylene oxide
1,3,5-Triazine
l,3,5-Triazine-l,3,5(2H,4H,6H)-triethanol
CASRN
526-73-8
95-63-6
2634-33-5
35691-65-7
95-47-6
138879-94-4
57-55-6
75-56-9
290-87-9
4719-04-4
Log Kow
Estimated
3.63
3.63
0.64
1.63
3.09
-23.19
-0.78
0.37
-0.2
-4.67
Measured
3.66
3.63
-
-
3.12
-
-0.92
0.03
0.12
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
75.03
79.59
2.14xl04
424
224.1
1.00 x 10s
S.llxlO5
1.29 x 105
1.03 x 105
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
7.24 x ID"3
7.24 x 1Q-3
6.92 x 1Q-9
3.94 x ID"10
6.56 x 1Q-3
2.33 x 1Q-35
1.74 x ID"7
1.60 x ID"4
1.21 x 1Q-6
1.08 x 1Q-11
Group
method 25
6.58 x ID"3
6.58 x ID"3
-
-
6.14xlQ-3
-
1.31 x ID"10
1.23 x ID"4
-
-
Measured
4.36 x ID"3
6.16xlQ-3
-
-
S.lSxlQ-3
-
1.29 x ID"8
6.96 x ID"5
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
1,3,5-Trimethylbenzene
1,3-Butadiene
1,3-Dichloropropene
1,4-Dioxane
1,6-Hexanediamine
1,6-Hexanediamine dihydrochloride
l-[2-(2-Methoxy-l-methylethoxy)-l-
methylethoxy]-2-propanol
l-Amino-2-propanol
1-Benzylquinolinium chloride
1-Butanol
l-Butoxy-2-propanol
CASRN
108-67-8
106-99-0
542-75-6
123-91-1
124-09-4
6055-52-3
20324-33-8
78-96-6
15619-48-4
71-36-3
5131-66-8
Log Kow
Estimated
3.63
2.03
2.29
-0.32
0.35
0.35
-0.2
-1.19
4.4
0.84
0.98
Measured
3.42
1.99
2.04
-0.27
-
-
-
-0.96
-
0.88
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
120.3
792.3
1,994
2.14xl05
5.34 x 105
5.34 x 105
1.96 x 105
1.00 x 10s
6.02
7.67 x 104
4.21 xlO4
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
7.24 x ID"3
7.79 x ID"2
2.45 x ID"2
5.91 x 1Q-6
3.21 x 1Q-9
3.21 x 1Q-9
2.36 x 1Q-11
4.88 x ID"10
1.19 x 1Q-6
9.99 x 1Q-6
1.30 x ID"7
Group
method 25
6.58 x ID"3
7.05 x ID"2
3.22 x 1Q-3
1.12 x ID"7
7.05 x ID"10
7.05 x ID"10
4.55 x 1Q-13
2.34 x ID"10
-
9.74 x ID"6
4.88 x ID"8
Measured
8.77 x 1Q-3
7.36 x ID"2
3.55 x 1Q-3
4.80 x 1Q-6
-
-
-
-
-
8.81 x ID"6
-
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
1-Decanol
l-Dodecyl-2-pyrrolidinone
1-Eicosene
l-Ethyl-2-methylbenzene
1-Hexadecene
1-Hexanol
l-Methoxy-2-propanol
1-Octadecanamine, acetate (1:1)
1-Octadecanamine, N,N-dimethyl-
1-Octadecene
1-Octanol
1-Pentanol
CASRN
112-30-1
2687-96-9
3452-07-1
611-14-3
629-73-2
111-27-3
107-98-2
2190-04-7
124-28-7
112-88-9
111-87-5
71-41-0
Log Kow
Estimated
3.79
5.3
10.03
3.58
8.06
1.82
-0.49
7.71
8.39
9.04
2.81
1.33
Measured
4.57
4.2
-
3.53
-
2.03
-
-
-
-
3
1.51
Water solubility
Estimate from log Kow
(mg/Lat25°C)
28.21
5.862
1.26 x ID"5
96.88
0.001232
6,885
1.00 x 10s
0.04875
0.008882
1.256x 10'4
814
2.09 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
5.47 x ID"5
7.12 x ID"7
1.89 x 101
8.71 x 1Q-3
6.10
1.76 x 1Q-5
5.56 x 1Q-8
9.36 x ID"4
4.51 x 1Q-3
10.7
S.lOxlQ-5
1.33 x 1Q-5
Group
method 25
7.73 x ID"5
-
6.74 x 101
9.52 x ID"3
1.69 x 101
1.94 x 1Q-5
1.81 x 1Q-8
2.18xlQ-3
3.88 x ID"2
3.38 xlO1
3.88 x 1Q-5
1.38 x 1Q-5
Measured
3.20 x 1Q-5
-
-
5.53 x ID"3
-
1.71 x ID"5
9.20 x ID"7
-
-
-
2.45 x ID"5
1.30 x ID"5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-35 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
1-Propanaminium, 3-chloro-2-hydroxy-
N,N,N-trimethyl-, chloride
1-Propanesulfonic acid
1-Propanol
1-Propene
l-tert-Butoxy-2-propanol
1-Tetradecene
1-Tridecanol
1-Undecanol
2-(2-Butoxyethoxy)ethanol
2-(2-Ethoxyethoxy)ethanol
2-(2-Ethoxyethoxy)ethyl acetate
CASRN
3327-22-8
5284-66-2
71-23-8
115-07-1
57018-52-7
1120-36-1
112-70-9
112-42-5
112-34-5
111-90-0
112-15-2
Log Kow
Estimated
-4.48
-1.4
0.35
1.68
0.87
7.08
5.26
4.28
0.29
-0.69
0.32
Measured
-
-
0.25
1.77
-
-
-
-
0.56
-0.54
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.00 x 10s
2.72 x 105
1,162
5.24 x 104
0.01191
4.533
43.04
7.19xl04
8.28 x 105
3.09 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
9.48 x ID"17
2.22 x 1Q-8
7.52 x 1Q-6
1.53 x ID"1
1.30 x ID"7
3.46
1.28 x ID"4
7.26 x 1Q-5
1.52 x 1Q-9
8.63 x ID"10
5.62 x 1Q-8
Group
method 25
-
-
6.89 x ID"6
1.58 x ID"1
5.23 x 1Q-8
8.48
2.18xlQ-4
1.09 x ID"4
4.45 x 1Q-11
2.23 x 1Q-11
7.22 x ID"10
Measured
-
-
7.41 x ID"6
1.96 x ID"1
-
-
-
-
7.20 x ID"9
2.23 x ID"8
2.29 x 1Q-8
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
2-(Dibutylamino)ethanol
2-(Hydroxymethylamino)ethanol
2-(Thiocyanomethylthio)benzothiazole
2,2'-(Diazene-l,2-diyldiethane-l,l-
diyl)bis-4,5-dihydro-lH-imidazole
dihydrochloride
2,2'-(Octadecylimino)diethanol
2,2'-[Ethane-l,2-
diylbis(oxy)]diethanamine
2,2'-Azobis(2-amidinopropane)
dihydrochloride
2,2-Dibromo-3-nitrilopropionamide
2,2-Dibromopropanediamide
2,4-Hexadienoicacid, potassium salt,
(2E,4E)-
CASRN
102-81-8
34375-28-5
21564-17-0
27776-21-2
10213-78-2
929-59-9
2997-92-4
10222-01-2
73003-80-2
24634-61-5
Log Kow
Estimated
2.01
-1.53
3.12
2.12
6.85
-2.17
-3.28
1.01
0.37
1.62
Measured
2.65
-
3.3
-
-
-
-
0.82
-
1.33
Water solubility
Estimate from log Kow
(mg/Lat25°C)
3,297
1.00 x 10s
41.67
193.3
0.08076
1.00 x 10s
1.00 x 10s
2,841
1.00 x 104
1.94 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
9.70 x ID"9
1.62 x ID"12
6.49 x ID"12
S.llxlQ-14
1.06 x 1Q-8
2.50 x 1Q-13
1.21 x 1Q-14
6.16 x 1Q-14
3.58 x ID"14
5.72 x ID"7
Group
method 25
1.02 x ID"8
-
-
-
7.39 x ID"12
S.lOxlQ-16
-
-
-
4.99 x ID"8
Measured
-
-
-
-
-
-
-
1.91 x ID"8
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-37 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
2,6,8-Trimethyl-4-nonanol
2-Acrylamido-2-methyl-l-propanesulfonic
acid
2-Amino-2-methylpropan-l-ol
2-Aminoethanol hydrochloride
2-Bromo-3-nitrilopropionamide
2-Butanone oxime
2-Butoxy-l-propanol
2-Butoxyethanol
2-Dodecylbenzenesulfonic acid- N-(2-
aminoethyl)ethane-l,2-diamine(l:l)
2-Ethoxyethanol
2-Ethoxynaphthalene
CASRN
123-17-1
15214-89-8
124-68-5
2002-24-6
1113-55-9
96-29-7
15821-83-7
111-76-2
40139-72-8
110-80-5
93-18-5
Log Kow
Estimated
4.48
-2.19
-0.74
-1.61
-0.31
1.69
0.98
0.57
4.78
-0.42
3.74
Measured
-
-
-
-1.31
-
0.63
-
0.83
-
-0.32
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
24.97
1.00 x 10s
1.00 x 10s
1.00 x 10s
3,274
3.66 x 104
4.21 xlO4
6.45 x 104
0.7032
7.55 x 105
38.32
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
9.63 x ID"5
S.lSxlQ-15
6.48 x ID"10
3.68 x ID"10
5.35 x 1Q-13
1.04 x 1Q-5
1.30 x ID"7
9.79 x 1Q-8
6.27 x 1Q-8
5.56 x 1Q-8
4.13 x 1Q-5
Group
method 25
4.45 x ID"4
-
-
9.96 x ID"11
-
-
4.88 x ID"8
2.08 x ID"8
-
1.04 x ID"8
4.06 x ID"4
Measured
-
-
-
-
-
-
-
1.60 x ID"6
-
4.70 x ID"7
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-38 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
2-Ethyl-l-hexanol
2-Ethyl-2-hexenal
2-Ethylhexyl benzoate
2-Hydroxyethyl acrylate
2-Hydroxyethylammonium hydrogen
sulphite
2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-
methylethanaminium chloride
2-Mercaptoethanol
2-Methoxyethanol
2-Methyl-l-propanol
2-Methyl-2,4-pentanediol
2-Methyl-3(2H)-isothiazolone
CASRN
104-76-7
645-62-5
5444-75-7
818-61-1
13427-63-9
7006-59-9
60-24-2
109-86-4
78-83-1
107-41-5
2682-20-4
Log Kow
Estimated
2.73
2.62
5.19
-0.25
-1.61
-6.7
-0.2
-0.91
0.77
0.58
-0.83
Measured
-
-
-
-0.21
-1.31
-
-
-0.77
0.76
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1,379
548.6
1.061
5.07 x 105
1.00 x 10s
1.00 x 10s
1.94 x 105
1.00 x 10s
9.71 xlO4
3.26 x 104
5.37 x 105
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
S.lOxlQ-5
2.06 x ID"4
2.52 x ID"4
4.49 x 1Q-9
3.68 x ID"10
4.78 x 1Q-19
1.27 x ID"7
4.19 x 1Q-8
9.99 x 1Q-6
4.06 x ID"7
4.96 x 1Q-8
Group
method 25
4.66 x ID"5
4.88 x ID"4
2.34 x ID"4
7.22 x ID"10
9.96 x 1Q-11
-
3.38 x ID"8
7.73 x ID"9
1.17 x 1Q-5
3.97 x ID"10
-
Measured
2.65 x ID"5
-
-
-
-
-
1.80 x ID"7
3.30 x ID"7
9.78 x 1Q-6
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-39 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
2-Methyl-3-butyn-2-ol
2-Methylbutane
2-Methylquinoline hydrochloride
2-Phosphono-l,2,4-butanetricarboxylic
acid
2-Phosphonobutane-l,2,4-tricarboxylic
acid, potassium salt (l:x)
2-Propenoic acid, 2-(2-
hydroxyethoxy)ethyl ester
3-(Dimethylamino)propylamine
3,4,4-Trimethyloxazolidine
3,5,7-Triazatricyclo(3.3.1.13,7))decane, 1-
(3-chloro-2-propenyl)-, chloride, (Z)-
3,7-Dimethyl-2,6-octadienal
CASRN
115-19-5
78-78-4
62763-89-7
37971-36-1
93858-78-7
13533-05-6
109-55-7
75673-43-7
51229-78-8
5392-40-5
Log Kow
Estimated
0.45
2.72
2.69
-1.66
-1.66
-0.52
-0.45
0.13
-5.92
3.45
Measured
0.28
-
2.59
-
-
-0.3
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
2.40 x 105
184.6
498.5
1.00 x 10s
1.00 x 10s
3.99 x 105
1.00 x 10s
8.22 x 105
1.00 x 10s
84.71
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.04 x ID"6
1.29
7.60 x ID"7
1.17xlQ-26
1.17xlQ-26
6.98 x ID"11
6.62 x ID"9
6.63 x ID"6
1.76 x ID"8
3.76 x ID"4
Group
method 25
-
1.44
2.13 x ID"6
-
-
1.54 x ID"12
4.45 x ID"9
-
-
4.35 x ID"5
Measured
3.91 x 1Q-6
1.40
-
-
-
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-40 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
3-Hydroxybutanal
3-Methoxypropylamine
3-Phenylprop-2-enal
4,4-Dimethyloxazolidine
4,6-Dimethyl-2-heptanone
4-[Abieta-8,ll,13-trien-18-yl(3-oxo-3-
phenylpropyl)amino]butan-2-one
hydrochloride
4-Ethyloct-l-yn-3-ol
4-Hydroxy-3-methoxybenzaldehyde
4-Methoxybenzyl formate
4-Methoxyphenol
4-Methyl-2-pentanol
CASRN
107-89-1
5332-73-0
104-55-2
51200-87-4
19549-80-5
143106-84-7
5877-42-9
121-33-5
122-91-8
150-76-5
108-11-2
Log Kow
Estimated
-0.72
-0.42
1.82
-0.08
2.56
7.72
2.87
1.05
1.61
1.59
1.68
Measured
-
-
1.9
-
-
-
-
1.21
-
1.58
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.00 x 10s
2,150
1.00 x 10s
528.8
0.002229
833.9
6,875
2,679
1.65 x 104
1.38 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
4.37 x ID"9
1.56 x ID"7
1.60 x 1Q-6
3.02 x 1Q-6
2.71 xlQ-4
2.49 x ID"12
4.27 x 1Q-6
8.27 x 1Q-11
1.15 x 1Q-6
3.32 x 1Q-8
1.76 x 1Q-5
Group
method 25
2.28 x ID"9
1.94 x ID"8
3.38 x ID"7
-
4.55 x ID"4
1.20 x ID"14
-
2.81 x ID"9
2.13 x ID"6
5.35 x ID"7
3.88 x 1Q-5
Measured
-
-
-
-
-
-
-
2.15xlQ-9
-
-
4.45 x ID"5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-41 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
4-Methyl-2-pentanone
4-Nonylphenol
5-Chloro-2-methyl-3(2H)-isothiazolone
Acetaldehyde
Acetic acid
Acetic acid, C6-8-branched alkyl esters
Acetic acid, hydroxy-, reaction products
with triethanolamine
Acetic acid, mercapto-, monoammonium
salt
Acetic anhydride
Acetone
Acetonitrile, 2,2',2"-nitrilotris-
CASRN
108-10-1
104-40-5
26172-55-4
75-07-0
64-19-7
90438-79-2
68442-62-6
5421-46-5
108-24-7
67-64-1
7327-60-8
Log Kow
Estimated
1.16
5.99
-0.34
-0.17
0.09
3.25
-2.48
0.03
-0.58
-0.24
-1.39
Measured
1.31
5.76
-
-0.34
-0.17
-
-1
0.09
-
-0.24
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
8,888
1.57
1.49 x 105
2.57 x 105
4.76 x 105
117.8
1.00 x 10s
2.56 x 105
3.59 x 105
2.20 x 105
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.16 x ID"4
5.97 x 1Q-6
3.57 x 1Q-8
6.78 x 1Q-5
5.48 x ID"7
9.60 x ID"4
4.18xlO-12
1.94 x 1Q-8
3.57 x 1Q-5
4.96 x 1Q-5
2.61 x 1Q-15
Group
method 25
1.34 x ID"4
1.23 x ID"5
-
6.00 x ID"5
2.94 x ID"7
1.07 x 1Q-3
3.38 x 1Q-19
-
-
3.97 x ID"5
-
Measured
1.38 x ID"4
3.40 x 1Q-5
-
6.67 x ID"5
1.00 x ID"7
-
7.05 x ID"13
-
5.71 x ID"6
3.50 x ID"5
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-42 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Acetophenone
Acetyltriethyl citrate
Acrolein
Acrylamide
Acrylic acid
Acrylic acid, with sodium-2-acrylamido-2-
methyl-1-propanesulfonate and sodium
phosphinate
Alcohols, CIO- 12, ethoxylated
Alcohols, Cll-14-iso-, CIS-rich
Alcohols, Cll-14-iso-, CIS-rich,
ethoxylated
Alcohols, C12-13, ethoxylated
CASRN
98-86-2
77-89-4
107-02-8
79-06-1
79-10-7
110224-99-2
67254-71-1
68526-86-3
78330-21-9
66455-14-9
Log Kow
Estimated
1.67
1.34
0.19
-0.81
0.44
-2.19
5.47
5.19
4.91
5.96
Measured
1.58
-
-0.01
-0.67
0.35
-
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
4,484
688.2
1.40 x 105
5.04 x 105
1.68 x 105
1.00 x 10s
0.9301
5.237
5.237
0.2995
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
9.81 x ID"6
6.91 x 1Q-11
3.58 x 1Q-5
5.90 x 1Q-9
2.89 x ID"7
S.lSxlQ-15
1.95 x ID"2
1.28 x ID"4
1.25 x 1Q-6
2.58 x ID"2
Group
method 25
1.09 x ID"5
-
1.94 x ID"5
-
1.17 x ID"7
-
2.03 x ID"2
2.62 x ID"4
7.73 x ID"7
2.87 x ID"2
Measured
1.04 x 1Q-5
-
1.22 x ID"4
1.70 x ID"9
3.70 x ID"7
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-43 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Alcohols, C12-14, ethoxylated
propoxylated
Alcohols, C12-14-secondary
Alcohols, C12-16, ethoxylated
Alcohols, C14-15, ethoxylated
Alcohols, C6-12, ethoxylated
Alcohols, C7-9-iso-, C8-rich, ethoxylated
Alcohols, C9-11, ethoxylated
Alcohols, C9-11-ISO-, ClO-rich,
ethoxylated
Alkanes, C12-14-iso-
Alkanes, C13-16-iso-
Alkenes, OlOalpha-
CASRN
68439-51-0
126950-60-5
68551-12-2
68951-67-7
68439-45-2
78330-19-5
68439-46-3
78330-20-8
68551-19-9
68551-20-2
64743-02-8
Log Kow
Estimated
6.67
5.19
6.45
7.43
4.49
2.46
4.98
4.9
6.65
7.63
8.55
Measured
-
-
-
-
-
-
-
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
0.02971
5.237
0.09603
0.009765
8.832
1,513
2.874
3.321
0.03173
0.003311
0.0003941
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
7.08 x ID"4
1.28 x ID"4
3.43 x ID"2
6.04 x ID"2
l.lOxlQ-2
3.04 x ID"7
1.47 x ID"2
1.47 x ID"2
1.24 x 101
2.19X101
8.09
Group
method 25
1.23 x ID"4
3.62 x ID"4
4.06 x ID"2
S.lOxlQ-2
1.02 x ID"2
1.38 x ID"7
1.44 x ID"2
2.39 x ID"2
2.28 xlO1
4.55 x 101
2.39 x 101
Measured
-
-
-
-
-
-
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-44 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Alkyl* dimethyl ethylbenzyl ammonium
chloride *(50%C12, 30%C14, 17%C16,
3%C18)
Alkyl* dimethyl ethylbenzyl ammonium
chloride *(60%C14, 30%C16, 5%C12,
5%C18)
Alkylbenzenesulfonate, linear
alpha-Lactose monohydrate
alpha-Terpineol
Amaranth
Aminotrimethylene phosphonic acid
Ammonium acetate
Ammonium acrylate
Ammonium citrate (1:1)
CASRN
85409-23-0_l
68956-79-6
42615-29-2
5989-81-1
98-55-5
915-67-3
6419-19-8
631-61-8
10604-69-0
7632-50-0
Log Kow
Estimated
3.97
4.95
4.71
-5.12
3.33
1.63
-5.45
0.09
0.44
-1.67
Measured
-
-
-
-
2.98
-
-3.53
-0.17
0.35
-1.64
Water solubility
Estimate from log Kow
(mg/Lat25°C)
3.23
0.3172
0.8126
1.00 x 10s
371.7
1.789
1.00 x 10s
4.76 x 105
1.68 x 105
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
l.llxlQ-11
1.96 x ID"11
6.27 x ID"8
4.47 x ID"22
1.58 x 1Q-5
1.49 x 1Q-30
1.65 x 1Q-34
5.48 x ID"7
2.89 x ID"7
8.33 x 1Q-18
Group
method 25
-
-
-
9.81 x ID"45
3.15 x ID"6
-
-
2.94 x ID"7
1.17 x ID"7
-
Measured
-
-
-
-
1.22 x ID"5
-
-
1.00 x ID"7
3.70 x ID"7
4.33 x 1Q-14
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-45 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Ammonium citrate (2:1)
Ammonium dodecyl sulfate
Ammonium hydrogen carbonate
Ammonium lactate
Anethole
Aniline
Benactyzine hydrochloride
Benzamorf
Benzene
Benzene, C10-16-alkyl derivatives
Benzenesulfonic acid
Benzenesulfonic acid, (1-methylethyl)-,
CASRN
3012-65-5
2235-54-3
1066-33-7
515-98-0
104-46-1
62-53-3
57-37-4
12068-08-5
71-43-2
68648-87-3
98-11-3
37953-05-2
Log Kow
Estimated
-1.67
2.42
-0.46
-0.65
3.39
1.08
2.89
4.71
1.99
8.43
-1.17
0.29
Measured
-1.64
-
-
-0.72
-
0.9
-
-
2.13
9.36
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
163.7
8.42 x 105
1.00 x 10s
98.68
2.08 x 104
292.1
0.8126
2,000
0.0002099
6.90 x 105
2.46 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
8.33 x ID"18
1.84 x ID"7
6.05 x 1Q-9
1.13 x ID"7
2.56 x ID"4
1.90 x 1Q-6
2.07 x ID"10
6.27 x 1Q-8
5.39 x 1Q-3
1.78 x ID"1
2.52 x 1Q-9
4.89 x 1Q-9
Group
method 25
-
-
-
-
2.23 x ID"3
2.18xlQ-6
-
-
5.35 x ID"3
3.97 x ID"1
-
-
Measured
4.33 x ID"14
-
-
8.13xlQ-8
-
2.02 x ID"6
-
-
5.55 x ID"3
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-46 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Benzenesulfonic acid, (1-methylethyl)-,
ammonium salt
Benzenesulfonic acid, (1-methylethyl)-,
sodium salt
Benzenesulfonic acid, C10-16-alkyl
derivatives, compounds with
cyclohexylamine
Benzenesulfonic acid, C10-16-alkyl
derivatives, compounds with
triethanolamine
Benzenesulfonic acid, C10-16-alkyl
derivatives, potassium salts
Benzenesulfonic acid, dodecyl-, branched,
compounds with 2-propanamine
Benzenesulfonic acid, mono-C10-16-alkyl
derivatives, sodium salts
Benzoicacid
CASRN
37475-88-0
28348-53-0
255043-08-4
68584-25-8
68584-27-0
90218-35-2
68081-81-2
65-85-0
Log Kow
Estimated
0.29
0.29
4.71
5.2
5.2
4.49
4.22
1.87
Measured
-
-
-
-
-
-
-
1.87
Water solubility
Estimate from log Kow
(mg/Lat25°C)
2.46 x 104
2.46 x 104
0.8126
0.255
0.255
1.254
2.584
2,493
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
4.89 x ID"9
4.89 x 1Q-9
6.27 x 1Q-8
8.32 x 1Q-8
8.32 x 1Q-8
6.27 x 1Q-8
4.72 x 1Q-8
1.08 x ID"7
Group
method 25
-
-
-
-
-
-
-
4.55 x ID"8
Measured
-
-
-
-
-
-
-
3.81 x ID"8
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-47 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Benzyl chloride
Benzyldimethyldodecylammonium
chloride
Benzylhexadecyldimethylammonium
chloride
Benzyltrimethylammonium chloride
Bicine
Bis(l-methylethyl)naphthalenesulfonic
acid, cyclohexylamine salt
Bis(2-chloroethyl) ether
Bisphenol A
Bronopol
Butane
CASRN
100-44-7
139-07-1
122-18-9
56-93-9
150-25-4
68425-61-6
111-44-4
80-05-7
52-51-7
106-97-8
Log Kow
Estimated
2.79
2.93
4.89
-2.47
-3.27
2.92
1.56
3.64
-1.51
2.31
Measured
2.3
-
-
-
-
-
1.29
3.32
-
2.89
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1,030
36.47
0.3543
1.00 x 10s
3.52 x 105
43.36
6,435
172.7
8.37 x 105
135.6
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
2.09 x ID"3
7.61 xlQ-12
2.36 x 1Q-11
3.37 x 1Q-13
1.28 x 1Q-14
9.29 x ID"10
1.89 x ID"4
9.16 x ID"12
6.35 x ID"21
9.69 x ID"1
Group
method 25
3.97 x ID"4
-
-
-
-
-
4.15 x ID"7
-
-
8.48 x ID"1
Measured
4.12xlQ-4
-
-
-
-
-
1.70 x ID"5
-
-
9.50 x ID"1
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-48 DRAFT—DO NOT CITE OR QUOTE
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Butanedioic acid, sulfo-, l,4-bis(l,3-
dimethylbutyl) ester, sodium salt
Butene
Butyl glycidyl ether
Butyl lactate
Butyryl trihexyl citrate
C.I. Acid Red 1
C.I. Acid Violet 12, disodium salt
C.I. Pigment Red 5
C.I. Solvent Red 26
CIO- 16-Alkyldimethyla mines oxides
C10-C16 Ethoxylated alcohol
CASRN
2373-38-8
25167-67-3
2426-08-6
138-22-7
82469-79-2
3734-67-6
6625-46-3
6410-41-9
4477-79-6
70592-80-2
68002-97-1
Log Kow
Estimated
3.98
2.17
1.08
0.8
8.21
0.51
0.59
7.65
9.27
2.87
4.99
Measured
-
2.4
0.63
-
-
-
-
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
0.1733
354.8
2.66 x 104
5.30 x 104
5.56 x ID"5
6.157
3.379
4.38 x 1Q-5
5.68 x 1Q-5
89.63
4.532
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.61 x ID"12
2.03 x ID"1
4.37 x 1Q-6
8.49 x 1Q-5
3.65 x 1Q-9
3.73 x 1Q-29
2.21 x 1Q-30
4.36 x ID"21
5.48 x 1Q-13
1.14xlO-13
1.25 x 1Q-6
Group
method 25
-
2.68 x ID"1
5.23 x ID"7
-
-
-
-
-
4.66 x ID"13
-
4.66 x ID"7
Measured
-
2.33 x ID"1
2.47 x ID"5
1.92 x 1Q-6
-
-
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-49 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
C12-14 tert-Alkyl ethoxylated amines
Calcium dodecylbenzene sulfonate
Camphor
Carbon dioxide
Carbonic acid, dipotassium salt
Choline bicarbonate
Choline chloride
Citric acid
Citronellol
Coconut trimethylammonium chloride
Coumarin
Cumene
CASRN
73138-27-9
26264-06-2
76-22-2
124-38-9
584-08-7
78-73-9
67-48-1
77-92-9
106-22-9
61789-18-2
91-64-5
98-82-8
Log Kow
Estimated
3.4
4.71
3.04
0.83
-0.46
-5.16
-5.16
-1.67
3.56
1.22
1.51
3.45
Measured
-
-
2.38
0.83
-
-
-
-1.64
3.91
-
1.39
3.66
Water solubility
Estimate from log Kow
(mg/Lat25°C)
264.2
0.8126
339.1
2.57 x 104
8.42 x 105
1.00 x 10s
1.00 x 10s
1.00 x 10s
105.5
2,816
5,126
75.03
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.29 x ID"10
6.27 x 1Q-8
7.00 x 1Q-5
1.52 x ID"2
6.05 x 1Q-9
2.03 x 1Q-16
2.03 x 1Q-16
8.33 x 1Q-18
5.68 x 1Q-5
9.42 x 1Q-11
6.95 x 1Q-6
1.05 x ID"2
Group
method 25
-
-
-
-
-
-
-
-
2.13 x ID"5
-
-
1.23 x ID"2
Measured
-
-
S.lOxlQ-5
1.52 x ID"2
-
-
-
4.33 x ID"14
-
-
9.92 x ID"8
l.lSxlQ-2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-50 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Cyclohexane
Cyclohexanol
Cyclohexanone
Cyclohexylamine sulfate
D&C Red no. 28
D&C Red no. 33
Daidzein
Dapsone
Dazomet
Decyldimethylamine
D-Glucitol
D-Gluconic acid
CASRN
110-82-7
108-93-0
108-94-1
19834-02-7
18472-87-2
3567-66-6
486-66-8
80-08-0
533-74-4
1120-24-7
50-70-4
526-95-4
Log Kow
Estimated
3.18
1.64
1.13
1.63
9.62
0.48
2.55
0.77
0.94
4.46
-3.01
-1.87
Measured
3.44
1.23
0.81
1.49
-
-
-
0.97
0.63
-
-2.2
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
43.02
3.37 x 104
2.41 x 104
6.40 x 104
1.64 x ID"8
11.87
568.4
3,589
1.94 x 104
82.23
1.00 x 10s
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
2.55 x ID"1
4.90 x 1Q-6
S.llxlQ-5
1.38 x 1Q-5
6.37 x ID"21
1.15 x 1Q-26
3.91 x 1Q-16
S.llxlQ-14
2.84 x 1Q-3
4.68 x ID"4
7.26 x 1Q-13
4.74 x 1Q-13
Group
method 25
1.94 x ID"1
3.70 x ID"6
1.28 x 1Q-5
-
-
-
-
-
-
2.45 x ID"3
2.94 x ID"29
-
Measured
1.50 x ID"1
4.40 x 1Q-6
9.00 x 1Q-6
4.16xlQ-6
-
-
-
-
4.98 x ID"10
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-51 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
D-Glucopyranoside, methyl
D-Glucose
Di(2-ethylhexyl) phthalate
Dibromoacetonitrile
Dichloromethane
Didecyldimethylammonium chloride
Diethanolamine
Diethylbenzene
Diethylene glycol
Diethylene glycol monomethyl ether
Diethylenetriamine
Diisobutyl ketone
CASRN
3149-68-6
50-99-7
117-81-7
3252-43-5
75-09-2
7173-51-5
111-42-2
25340-17-4
111-46-6
111-77-3
111-40-0
108-83-8
Log Kow
Estimated
-2.5
-2.89
8.39
0.47
1.34
4.66
-1.71
4.07
-1.47
-1.18
-2.13
2.56
Measured
-
-3.24
7.6
-
1.25
-
-1.43
3.72
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.00 x 10s
0.001132
9,600
l.lOxlO4
0.9
1.00 x 10s
58.86
1.00 x 10s
1.00 x 10s
1.00 x 10s
528.8
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.56 x ID"14
9.72 x 1Q-15
l.lSxlQ-5
4.06 x ID"7
9.14xlQ-3
6.85 x ID"10
3.92 x 1Q-11
1.16 x ID"2
2.03 x 1Q-9
6.50 x ID"10
S.lOxlQ-13
2.71 x ID"4
Group
method 25
2.23 x ID"24
1.62 x ID"26
1.02 x 1Q-5
-
3.01 x ID"3
-
3.46 x ID"15
1.47 x ID"2
1.20 x 1Q-13
1.65 x 1Q-11
1.09 x ID"14
4.55 x ID"4
Measured
-
-
2.70 x ID"7
-
3.25 x ID"3
-
3.87 x ID"11
2.61 x ID"3
-
-
-
1.17xlQ-4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-52 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Diisopropanolamine
Diisopropylnaphthalene
Dimethyl adipate
Dimethyl glutarate
Dimethyl succinate
Dimethylaminoethanol
Dimethyldiallylammonium chloride
Diphenyl oxide
Dipropyleneglycol
Di-sec-butylphenol
Disodium
dodecyl(sulphonatophenoxy)benzenesulp
honate
CASRN
110-97-4
38640-62-9
627-93-0
1119-40-0
106-65-0
108-01-0
7398-69-8
101-84-8
25265-71-8
31291-60-8
28519-02-0
Log Kow
Estimated
-0.88
6.08
1.39
0.9
0.4
-0.94
-2.49
4.05
-0.64
5.41
5.05
Measured
-0.82
-
1.03
0.62
0.35
-
-
4.21
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
0.2421
7,749
2.02 x 104
3.96 x 104
1.00 x 10s
1.00 x 10s
15.58
S.llxlO5
3.723
0.0353
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
6.91 x ID"11
1.99 x 1Q-3
9.77 x ID"7
7.36 x ID"7
5.54 x ID"7
1.77 x 1Q-9
7.20 x ID"12
l.lSxlQ-4
3.58 x 1Q-9
3.74 x 1Q-6
6.40 x 1Q-16
Group
method 25
1.90 x ID"14
1.94 x ID"3
1.28 x ID"7
9.09 x 1Q-8
6.43 x 1Q-8
1.77 x 1Q-9
-
2.81 x ID"4
6.29 x ID"10
6.89 x 1Q-6
-
Measured
-
-
2.31 x ID"6
6.43 x ID"7
-
3.73 x ID"7
-
2.79 x ID"4
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-53 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Disodium ethylenediaminediacetate
Disodium ethylenediaminetetraacetate
dihydrate
D-Lactic acid
D-Limonene
Docusate sodium
Dodecane
Dodecylbenzene
Dodecylbenzenesulfonic acid
Dodecylbenzenesulfonic acid,
monoethanolamine salt
Epichlorohydrin
CASRN
38011-25-5
6381-92-6
10326-41-7
5989-27-5
577-11-7
112-40-3
123-01-3
27176-87-0
26836-07-7
106-89-8
Log Kow
Estimated
-4.79
-3.86
-0.65
4.83
6.1
6.23
7.94
4.71
4.71
0.63
Measured
-
-
-0.72
4.57
-
6.1
8.65
-
-
0.45
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
2.28 x 105
1.00 x 10s
4.581
0.001227
0.1099
0.001015
0.8126
0.8126
5.06 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
l.lOxlQ-16
1.17xlO-23
1.13 x ID"7
3.80 x ID"1
5.00 x ID"12
9.35
1.34 x ID"1
6.27 x 1Q-8
6.27 x 1Q-8
5.62 x 1Q-5
Group
method 25
-
-
-
-
-
1.34 x 101
2.81 x ID"1
-
-
2.62 x ID"6
Measured
-
5.77 x ID"16
8.13xlQ-8
3.19X1Q-2
-
8.18
-
-
-
3.04 x ID"5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-54 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Ethanaminium, N,N,N-trimethyl-2-[(l-
oxo-2-propenyl)oxy]-, chloride
Ethane
Ethanol
Ethanol, 2,2',2"-nitrilotris-,
tris(dihydrogen phosphate) (ester),
sodium salt
Ethanol, 2-[2-[2-(tridecyloxy)
ethoxy]ethoxy]-, hydrogen sulfate,
sodium salt
Ethanolamine
Ethoxylated dodecyl alcohol
Ethyl acetate
Ethyl acetoacetate
Ethyl benzoate
CASRN
44992-01-0
74-84-0
64-17-5
68171-29-9
25446-78-0
141-43-5
9002-92-0
141-78-6
141-97-9
93-89-0
Log Kow
Estimated
-3.1
1.32
-0.14
-3.13
2.09
-1.61
4.5
0.86
-0.2
2.32
Measured
-
1.81
-0.31
-
-
-1.31
-
0.73
0.25
2.64
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
938.6
7.92 x 105
1.00 x 10s
42
1.00 x 10s
14.19
2.99 x 104
5.62 x 104
421.5
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
6.96 x ID"15
5.50 x ID"1
5.67 x 1Q-6
3.08 x 1Q-36
9.15xlO-13
3.68 x ID"10
9.45 x ID"7
2.33 x ID"4
1.57 x ID"7
4.61 x 1Q-5
Group
method 25
-
4.25 x ID"1
4.88 x ID"6
-
-
9.96 x ID"11
3.30 x ID"7
1.58 x ID"4
-
2.45 x ID"5
Measured
-
5.00 x ID"1
5.00 x ID"6
-
-
-
-
1.34 x ID"4
1.20 x ID"6
7.33 x 1Q-5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-55 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Ethyl lactate
Ethyl salicylate
Ethylbenzene
Ethylene
Ethylene glycol
Ethylene oxide
Ethylenediamine
Ethylenediaminetetraacetic acid
Ethylenediaminetetraacetic acid
tetrasodium salt
Ethylenediaminetetraacetic acid,
disodium salt
Ethyne
CASRN
97-64-3
118-61-6
100-41-4
74-85-1
107-21-1
75-21-8
107-15-3
60-00-4
64-02-8
139-33-3
74-86-2
Log Kow
Estimated
-0.18
3.09
3.03
1.27
-1.2
-0.05
-1.62
-3.86
-3.86
-3.86
0.5
Measured
-
2.95
3.15
1.13
-1.36
-0.3
-2.04
-
-
-
0.37
Water solubility
Estimate from log Kow
(mg/Lat25°C)
4.73 x 105
737.1
228.6
3,449
1.00 x 10s
2.37 x 105
1.00 x 10s
2.28 x 105
2.28 x 105
2.28 x 105
1.48 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
4.82 x ID"5
6.04 x 1Q-6
7.89 x 1Q-3
9.78 x ID"2
1.31 x ID"7
1.20 x ID"4
1.03 x 1Q-9
1.17 x 10-23
1.17xlQ-23
1.17xlQ-23
2.40 x ID"2
Group
method 25
-
3.01 x ID"9
8.88 x ID"3
1.62 x ID"1
5.60 x 1Q-11
5.23 x 1Q-5
1.77 x ID"10
-
-
-
2.45 x ID"2
Measured
5.83 x ID"7
-
7.88 x ID"3
2.28 x ID"1
6.00 x 1Q-8
1.48 x ID"4
1.73 x 1Q-9
5.77 x 1Q-16
5.77 x 1Q-16
5.77 x 1Q-16
2.17xlO-2
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-56 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Fatty acids, C18-unsaturated, dimers
FD&C Blue no. 1
FD&C Yellow no. 5
FD&C Yellow no. 6
Formaldehyde
Formamide
Formic acid
Formic acid, potassium salt
Fumaricacid
Furfural
Furfuryl alcohol
Galantamine hydrobromide
CASRN
61788-89-4
3844-45-9
1934-21-0
2783-94-0
50-00-0
75-12-7
64-18-6
590-29-4
110-17-8
98-01-1
98-00-0
69353-21-5
Log Kow
Estimated
14.6
-0.15
-1.82
1.4
0.35
-1.61
-0.46
-0.46
0.05
0.83
0.45
2.29
Measured
-
-
-
-
0.35
-1.51
-0.54
-0.54
-0.48
0.41
0.28
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
2.31 x ID"10
0.2205
7.388
242.7
5.70 x 104
1.00 x 10s
9.55 x 105
9.55 x 105
1.04 x 105
5.36 x 104
2.21 xlO5
1,606
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
4.12 x ID"8
2.25 x 1Q-35
1.31 x 1Q-28
3.26 x 1Q-23
9.29 x 1Q-5
1.53 x 1Q-8
7.50 x ID"7
7.50 x ID"7
1.35 x ID"12
1.34 x 1Q-5
2.17 x ID"7
1.70 x 1Q-13
Group
method 25
9.74 x ID"9
-
-
-
6.14xlQ-5
-
S.llxlQ-7
S.llxlQ-7
8.48 x ID"14
-
-
-
Measured
-
-
-
-
3.37 x ID"7
1.39 x ID"9
1.67 x ID"7
1.67 x ID"7
-
3.77 x ID"6
7.86 x ID"8
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-57 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Gluconic acid
Glutaraldehyde
Glycerol
Glycine, N-(carboxymethyl)-N-(2-
hydroxy ethyl)-, disodium salt
Glycine, N-(hydroxymethyl)-,
monosodium salt
Glycine, N,N-bis(carboxymethyl)-,
trisodium salt
Glycine, N-[2-
[bis(carboxymethyl)amino]ethyl]-N-(2-
hydroxyethyl)-, trisodium salt
Glycolicacid
Glycolic acid sodium salt
Glyoxal
CASRN
133-42-6
111-30-8
56-81-5
135-37-5
70161-44-3
5064-31-3
139-89-9
79-14-1
2836-32-0
107-22-2
Log Kow
Estimated
-1.87
-0.18
-1.65
-3.04
-3.41
-3.81
-4.09
-1.07
-1.07
-1.66
Measured
-
-
-1.76
-
-
-
-
-1.11
-1.11
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.67 x 105
1.00 x 10s
1.90 x 105
7.82 x 105
7.39 x 105
4.31 x 105
1.00 x 10s
1.00 x 10s
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
4.74 x ID"13
l.lOxlQ-7
6.35 x 1Q-9
3.90 x 1Q-17
1.80 x ID"12
1.19xlO-16
3.81 x ID"24
8.54 x ID"8
8.54 x ID"8
3.70 x ID"7
Group
method 25
-
2.39 x ID"8
1.51 x ID"15
-
-
-
-
6.29 x ID"11
6.29 x ID"11
-
Measured
-
-
1.73 x ID"8
-
-
-
-
-
-
3.33 x ID"9
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-58 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Glyoxylic acid
Heptane
Hexadecyltrimethylammonium bromide
Hexane
Hexanedioicacid
Hydroxyvalerenic acid
Indole
Isoascorbic acid
Isobutane
Isobutene
Isooctanol
Isopentyl alcohol
CASRN
298-12-4
142-82-5
57-09-0
110-54-3
124-04-9
1619-16-5
120-72-9
89-65-6
75-28-5
115-11-7
26952-21-6
123-51-3
Log Kow
Estimated
-1.4
3.78
3.18
3.29
0.23
3.31
2.05
-1.88
2.23
2.23
2.73
1.26
Measured
-
4.66
-
3.9
0.08
-
2.14
-1.85
2.76
2.34
-
1.16
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
3.554
28.77
17.24
1.67 x 105
282.1
1,529
1.00 x 10s
175.1
399.2
1,379
4.16xl04
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
2.98 x ID"9
2.27
2.93 x ID"10
1.71
9.53 x ID"12
-
8.86 x ID"7
4.07 x ID"8
9.69 x ID"1
2.40 x ID"1
S.lOxlQ-5
1.33 x 1Q-5
Group
method 25
-
2.39
-
1.69
S.lOxlQ-13
-
1.99 x ID"6
-
1.02
2.34 x ID"1
4.66 x ID"5
1.65 x 1Q-5
Measured
-
2.00
-
1.80
4.71 x ID"12
-
5.28 x ID"7
-
1.19
2.18X1Q-1
9.21 x ID"5
1.41 x 1Q-5
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-59 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Isopropanol
Isopropanolamine dodecylbenzene
Isopropylamine
Isoquinoline
Isoquinoline, reaction products with
benzyl chloride and quinoline
Isoquinolinium, 2-(phenylmethyl)-,
chloride
Lactic acid
Lactose
Lauryl hydroxysultaine
L-Dilactide
L-Glutamic acid
CASRN
67-63-0
42504-46-1
75-31-0
119-65-3
68909-80-8
35674-56-7
50-21-5
63-42-3
13197-76-7
4511-42-6
56-86-0
Log Kow
Estimated
0.28
7.94
0.27
2.14
2.14
4.4
-0.65
-5.12
-1.3
1.65
-3.83
Measured
0.05
8.65
0.26
2.08
2.08
-
-0.72
-
-
-
-3.69
Water solubility
Estimate from log Kow
(mg/Lat25°C)
4.02 x 105
0.001015
8.38 x 105
1,551
1,551
6.02
1.00 x 10s
1.00 x 10s
7.71 xlO4
3,165
9.42 x 105
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
7.52 x ID"6
1.34 x ID"1
1.34 x 1Q-5
6.88 x ID"7
6.88 x ID"7
1.19xlQ-6
1.13 x ID"7
4.47 x ID"22
1.04 x ID"21
1.22 x ID"5
1.47 x ID"14
Group
method 25
1.14xlQ-5
2.81 x ID"1
-
4.15 x ID"7
4.15 x ID"7
-
-
9.81 x ID"45
-
-
-
Measured
S.lOxlQ-6
-
4.51 x ID"5
-
-
-
8.13xlQ-8
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-60 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
L-Lactic acid
Methane
Methanol
Methenamine
Methoxyacetic acid
Methyl salicylate
Methyl vinyl ketone
Methylcyclohexane
Methylene bis(thiocyanate)
Methylenebis(5-methyloxazolidine)
Morpholine
CASRN
79-33-4
74-82-8
67-56-1
100-97-0
625-45-6
119-36-8
78-94-4
108-87-2
6317-18-6
66204-44-2
110-91-8
Log Kow
Estimated
-0.65
0.78
-0.63
-4.15
-0.68
2.6
0.41
3.59
0.62
-0.58
-0.56
Measured
-0.72
1.09
-0.77
-
-
2.55
-
3.61
-
-
-0.86
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
2,610
1.00 x 10s
1.00 x 10s
1.00 x 10s
1,875
6.06 x 104
28.4
2.72 x 104
1.00 x 10s
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.13 x ID"7
4.14X1Q-1
4.27 x 1Q-6
1.63 x ID"1
4.54 x 1Q-8
4.55 x 1Q-6
2.61 x 1Q-5
3.39 x ID"1
2.61 x 1Q-8
1.07 x ID"7
1.14xlQ-7
Group
method 25
-
6.58 x ID"1
3.62 x ID"6
-
8.68 x ID"9
2.23 x ID"9
1.38 x 1Q-5
3.30 x ID"1
-
-
3.22 x ID"9
Measured
8.13xlQ-8
6.58 x ID"1
4.55 x 1Q-6
1.64 x 1Q-9
6.42 x 1Q-9
9.81 x 1Q-5
4.65 x 1Q-5
4.30 x ID"1
-
-
i.iexio-6
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-61 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Morpholinium, 4-ethyl-4-hexadecyl-,
ethyl sulfate
N-(2-Acryloyloxyethyl)-N-benzyl-N,N-
dimethylammonium chloride
N-(3-Chloroallyl)hexaminium chloride
N,N,N-Trimethyl-3-((l-
oxooctadecyl)amino)-l-propanaminium
methyl sulfate
N,N,N-Trimethyloctadecan-l-aminium
chloride
N,N'-Dibutylthiourea
N,N-Dimethyldecylamine oxide
N,N-Dimethylformamide
N,N-Dimethylmethanamine
hydrochloride
CASRN
78-21-7
46830-22-2
4080-31-3
19277-88-4
112-03-8
109-46-6
2605-79-0
68-12-2
593-81-7
Log Kow
Estimated
4.54
-1.39
-5.92
4.38
4.17
2.57
1.4
-0.93
0.04
Measured
-
-
-
-
-
2.75
-
-1.01
0.16
Water solubility
Estimate from log Kow
(mg/Lat25°C)
0.9381
4.42 x 105
1.00 x 10s
0.7028
2.862
2,287
2,722
9.78 x 105
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
2.66 x ID"12
5.62 x 1Q-16
1.76 x 1Q-8
2.28 x 1Q-16
5.16xlO-10
4.17 x 1Q-6
4.88 x 1Q-14
7.38 x 1Q-8
3.65 x 1Q-5
Group
method 25
-
-
-
-
-
-
-
-
1.28 x ID"4
Measured
-
-
-
-
-
-
-
7.39 x ID"8
1.04 x ID"4
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-62 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
N,N-Dimethyl-methanamine-N-oxide
N,N-dimethyloctadecylamine
hydrochloride
N,N'-Methylenebisacrylamide
Naphthalene
Naphthalenesulfonicacid, bis(l-
methylethyl)-
Naphthalenesulphonic acid, bis (1-
methylethyl)-methyl derivatives
Naphthenic acid ethoxylate
Nitrilotriacetamide
Nitrilotriacetic acid
Nitrilotriacetic acid trisodium
monohydrate
CASRN
1184-78-7
1613-17-8
110-26-9
91-20-3
28757-00-8
99811-86-6
68410-62-8
4862-18-4
139-13-9
18662-53-8
Log Kow
Estimated
-3.02
8.39
-1.52
3.17
2.92
4.02
3.41
-4.75
-3.81
-3.81
Measured
-
-
-
3.3
-
-
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
0.008882
7.01 x 104
142.1
43.36
3.45
112.5
1.00 x 10s
7.39 x 105
7.39 x 105
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
3.81 x ID"15
4.51 x 1Q-3
1.14xlQ-9
5.26 x ID"4
9.29 x ID"10
l.lSxlQ-9
3.62 x ID"8
1.61 x ID"18
1.19 x ID"16
1.19xlO-16
Group
method 25
-
3.88 x ID"2
-
3.70 x ID"4
-
-
2.74 x ID"9
-
-
-
Measured
-
-
-
4.40 x ID"4
-
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
N-Methyl-2-pyrrolidone
N-Methyldiethanolamine
N-Methylethanolamine
N-Methyl-N-hydroxyethyl-N-
hydroxyethoxyethylamine
N-Oleyl diethanolamide
Oleic acid
Pentaethylenehexamine
Pentane
Pentyl acetate
Pentyl butyrate
Peracetic acid
CASRN
872-50-4
105-59-9
109-83-1
68213-98-9
13127-82-7
112-80-1
4067-16-7
109-66-0
628-63-7
540-18-1
79-21-0
Log Kow
Estimated
-0.11
-1.5
-1.15
-1.78
6.63
7.73
-3.67
2.8
2.34
3.32
-1.07
Measured
-0.38
-
-0.94
-
-
7.64
-
3.39
2.3
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
2.48 x 105
1.00 x 10s
1.00 x 10s
1.00 x 10s
0.1268
0.01151
1.00 x 10s
49.76
996.8
101.9
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
3.16 x ID"8
8.61 x 1Q-11
8.07 x ID"10
1.34 x ID"12
9.35 x 1Q-9
4.48 x 1Q-5
8.36 x ID"24
1.29
5.45 x ID"4
9.60 x ID"4
1.39 x 1Q-6
Group
method 25
-
2.45 x ID"14
2.50 x ID"10
5.23 x 1Q-17
1.94 x ID"12
1.94 x 1Q-5
2.56 x ID"27
1.20
4.45 x ID"4
8.88 x ID"4
-
Measured
3.20 x ID"9
3. 14x10-"
-
-
-
-
-
1.25
3.88 x ID"4
-
2.14xlQ-6
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-64 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Phenanthrene
Phenol
Phosphonic acid
(dimethylamino(methylene))
Phosphonic acid, (((2-[(2-hydroxyethyl)
(phosphonomethyl)amino)ethyl)imino]bis
(methylene))bis-, compd. with 2-
aminoethanol
Phosphonic acid, (1-hydroxyethylidene)
bis-, potassium salt
Phosphonic acid, (1-hydroxyethylidene)
bis-, tetrasodium salt
Phosphonic acid, [[(phosphonomethyl)
imino]bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-
CASRN
85-01-8
108-95-2
29712-30-9
129828-36-0
67953-76-8
3794-83-0
15827-60-8
Log Kow
Estimated
4.35
1.51
-1.9
-6.73
-0.01
-0.01
-9.72
Measured
4.46
1.46
-
-
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
0.677
2.62 x 104
1.00 x 10s
1.00 x 10s
1.34 x 105
1.34 x 105
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
5.13 x ID"5
5.61 x ID"7
1.00 x ID"24
5.29 x ID"42
9.79 x 1Q-26
9.79 x 1Q-26
-
Group
method 25
2.56 x ID"5
6.58 x ID"7
-
-
-
-
-
Measured
4.23 x ID"5
3.33 x ID"7
-
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-65 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Phosphonic acid, [[(phosphonomethyl)
imino]bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-, ammonium salt
(l:x)
Phosphonic acid, [[(phosphonomethyl)
imino]bis[2,l-ethanediylnitrilobis
(methylene)]]tetrakis-, sodium salt
Phosphonic acid, [[(phosphonomethyl)
imino]bis[6,l-hexanediylnitrilobis
(methylene)]]tetrakis-
Phthalic anhydride
Poly(oxy-l,2-ethanediyl),
.alpha.-(octylphenyl)-.omega.-hydroxy-,
branched
Potassium acetate
Potassium oleate
Propane
CASRN
70714-66-8
22042-96-2
34690-00-1
85-44-9
68987-90-6
127-08-2
143-18-0
74-98-6
Log Kow
Estimated
-9.72
-9.72
-5.79
2.07
5.01
0.09
7.73
1.81
Measured
-
-
-
1.6
-
-0.17
7.64
2.36
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.00 x 10s
1.00 x 10s
3,326
3.998
4.76 x 105
0.01151
368.9
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
-
-
-
6.35 x ID"6
1.24 x ID"7
5.48 x ID"7
4.48 x 1Q-5
7.30 x ID"1
Group
method 25
-
-
-
-
1.07 x ID"6
2.94 x ID"7
1.94 x 1Q-5
6.00 x ID"1
Measured
-
-
-
1.63 x ID"8
-
1.00 x ID"7
-
7.07 x ID"1
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
C-66 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Propanol, l(or2)-(2-
methoxymethylethoxy)-
Propargyl alcohol
Propylene carbonate
Propylene pentamer
p-Xylene
Pyrimidine
Pyrrole
Quaternary ammonium compounds, di-
C8-10-alkyldimethyl, chlorides
Quinaldine
Quinoline
Rhodamine B
CASRN
34590-94-8
107-19-7
108-32-7
15220-87-8
106-42-3
289-95-2
109-97-7
68424-95-3
91-63-4
91-22-5
81-88-9
Log Kow
Estimated
-0.27
-0.42
0.08
6.28
3.09
-0.06
0.88
2.69
2.69
2.14
6.03
Measured
-
-0.38
-0.41
-
3.15
-0.4
0.75
-
2.59
2.03
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
4.27 x 105
9.36 x 105
2.58 x 105
0.05601
228.6
2.87 x 105
3.12xl04
90.87
498.5
1,711
0.0116
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.15 x ID"9
5.88 x ID"7
3.63 x ID"4
3.92 x ID"1
6.56 x 1Q-3
2.92 x 1Q-6
9.07 x 1Q-6
2.20 x ID"10
7.60 x ID"7
6.88 x ID"7
-
Group
method 25
1.69 x ID"9
-
-
1.09 x ID"3
6.14xlQ-3
-
7.73 x ID"6
-
2.13 x ID"6
1.54 x ID"6
-
Measured
-
l.lSxlQ-6
3.45 x ID"8
-
6.90 x ID"3
-
1.80 x ID"5
-
-
1.67 x ID"6
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-67 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Sodium 1-octanesulfonate
Sodium 2-mercaptobenzothiolate
Sodium acetate
Sodium benzoate
Sodium bicarbonate
Sodium bis(tridecyl) sulfobutanedioate
Sodium C14-16 alpha-olefin sulfonate
Sodium caprylamphopropionate
Sodium carbonate
Sodium chloroacetate
Sodium decyl sulfate
Sodium D-gluconate
CASRN
5324-84-5
2492-26-4
127-09-3
532-32-1
144-55-8
2673-22-5
68439-57-6
68610-44-6
497-19-8
3926-62-3
142-87-0
527-07-1
Log Kow
Estimated
1.06
2.86
0.09
1.87
-0.46
11.15
4.36
-0.26
-0.46
0.34
1.44
-1.87
Measured
-
2.42
-0.17
1.87
-
-
-
-
-
0.22
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
5,864
543.4
4.76 x 105
2,493
8.42 x 105
7.46 x ID"9
2.651
615.1
8.42 x 105
1.95 x 105
1,617
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
9.15 x ID"8
3.63 x 1Q-8
5.48 x ID"7
1.08 x ID"7
6.05 x 1Q-9
8.51 x 1Q-11
4.95 x ID"7
1.19 x 1Q-9
6.05 x 1Q-9
1.93 x ID"7
1.04 x ID"7
4.74 x 1Q-13
Group
method 25
-
-
2.94 x ID"7
4.55 x ID"8
-
-
-
2.45 x ID"10
-
8.88 x ID"8
-
-
Measured
-
-
1.00 x ID"7
3.81 x ID"8
-
-
-
-
-
9.26 x ID"9
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-68 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Sodium diacetate
Sodium dichloroisocyanurate
Sodium dl-lactate
Sodium dodecyl sulfate
Sodium erythorbate (1:1)
Sodium ethasulfate
Sodium formate
Sodium hydroxymethanesulfonate
Sodium l-lactate
Sodium maleate (l:x)
Sodium N-methyl-N-oleoyltaurate
Sodium octyl sulfate
CASRN
126-96-5
2893-78-9
72-17-3
151-21-3
6381-77-7
126-92-1
141-53-7
870-72-4
867-56-1
18016-19-8
137-20-2
142-31-4
Log Kow
Estimated
0.09
1.28
-0.65
2.42
-1.88
0.38
-0.46
-3.85
-0.65
0.05
4.43
0.46
Measured
-0.17
-
-0.72
-
-1.85
-
-0.54
-
-0.72
-0.48
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
4.76 x 105
3,613
1.00 x 10s
163.7
1.00 x 10s
1.82 x 104
9.55 x 105
1.00 x 10s
1.00 x 10s
1.04 x 105
0.4748
1.58 x 104
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
5.48 x ID"7
3.22 x ID"12
1.13 x ID"7
1.84 x ID"7
4.07 x 1Q-8
5.91 x 1Q-8
7.50 x ID"7
4.60 x 1Q-13
1.13 x ID"7
1.35 x ID"12
1.00 x ID"12
5.91 x 1Q-8
Group
method 25
2.94 x ID"7
-
-
-
-
-
S.llxlQ-7
-
-
8.48 x ID"14
-
-
Measured
1.00 x ID"7
-
S.lSxlQ-8
-
-
-
1.67 x ID"7
-
8.13xlQ-8
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 C-69 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Sodium salicylate
Sodium sesquicarbonate
Sodium thiocyanate
Sodium trichloroacetate
Sodium xylenesulfonate
Sorbic acid
Sorbitan sesquioleate
Sorbitan, mono-(9Z)-9-octadecenoate
Sorbitan, monooctadecanoate
Sorbitan, tri-(9Z)-9-octadecenoate
Styrene
Sucrose
CASRN
54-21-7
533-96-0
540-72-7
650-51-1
1300-72-7
110-44-1
8007-43-0
1338-43-8
1338-41-6
26266-58-0
100-42-5
57-50-1
Log Kow
Estimated
2.24
-0.46
0.58
1.44
-0.07
1.62
14.32
5.89
6.1
22.56
2.89
-4.27
Measured
2.26
-
-
1.33
-
1.33
-
-
-
-
2.95
-3.7
Water solubility
Estimate from log Kow
(mg/Lat25°C)
3,808
8.42 x 105
4.36 x 104
1.20 x 104
5.89 x 104
1.94 x 104
2.31 x 1Q-11
0.01914
0.01218
1.12 x 1Q-19
343.7
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.42 x ID"8
6.05 x 1Q-9
1.46 x ID"4
2.39 x 1Q-8
3.06 x 1Q-9
5.72 x ID"7
7.55 x ID"12
1.42 x ID"12
1.61 x ID"12
4.02 x 1Q-11
2.76 x 1Q-3
4.47 x ID"22
Group
method 25
5.60 x ID"12
-
-
-
-
4.99 x ID"8
1.25 x ID"16
5.87 x ID"20
2.23 x 1Q-19
2.68 x 1Q-13
2.81 x 1Q-3
-
Measured
7.34 x ID"9
-
-
1.35 x ID"8
-
-
-
-
-
-
2.75 x ID"3
-
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Sulfan blue
Sulfuric acid, mono-C12-18-alkyl esters,
sodium salts
Sulfuric acid, mono-C6-10-alkyl esters,
ammonium salts
Symclosene
tert-Butyl hydroperoxide
tert-Butyl perbenzoate
Tetradecane
Tetradecyldimethylbenzylammonium
chloride
Tetraethylene glycol
Tetraethylenepentamine
CASRN
129-17-9
68955-19-1
68187-17-7
87-90-1
75-91-2
614-45-9
629-59-4
139-08-2
112-60-7
112-57-2
Log Kow
Estimated
-1.34
3.9
0.46
0.94
0.94
2.89
7.22
3.91
-2.02
-3.16
Measured
-
-
-
-
-
-
7.2
-
-
-
Water solubility
Estimate from log Kow
(mg/Lat25°C)
50.67
5.165
1.58 x 104
4,610
1.97 x 104
159.2
0.009192
3.608
1.00 x 10s
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
1.31 x ID"26
4.29 x ID"7
5.91 x 1Q-8
6.19 x 1Q-11
1.60 x 1Q-5
2.06 x ID"4
1.65 x 101
1.34 x 1Q-11
4.91 x 1Q-13
2.79 x ID"20
Group
method 25
-
-
-
-
-
-
2.68 xlO1
-
5.48 x ID"19
4.15 x ID"23
Measured
-
-
-
-
-
-
9.20
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Tetrakis(hydroxymethyl)phosphonium
sulfate
Tetramethylammonium chloride
Thiamine hydrochloride
Thiocyanic acid, ammonium salt
Thioglycolic acid
Thiourea
Toluene
Tributyl phosphate
Tributyltetradecylphosphonium chloride
Tridecane
Triethanolamine
CASRN
55566-30-8
75-57-0
67-03-8
1762-95-4
68-11-1
62-56-6
108-88-3
126-73-8
81741-28-8
629-50-5
102-71-6
Log Kow
Estimated
-5.03
-4.18
0.95
0.58
0.03
-1.31
2.54
3.82
11.22
6.73
-2.48
Measured
-
-
-
-
0.09
-1.08
2.73
4
-
-
-1
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.00 x 10s
3,018
4.36 x 104
2.56 x 105
5.54 x 105
573.1
7.355
7.90 x ID"7
0.02746
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
9.17xlO-13
4.17 x ID"12
8.24 x 1Q-17
1.46 x ID"4
1.94 x 1Q-8
1.58 x ID"7
5.95 x 1Q-3
3.19 x 1Q-6
2.61 x ID"1
1.24 x 101
4.18xlO-12
Group
method 25
-
-
-
-
-
-
5.73 x ID"3
-
-
1.90 x 101
3.38 x ID"19
Measured
-
-
-
-
-
1.98 x ID"9
6.64 x ID"3
1.41 x 1Q-6
-
2.88
7.05 x ID"13
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Triethanolamine hydrochloride
Triethanolamine hydroxyacetate
Triethyl citrate
Triethyl phosphate
Triethylene glycol
Triethylenetetramine
Triisopropanolamine
Trimethanolamine
Trimethylamine
Tripotassium citrate monohydrate
Tripropylene glycol monomethyl ether
Trisodium citrate
CASRN
637-39-8
68299-02-5
77-93-0
78-40-0
112-27-6
112-24-3
122-20-3
14002-32-5
75-50-3
6100-05-6
25498-49-1
68-04-2
Log Kow
Estimated
-2.48
-2.97
0.33
0.87
-1.75
-2.65
-1.22
-3.95
0.04
-1.67
-0.2
-1.67
Measured
-1
-
-
0.8
-1.75
-
-
-
0.16
-1.64
-
-1.64
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
1.00 x 10s
2.82 x 104
1.12xl04
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.00 x 10s
1.96 x 105
1.00 x 10s
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
4.18xlO-12
6.28 x 1Q-11
6.39 x ID"10
5.83 x ID"7
3.16 x 1Q-11
9.30 x 1Q-17
9.77 x ID"12
1.42 x 1Q-8
3.65 x 1Q-5
8.33 x 1Q-18
2.36 x 1Q-11
8.33 x 1Q-18
Group
method 25
3.38 x ID"19
-
-
-
2.56 x ID"16
6.74 x ID"19
4.35 x 1Q-18
-
1.28 x ID"4
-
4.55 x ID"13
-
Measured
7.05 x ID"13
-
3.84 x ID"9
3.60 x ID"8
-
-
-
-
1.04 x ID"4
4.33 x ID"14
-
4.33 x ID"14
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix C
Chemical name
Trisodium citrate dihydrate
Trisodium ethylenediaminetetraacetate
Trisodium ethylenediaminetriacetate
Tromethamine
Undecane
Urea
Xylenes
CASRN
6132-04-3
150-38-9
19019-43-3
77-86-1
1120-21-4
57-13-6
1330-20-7
Log Kow
Estimated
-1.67
-3.86
-4.32
-1.56
5.74
-1.56
3.09
Measured
-1.64
-
-
-
-
-2.11
3.2
Water solubility
Estimate from log Kow
(mg/Lat25°C)
1.00 x 10s
2.28 x 105
1.00 x 10s
1.00 x 10s
0.2571
4.26 x 105
207.2
Henry's law constant
(atm-m3/mol at 25°C)
Bond
method
8.33 x ID"18
1.17 x 1Q-23
3.58 x ID"20
8.67 x 1Q-13
7.04
3.65 x ID"10
6.56 x 1Q-3
Group
method 25
-
-
-
-
9.52
-
6.14xlQ-3
Measured
4.33 x ID"14
5.77 x 1Q-16
-
-
1.93
1.74 x ID"12
7.18xlQ-3
"--" indicates no information available.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix C
1 The EPI (Estimation Programs Interface) Suite™ (USJiPJLZOlla) is an open-source, Windows®-
2 based suite of physicochemical property and environmental fate estimation programs developed by
3 the EPA's Office of Pollution Prevention Toxics and Syracuse Research Corporation. More
4 information on EPI Suite™ is available at hJlBi66vww^^
5 Although only physicochemical properties from EPI Suite™ are provided here, other sources of
6 information were also consulted. QikProp (Sc^inidin^ej^ZJllZ,) and LeadScope® (Inc11_2012.) are
7 commercial products designed primarily as drug development and screening tools. QikProp is
8 specifically focused on drug discovery and provides predictions for physically significant
9 descriptors and pharmaceutically (and toxicologically) relevant properties useful in predicting
10 ADME (adsorption, distribution, metabolism, and excretion) characteristics of drug candidates.
11 QikProp's use of whole-molecule descriptors that have a straightforward physical interpretation (as
1 2 opposed to fragment-based descriptors).
13 LeadScope® is a program designed for interpreting chemical and biological screening data that can
14 assist pharmaceutical scientists in finding promising drug candidates. The software organizes the
15 chemical data by structural features familiar to medicinal chemists. Graphs are used to summarize
16 the data, and structural classes are highlighted that are statistically correlated with biological
17 activity. It incorporates chemically-based data mining, visualization, and advanced informatics
18 techniques (e.g., prediction tools, scaffold generators). Note that properties generated by QikProp
19 and LeadScope® are generally more relevant to drug development than to environmental
20 assessment
21 Physicochemical properties of chemicals were generated from the two-dimensional (2-D) chemical
22 structures from the EPA National Center for Computational Toxicology's Distributed Structure-
23 Searchable Toxicity (NCCT DSSTox) Database Network in structure- data file (SDF) format. For EPI
24 Suite™ properties, both the desalted and non-desalted 2-D files were run using the program's batch
25 mode (i.e., processing many molecules at once) to calculate environmentally-relevant, chemical
26 property descriptors. The chemical descriptors in QikProp require 3-D chemical structures. For
27 these calculations, the 2-D desalted chemical structures were converted to 3-D using the RebuildSD
28 function in the Molecular Operating Environment software (CCiLlQll). All computed
29 physicochemical properties are added into the structure-data file prior to assigning toxicological
30 properties.
3 1 Both LeadScope® and Qikprop software require input of desalted structures. Therefore, the
32 structures were desalted, a process where salts and complexes are simplified to the neutral,
33 uncomplexed form of the chemical, using "Desalt Batch" option in ACD Labs ChemFolder. All
34 LeadScope® general chemical descriptors (Parent Molecular Weight, AlogP, Hydrogen Bond
35 Acceptors, Hydrogen Bond Donors, Lipinski Score, Molecular Weight, Parent Atom Count, Polar
36 Surface Area, and Rotatable Bonds) were calculated by default
37 All physicochemical properties generated from EPI Suite™, QikProp, and LeadScope® will be made
38 available to the public in an electronic format in 2015.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix C
C.2. References for Appendix C
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix C
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This document is a draft for review purposes only and does not constitute Agency policy.
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix C
Sarkar. BK: Choudhury. A: Sinha. B. (2012). Excess molar volumes, excess viscosities and ultrasonic speeds of
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Solution Chemistry 41: 53-74. http://dx.doi.org/10.1007/sl0953-011-9780-5
Sarkar. L: Roy. MN. (2009). Density, viscosity, refractive index, and ultrasonic speed of binary mixtures of 1,3-
dioxolane with 2-methoxyethanol, 2-ethoxyethanol, 2-butoxyethanol, 2-propylamine, and
cyclohexylamine. Journal of Chemical and Engineering Data 54: 3307-3312.
http://dx.doi.org/10.1021/ie900240s
Schrodinger. (2012). Qikprop [Computer Program]. New York, New York: Schrodinger, LLC. Retrieved from
http://www.schrodinger.com/products/14/17
Shanley. P: Collin. RL. (1961). The crystal structure of the high temperature form of choline chloride. Acta
Cryst 14: 79-80. http://dx.doi.org/10.1107/S0365110X61000292
Sigma-Aldrich. (2007). Material safety data sheet: Tert-butyl hydroperoxide (70% solution in water).
Available online at http://www.orcbs.msu.edu/msds/111607 DLI 027 TERT-BUTYL.PDF
Sigma-Aldrich. (2010). Product information: Sodium chloride. Available online at
https:// www.sigmaaldrich.com/content/dam/sigma-aldrich/docs/Sigma-
Aldrich/Product Information Sheet/s7653pis.pdf
Sigma-Aldrich. (2014a). Material safety data sheet: Phosphorus acid. Available online at
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Sigma-Aldrich. (2015e). Material safety data sheet: Trimethyl borate. Available online at
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Hydraulic Fracturing Drinking Water Assessment Appendix C
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix D
Appendix D
Designing, Constructing, and Testing Wells for
Integrity
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Hydraulic Fracturing Drinking Water Assessment Appendix D
Appendix D. Designing, Constructing, and Testing Wells
for Integrity
1 This appendix presents the goals for the design and construction of oil and gas production wells,
2 the well components used to achieve those goals, and methods for testing well integrity to help
3 verify that the goals for well performance are achieved. This information provides additional
4 background for the well component discussions presented in Chapter 6. Information on the
5 pathways associated with the well that can cause fluid movement into drinking water resources is
6 presented in Chapter 6.
D.I. Design Goals for Well Construction
7 Simply stated, production wells are designed to move oil and gas from the production zone (within
8 the oil and gas reservoir) into the well and then through the well to the surface. There are typically
9 a variety of goals for well design (RenpMJLQJLl), but the main purposes are facilitating the flow of
10 oil and gas from the hydrocarbon reservoirs to the well (production management) while isolating
11 that oil and gas and the hydrocarbon reservoirs from nearby ground water resources (zonal
12 isolation).
13 To achieve these goals, operators design and construct wells to have and maintain mechanical
14 integrity throughout the life of the well. A properly designed and constructed well has two types of
15 mechanical integrity: internal and external. Internal mechanical integrity refers to the absence of
16 significant leakage within the production tubing, casing, or packer. External mechanical integrity
17 refers to the absence of significant leakage along the well outside of the casing.
18 Achieving mechanical integrity involves designing the well components to resist the stresses they
19 will encounter. Each well component must be designed to withstand all of the stresses to which the
20 well will be subjected, including burst pressure, collapse, tensile, compression (or bending), and
21 cyclical stresses (see Section 6.2.1 for additional information on these stresses). Well materials
22 should also be compatible with the fluids (including liquids or gases) with which they come into
23 contact to prevent leaks caused by corrosion.
24 These goals are accomplished by the use of one or more layers of casing, cement, and mechanical
25 devices (such as packers), which provide the main barrier preventing migration of fluids from the
26 well into drinking water sources.
D.2. Well Components
27 Casing and cement are used in the design and construction of wells to achieve the goals of
28 mechanical integrity and zonal isolation. Several industry-developed specifications and best
29 practices for well construction have been established to guide well operators in the construction
30 process; see Text Box D-l. (Information is not available to determine how often these practices are
31 used or how well they prevent the development of pathways for fluid movement to drinking water
32 resources.) The sections below describe options available for casing, cement, and other well
33 components.
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Hydraulic Fracturing Drinking Water Assessment Appendix D
Text Box D-l. Selected Industry-Developed Specifications and Recommended
Practices for Well Construction in North America.
1 American Petroleum Institute (API)
2 • API Guidance Document HF1—Hydraulic Fracturing Operations—Well Construction and Integrity
3 Guidelines [AP!.2009a]
4 • API RP 10B-2-Recommended Practice for Testing Well Cements [API, 2013]
5 • API RP 10D-2-Recommended Practice for Centralizer Placement and Stop Collar Testing [API. 2004]
6 • API RP 5Cl-Recommended Practices for Care and Use of Casing and Tubing [API, 19991
7 • API RP 65-2-Isolating Potential Flow Zones during Well Construction [API, 2010a]
8 • API Specification 10A—Specification on Cements and Materials for Well Cementing [API, 2010b]
9 • API Specification HDl-Packers and Bridge Plugs [API. 2009b1
10 • API Specification 5CT-Specification for Casing and Tubing [API, 20111
11 Canadian Association of Petroleum Producers (CAPP) and Enform
12 • Hydraulic Fracturing Operating Practices: Wellbore Construction and Quality Assurance [CAPP, 20131
13 • Interim Industry Recommended Practice Volume #24—Fracture Stimulation: Inter-wellbore
14 Communication [Enform, 2013]
15 Marcellus Shale Coalition (MSC)
16 • Recommended Practices—Drilling and Completions [MSC. 2013]
D.2.1. Casing
17 Casing is steel pipe that is placed into the wellbore (the cylindrical hole drilled through the
18 subsurface rock formation) to maintain the stability of the wellbore, to transport the hydrocarbons
19 from the subsurface to the surface, and to prevent intrusion of other fluids into the well and
2 0 wellbore. Up to four types of casing may be present in a well, including (from largest to smallest-
21 diameter): conductor casing, surface casing, intermediate casing, and production casing. Each is
22 described below.
2 3 The conductor casing is the largest diameter string of casing. It is typically in the range of 3 0 in.
24 (76 cm) to 42 in. (107 cm) in diameter (Hyne. 2012). Its main purpose is to prevent unconsolidated
25 material, such as sand, gravel, and soil, from collapsing into the wellbore. Therefore, the casing is
26 typically installed from the surface to the top of the bedrock or other consolidated formations. The
27 conductor casing may or may not be cemented in place.
28 The next string of casing is the surface casing. Atypical surface casing diameter is 13.75 in. (34.93
29 cm), but diameter can vary (Hyne. 2012). The surface casing's main purposes are to isolate any
30 ground water resources that are to be protected by preventing fluid migration along the wellbore
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 once the casing is cemented and to provide a sturdy structure to which blow-out prevention
2 equipment can be attached. For these reasons, the surface casing most commonly extends from the
3 surface to some distance beneath the lowermost geologic formation containing ground water
4 resources to be protected. The specific depth to which the surface casing is set is often governed by
5 the depth of the ground water resource as defined and identified for protection in state regulations.
6 Intermediate casing is typically used in wells to control pressure in an intermediate-depth
7 formation. It may be used to reduce or prevent exposure of weak formations to pressure from the
8 weight of the drilling fluid or cement or to allow better control of over-pressured formations. The
9 intermediate casing extends from the surface through the formation of concern. There may be more
10 than one string of concentric intermediate casing present or none at all, depending on the
11 subsurface geology. Intermediate casing may be cemented, especially through over-pressured
12 zones; however, it is not always cemented to the surface. Intermediate casing, when present, is
13 often 8.625 in. (21.908 cm) in diameter but can vary (Hyjie1_2012.).
14 Production casing extends from the surface into the production zone. The main purposes of the
15 production casing are to isolate the hydrocarbon product from fluids in surrounding formations
16 and to transport the product to the surface. It can also be used to inject fracturing fluids, receive
17 flowback during hydraulic fracturing operations (e.g., if tubing or a temporary fracturing string is
18 not present), and prevent other fluids from mixing with and diluting the produced hydrocarbons.
19 The production casing is generally cemented to some point above the production zone. Production
20 casing is often 5.5 in. (14.0 cm) in diameter but can vary (Hyne1_2()12.).
21 Liners are another type of metal tubular (casing-like) well component that can be used to fulfill the
22 same purposes as intermediate and production casing in the production zone. Like casing, they are
2 3 steel pipe, but differ in that they do not extend from the production zone to the surface. Rather, they
24 are connected to the next largest string of casing by a hanger that is attached to the casing. A frac
2 5 sleeve is a specialized type of liner that is used during fracturing. It has plugs that can be opened
26 and closed by dropping balls from the surface (see the discussion of well completions below for
2 7 additional information on the use of frac sleeves).
28 Production tubing is the smallest, innermost steel pipe in the well and is distinguished from casing
29 by not being cemented in place. It is used to transport the hydrocarbons to the surface. Fracturing
30 may be done through the tubing if present, or through the production casing. Because casing cannot
31 be replaced, tubing is often used, especially if the hydrocarbons contain corrosive substances such
32 as hydrogen sulfide or carbon dioxide. Tubing may not be used in high-volume production wells.
33 Typical tubing diameter is between 1.25 in. (3.18 cm) and 4.5 in. (11.4 cm) (HyjieJ_2fil2.).
D.2.2. Cement
34 Cement is the main barrier preventing fluid movement along the wellbore outside the casing. It also
3 5 lends mechanical strength to the well and protects the casing from corrosion by naturally occurring
36 formation fluids. Cement is placed in the annulus, which is the space between two adjacent casings
37 or the space between the outermost casing and the rock formation through which the wellbore was
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 drilled. The sections below describe considerations for selecting cement and additives, as well as
2 cementing procedures and techniques.
D.2.2.1. Considerations for Cementing
3 The length and location of the casing section to be cemented and the composition of the cement can
4 vary based on numerous factors, including the presence and locations of weak formations, over- or
5 under-pressured formations, or formations containing fluids; formation permeability; and
6 temperature. State requirements for oil and gas production well construction and the relative costs
7 of well construction options are also factors.
8 Improper cementing can lead to the formation of channels (small connected voids) in the cement,
9 which can—if they extend across multiple formations or connect to other existing channels or
10 fractures—present path ways for fluid migration. This section describes some of the considerations
11 and concerns for proper cement placement and techniques and materials that are available to
12 address these concerns. Careful selection of cements (and additives) and design of the cementing
13 job can avoid integrity problems related to cement
14 To select the appropriate cement type, properties, and additives, operators consider the required
15 strength needed to withstand downhole conditions and compatibility with subsurface chemistry, as
16 described below:
17 • The cement design needs to achieve the strength required under the measured or
18 anticipated downhole conditions. Factors that are taken into account to achieve proper
19 strength can include density, thickening time, the presence of free water, compressive
20 strength, and formation permeability (Kenj3uJ2j311). Commonly, cement properties are
21 varied during the process, with a "weaker" (i.e., less dense) lead cement, followed by a
22 "stronger" (denser) tail cement. The lead cement is designed with a lower density to
23 reduce pressure on the formation and better displace drilling fluid without a large concern
24 for strength. The stronger tail cement provides greater strength for the deeper portions of
25 the well the operator considers as requiring greater strength.
26 • The compatibility of the cement with the chemistry of formation fluids, hydrocarbons,
2 7 and hydraulic fracturing fluids is important for maintaining well integrity through the life
28 of the well. Most oil and gas wells are constructed using some form of Portland cement.
29 Portland cement is a specific type of cement consisting primarily of calcium silicates with
30 additional iron and aluminum. Industry specifications for recommended cements are
31 determined by the downhole pressure, temperature, and chemical compatibility required.
32 There are a number of considerations in the design and execution of a cement job. Proper
33 centralization of the casing within the wellbore is one of the more important considerations. Others
34 include the potential for lost cement, gas invasion, cement shrinkage, incomplete removal of drilling
35 mud, settling of solids in the wellbore, and water loss into the formation while curing. These
36 concerns, and techniques available to address them, include the following:
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 • Improper centralization of the casing within the wellbore can lead to preferential flow
2 of cement on the side of the casing with the larger space and little to no cement on the side
3 closest to the formation. If the casing is not centered in the wellbore, cement will flow
4 unevenly during the cement job, leading to the formation of cement channels. Kirksey
5 [2013] notes that, if the casing is off-center by just 25%, the cement job is almost always
6 inadequate. Centralizers are used to keep the casing in the center of the hole and allow an
7 even cement job. To ensure proper centralization, centralizers are placed at regular
8 intervals along the casing [API, 2010a]. Centralizer use is especially key in horizontal
9 wells, as the casing will tend to settle (due to gravity) to the bottom of the wellbore if the
10 casing is not centered [Sabins. 1990). leading to inadequate cement on the lower side.
11 • Lost cement (sometimes referred to as lost returns) refers to cement that moves out of
12 the wellbore and into the formation instead of filling up the annulus between the casing
13 and the formation. Lost cement can occur in weak formations that fail (fracture) under
14 pressure of the cement or in particularly porous, permeable, or naturally fractured
15 formations. Lost cement can result in lack of adequate cement across a water- or brine-
16 bearing zone. To avoid inadequate placement of cement due to lost cement, records of
17 nearby wells can be examined to determine zones where lost cement returns occur (API.
18 2009a). If records from nearby wells are not available, cores and logs may be used to
19 identify any high-permeability or mechanically weak formations that might lead to lost
20 cement Steps can then be taken to eliminate or reduce loss of cement to the formation.
21 Staged cementing (see below) can reduce the hydrostatic pressure on the formation and
22 may avoid fracturing weak formations (Lyons and Pligsa. 2004). Additives are also
23 available that will lessen the flow of cement into highly porous formations (API. 2010a: Ali
24 etal.. 2009).
25 • Gas invasion and cement shrinkage during cement setting can also cause channels and
26 poor bonding. During the cementing process, the hydrostatic pressure from the cement
27 column keeps formation gas from entering the cement. As the cement sets (hardens), the
2 8 hydrostatic pressure decreases; if it becomes less than the formation pressure, gas can
29 enter the cement, leading to channels. Cement also shrinks as it sets, which can lead to
30 poor bonding and formation of microannuli. These problems can be avoided by using
31 cement additives that increase setting time or expand to offset shrinkage (McDanieletal.,
32 2014: Wojtanowicz. 2008: Dusseaultetal.. 2000). Foamed cement can help alleviate
33 problems with shrinkage, although care needs to be taken in cement design to ensure the
34 proper balance of pressure between the cement column and formation (API, 2010a).
35 Cement additives are also available that will expand upon contact with certain fluids such
36 as hydrocarbons. These cements, termed self-healing cements, are relatively new but have
37 shown early promise in some fields (Ali etal.. 2009). Rotating the casing during cementing
38 will also delay cement setting. Another technique called pulsation, where pressure pulses
39 are applied to the cement while it is setting, also can delay cement setting and loss of
40 hydrostatic pressure until the cement is strong enough to resist gas penetration (Stein et
41 al.. 2003).
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 • Another important issue is removal of drilling mud. If drilling mud is not completely
2 removed, it can gather on one side of the wellbore and prevent that portion of the
3 wellbore from being adequately cemented. The drilling mud can then be eroded away after
4 the cement sets, leaving a channel. Drilling mud can be removed by circulating a denser
5 fluid (spacer fluid) to flush the drilling mud out fKirksey. 2013: Brufatto etal.. 20031
6 Mechanical devices called scratchers can also be attached to the casing and the casing
7 rotated or reciprocated to scrape drilling mud from the wellbore [Hyne. 2012: Crook.
8 2008]. The spacer fluid, which is circulated prior to the cement to wash the drilling fluid
9 out of the wellbore, must be designed with the appropriate properties and pumped in such
10 a way that it displaces the drilling fluid without mixing with the cement [Kirksey. 2013:
11 API. 2010a: Brufatto etal.. 20031.
12 • Also of concern in horizontal wells is the possibility of solids settling at the bottom of the
13 wellbore and free water collecting at the top of the wellbore. This can lead to channels and
14 poor cement bonding. The cement slurry must be properly designed for horizontal wells to
15 minimize free water and solids settling.
16 • If there is free water in the cement, pressure can cause water loss into the formation,
17 leaving behind poor cement or channels [Jiang etal.. 2012]. In horizontal wells, free water
18 can also accumulate at the top of the wellbore, forming a channel [Sabins. 1990].
19 Minimizing free water in the cement design and using fluid loss control additives can help
20 control loss of water [Ross and King, 2007].
D.2.2.2. Cement Placement Techniques
21 The primary cement job is most commonly conducted by pumping the cement down the inside of
22 the casing, then out the bottom of the casing where it is then forced up the space between the
23 outside of the casing and the formation. (The cement can also be placed in the space between two
24 casings.] If continuous cement (i.e., a sheath of cement placed along the entire wellbore] is
25 desired, cement is circulated through the annulus until cement that is pumped down the central
26 casing flows out of the annulus at the surface. A spacer fluid is often pumped ahead of cement to
27 remove any excess drilling fluid left in the wellbore; even if the operator does not plan to circulate
28 cement to the surface, the spacer fluid will still return to the surface, as this is necessary to remove
29 the drilling mud from the annulus. If neither the spacer fluid nor the cement returns to the surface,
30 this indicates that fluids are being lost into the formation.
31 Staged cementing is a technique that reduces pressure on the formation by decreasing the height
32 (and therefore the weight] of the cement column. This may be necessary if the estimated weight
33 and pressure associated with standard cement emplacement could damage zones where the
34 formation intersected is weak. The reduced hydrostatic pressure at the bottom of the cement
35 column can also reduce the loss of water to permeable formations, improving the quality of the
36 cement job. In multiple-stage cementing, cement is circulated to just below a cement collar placed
37 between two sections of casing. A cement collar will have been placed between two sections of
38 casing, just above, with ports that can be opened by dropping a weighted tool. Two plugs—which
39 are often referred to as bombs or darts because of their shape—are then dropped. The first plug is
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 dropped, once the desired cement for the first stage has been pushed out of the casing by a spacer
2 fluid. It closes the section of the well below the cement collar and stops cement from flowing into
3 the lower portion of the well. The second plug (or opening bomb) opens the cement ports in the
4 collar, allowing cement to flow into the annulus between the casing and formation. Cement is then
5 circulated down the wellbore, out the cement ports, into the annulus, and up to the surface. Once
6 cementing is complete, a third plug is dropped to close the cement ports, preventing the newly
7 pumped cement from flowing back into the well (J^ronjLiniiJB^^ see Figure D-l.
8 Another less commonly used primary cementing technique is reverse circulation cementing. This
9 technique has been developed to decrease the force exerted on weak formations. In reverse
10 circulation cementing, the cement is pumped down the annulus directly between the outside of the
1 1 outermost casing and the formation. This essentially allows use of lower density cement and lower
1 2 pumping pressures. With reverse circulation cementing, greater care must be taken in calculating
1 3 the required cement, ensuring proper cement circulation, and locating the beginning and end of the
14 cemented portion.
15 Another method used to cement specific portions of the well without circulating cement along the
1 6 entire wellbore length is to use a cement basket. A cement basket is a device that attaches to the
1 7 well casing. It is made of flexible material such as canvas or rubber that can conform to the shape of
1 8 the wellbore. The cement basket acts as a one-way barrier to cement flow. Cement can be circulated
19 up the wellbore past the cement basket, but when circulation stops the basket prevents the cement
2 0 from falling back down the wellbore. Cement baskets can be used to isolate weak formations or
2 1 formations with voids. They can also be placed above large voids such as mines or caverns with
2 2 staged cementing used to cement the casing above the void.
23 If any deficiencies are identified, remedial cementing may be performed. The techniques available
24 to address deficiencies in the primary cement job including cement squeezes or top-job cementing.
25 A cement squeeze injects cement under high pressure to fill in voids or spaces in the primary
26 cement job caused by high pressure, failed formations, or improper removal of drilling mud.
27 Although cement squeezes can be used to fix deficiencies in the primary cement job, they require
28 the well to be perforated, which can weaken the well and make it susceptible to degradation by
29 pressure and temperature cycling as would occur during fracturing (Crescent,_2011). Another
30 method of secondary cementing is the top job. In a top job, cement is pumped down the annulus
31 directly to fill the remaining uncemented space when cement fails to circulate to the surface.
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Hydraulic Fracturing Drinking Water Assessment
Appendix D
Second-stage slurry
Second-stage flow path
Circulating ports
Cement collar
Opening bomb
First-stage slurry
First-stage flow path
Note: Figure not to scale
Two-Stage Cementing Process
Figure D-l. A typical staged cementing process.
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Hydraulic Fracturing Drinking Water Assessment
Appendix D
D.3. Well Completions
1 Completion refers to how the well is prepared for production and how flow is established between
2 the formation and the surface. Figure D-2 presents examples of well completion types, including
3 cased, formation packer, and open hole completion.
Legend
Cement
Casing
Wellbore
Induced fracture
Cemented Casing
Completion
Fracture stage
Perforations
1111
Vd
Formation Packer
Completion
Fracture stage
^^~ EJ CT B8 E8 E8^
Open Hole
Completion
Fracture stage
HfTT
\
Packer
Note: Nottoscale. Conductor casing not shown.
Figure D-2. Examples of well completion types.
Configurations shown include cased, formation packer, and open hole completion. From U.S.
EPA(2015f).
4 A cased completion, where the casing extends to the end of the wellbore and is cemented in place,
5 is the most common configuration of the well in the production zone [U.S. EPA. 2015Q. Perforations
6 are made through the casing and cement and into the formation using small explosive charges
7 called "perf guns" or other devices, such as sand jets. Hydraulic fracturing then is conducted
8 through the perforations. This is a common technique in wells that produce from several different
9 depths and in low-permeability formations that are fractured [Renpu. 2011). While perforations do
10 control the initiation point of the fracture, this can be a disadvantage if the perforations are not
11 properly aligned with the local stress field. If the perforations are not aligned, the fractures will
12 twist to align with the stress field, leading to tortuosity in the fractures and making fluid movement
13 through them more difficult [Cramer, 2008]. Fracturing stages can be isolated from each other
14 using various mechanisms such as plugs or baffle rings, which close off a section of the well when a
15 ball of the correct size is dropped down the well.
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1 A packer is a mechanical device used to selectively seal off certain s ections of the wellbore.
2 Packers can be used to seal the space between the tubing and casing, between two casings, or
3 between the production casing and formation. The packer has one or more rubber elements that
4 can be manipulated downhole to increase in diameter and make contact with the inner wall of the
5 next-largest casing or the formation, effectively sealing the annulus created between the outside of
6 the tubing and the inside of the casing. Packers vary in how they are constructed and how they are
7 set, based on the downhole conditions in which they are used. There are two types of packers:
8 internal packers and formation packers. Internal packers are used to seal the space between the
9 casing and tubing or between two different casings. They isolate the outer casing layers from
10 produced fluids and prevent fluid movement into the annulus. Formation packers seal the space
11 between the casing and the formation and are often used to isolate fracture stages; they can be used
12 to separate an open hole completion into separate fracture stages. Packers can seal an annulus by
13 several different mechanisms. Mechanical packers expand mechanically against the formation and
14 can exert a significant force on the formation. Swellable packers have elastomer sealing elements
15 that swell when they come into contact with a triggering fluid such as water or hydrocarbons. They
16 exert less force on the formation and can seal larger spaces but take some time to fully swell
17 Internal mechanical integrity tests such as pressure tests can verify
18 that the packer is functioning as designed and has not corroded or deteriorated.
19 In an open hole completion, the production casing extends just into the production zone and the
20 entire length of the wellbore through the production zone is left uncased. This is only an option in
21 formations where the wellbore is stable enough to not collapse into the wellbore. In formations that
22 are unstable, a slotted liner may be used in open hole completions to control sand production
23 (Rejipu^JLQll). Perforations are not needed in an open hole completion, since the production zone
24 is not cased. An open hole completion can be fractured in a single stage or in multiple stages.
25 If formations are to be fractured in stages, additional completion methods are needed to separate
26 the stages from each other and control the location of the fractures. One possibility is use of a liner
27 with formation packers to isolate each stage. The liner is equipped with sliding sleeves that can be
28 opened by dropping balls down the casing to open each stage. Fracturing typically occurs from the
29 end of the well and continues toward the beginning of the production zone.
D.4. Mechanical Integrity Testing
30 While proper design and construction of the well's casing and cement are important, it is also
31 important to verify the well was constructed and is performing as designed. Mechanical integrity
32 tests (MITs) can verify that the well was constructed as planned and can detect damage to the
33 production well that occurs during operations, including hydraulic fracturing activities. Verifying
34 that a well has mechanical integrity can prevent potential impacts to drinking water resources by
35 providing early warning of a problem with the well or cement and allowing repairs.
36 It is important to note that if a well fails an MIT, this does not mean the well has failed or that an
37 impact on drinking water resources has occurred. An MIT failure is a warning that one or more
38 components of the well are not performing as designed and is an indication that corrective actions
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 are necessary. If well remediation is not performed, a loss of well integrity could occur, which could
2 result in fluid movement from the well.
D.4.1. Internal Mechanical Integrity
3 Internal mechanical integrity is an absence of significant leakage in the tubing, casing, or packers
4 within the well system. Loss of internal mechanical integrity is usually due to corrosion or
5 mechanical failure of the well's tubular and mechanical components.
6 Internal mechanical integrity can be tested by the use of pressure testing, annulus pressure
7 monitoring, ultrasonic monitoring, and casing inspection logs or caliper logs:
8 • Pressure testing involves raising the pressure in the wellbore to a set level and shutting
9 in the well. If the well has internal mechanical integrity, the pressure should remain
10 constant with only small changes due to temperature fluctuation. Typically, the well is
1 1 shut in (i.e., production is stopped and the wellhead valves closed) for half an hour, and if
12 the pressure remains within 5% of the original reading, the well is considered to have
13 passed the test Usually, the well is pressure tested to the maximum expected pressure; for
14 a well to be used for hydraulic fracturing this would be the pressure applied during
15 hydraulic fracturing. Pressure tests, however, can cause debonding of the cement from the
16 casing, so test length is often limited to reduce this effect (APL_2010a).
17 • If the annulus between the tubing and casing is sealed by a packer, annulus pressure
1 8 monitoring can give an indication of the integrity of the tubing and casing. If the tubing,
19 casing, and packer all have mechanical integrity, the pressure in the annulus should not
20 change except for small changes in response to temperature fluctuations. The annulus can
21 be filled with a non-corrosive liquid and the level of the liquid can be used as another
22 indication of the integrity of the casing, tubing, and packer. The advantage of monitoring
23 the tubing/production casing annulus is it can give a continuous, real-time indication of
24 the internal integrity of the well. Even if the annulus is not filled with a fluid, monitoring its
25 pressure can indicate leaks. If pressure builds up in the annulus and then recovers quickly
2 6 after having bled off, that condition is referred to as sustained casing pressure or surface
27 casing vent flow and is a sign of a leak in the tubing or casing
28 Monitoring of annuli between other sets of casings can also provide information on the
29 integrity of those casings. It can also provide information on external mechanical integrity
30 for annuli open to the formation (see Section D.4.2 for additional information on external
3 1 MITs). Ja£ksOTLeLiljllll3J also note that monitoring annular pressure allows the
32 operator to vent gas before it accumulates enough pressure to cause migration into
33 drinking water resources. Measuring annulus flow rate also allows detection of gas
34 flowing into the annulus (
35 • A newer tool uses ultrasonic monitors to detect leaks in casing and other equipment It
3 6 measures the attenuation of an ultrasonic signal as it is transmitted through the wellbore.
37 The tool measures transmitted ultrasonic signals as it is lowered down the wellbore. The
38 tool can pick up ultrasonic signals created by the leak, similar to noise logs. The tool only
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 has a range of a few feet but is claimed to detect leaks as small as half a cup per minute
2 (JuiiajlJ^^
3 • Caliper logs have mechanical fingers that extend from a central tool and measure the
4 distance from the center of the wellbore to the side of the casing. Running a caliper log can
5 identify areas where corrosion has altered the diameter of the casing or where holes have
6 formed in the casing. Caliper logs may also detect debris or obstructions in the well. Casing
7 inspection and caliper logs are primarily used to determine the condition of the casing.
8 Regular use of them may identify problems such as corrosion and allow mitigation before
9 they cause of loss of integrity to the casing. To run these logs in a producing well, the
10 tubing must first be pulled.
11 • Casing inspection logs are instruments lowered into the casing to inspect the casing for
12 signs of wear or corrosion. One type of casing log uses video equipment to detect
13 corrosion or holes. Another type uses electromagnetic pulses to detect variations in metal
14 thickness. Running these logs in a producing well requires the tubing to be pulled.
15 If an internal mechanical integrity problem is detected, first, the location of the problem must be
16 found. Caliper or casing inspection logs can detect locations of holes in casing. Locations of leaks
17 can also be detected by sealing off different sections of the well using packers and performing
18 pressure tests on each section until the faulty section is located. If the leaks are in the tubing or a
19 packer, the problem may be remedied by replacing the well component Casing leaks may be
20 remedied by performing a cement squeeze (see the section on cementing).
D.4.2. External Mechanical Integrity
21 External well mechanical integrity is demonstrated by establishing the absence of significant fluid
22 movement along the outside of the casing, either between the outer casing and cement or between
23 the cement and the wellbore. Failure of an external MIT can indicate improper cementing or
24 degradation of the cement emplaced in the annular space between the outside of the casing and the
25 wellbore. This type of failure can lead to movement of fluids out of intended production zones and
26 toward drinking water resources.
27 Several types of logs are available to evaluate external mechanical integrity, including temperature
2 8 logs, noise logs, oxygen activation logs, radioactive tracer logs, and cement evaluation logs.
29 • Temperature logs measure the temperature in the wellbore. They are capable of
3 0 measuring small changes in temperature. They can be performed using instruments that
31 are lowered down the well on a wireline or they can be done using fiber optic sensors
3 2 permanently installed in the well. When performed immediately after cementing, they can
3 3 detect the heat from the cement setting and determine the location of the top of cement.
34 After the cement has set, temperature logs can sense the difference in temperatures
35 between formation fluids and injected or produced fluids. They may also detect
36 temperature changes due to cooling or warming caused by flow. In this way temperature
37 logs may detect movement of fluid outside the casing in the wellbore (ArthyrJMll).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix D
1 Temperature logs require interpretation of the causes of temperature changes and are
2 therefore subject to varying results among different users.
3 • Noise logs are sensitive microphones that are lowered down the well on a wireline. They
4 are capable of detecting small noises caused by flowing fluids, such as fluids flowing
5 through channels in the cement [Arthur. 2012]. They are most effective at detecting fast-
6 moving gas leaks and less successful with more slowly moving liquid migration.
7 • Oxygen activation logs consist of a neutron source and one or more detectors that are
8 lowered on a wireline. The neutron source bombards oxygen molecules surrounding the
9 wellbore and converts them into unstable nitrogen molecules that rapidly decay back to
10 oxygen, emitting gamma radiation in the process. Gamma radiation detectors above or
11 below the neutron source measure how quickly the oxygen molecules are moving away
12 from the source, thereby determining flow associated with water.
13 • Radioactive tracer logs involve release of a radioactive tracer and then passing a
14 detector up or down the wellbore to measure the path the tracers have taken. They can be
15 used to determine if fluid is flowing up the wellbore. Tracer logs can be very sensitive but
16 may be limited in the range over which leaks can be detected.
17 • Cement evaluation logs (also known as cement bond logs) are acoustic logs consisting of
18 an instrument that sends out acoustic signals along with receivers, separated by some
19 distance, that record the acoustic signals. As the acoustic signals pass through the casing
20 they will be attenuated to an extent, depending on whether the pipe is free or is bonded to
21 cement. By analyzing the return acoustic signal, the degree of cement bonding with the
2 2 casing can be determined. The cement evaluation log measures the sound attenuation as
2 3 sound waves passing through the cement and casing. There are different types of cement
24 evaluation logs available. Some instruments can only return an average value over the
2 5 entire wellbore. Other instruments are capable of measuring the cement bond radially.
2 6 Cement logs do not actually determine whether fluid movement through the annulus is
2 7 occurring. They only can determine whether cement is present in the annulus and in some
2 8 cases can give a qualitative assessment of the quality of the cement in the annulus. Cement
29 evaluation logs are used to calculate a bond index which varies between 0 and 1, with 1
3 0 representing the strongest bond and 0 representing the weakest bond.
31 If the well fails an external MIT, damaged or missing cement may be repaired using a cement
32 squeeze (Wojtanowicz. 2008]. A cement squeeze involves injection of cement slurry into voids
33 behind the casing or into permeable formations. Different types of cement squeezes are available
34 depending on the location of the void needing to be filled and well conditions [Kirksey. 2013].
35 Cement squeezes are not always successful, however, and may need to be repeated to successfully
36 seal off flow [Wojtanowicz. 2008].
D.5. References for Appendix D
AM, M: Taoutaou, S: Shafqat, AD: Salehapour, A: Noor, S. (2009]. The use of self healing cement to ensure long
term zonal isolation for HPHT wells subject to hydraulic fracturing operations in Pakistan. Paper
presented at International Petroleum Technology Conference, December 7-9,2009, Doha, Qatar.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 D-13 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix D
API (American Petroleum Institute). (1999). Recommended practice for care and use of casing and tubing
[Standard] (18th ed.). (API RP 5C1). Washington, DC: API Publishing Services.
API (American Petroleum Institute). (2004). Recommended practice for centralizer placement and stop collar
testing (First ed.). (API RP 10D-2 (R2010)).
API (American Petroleum Institute). (2009a). Hydraulic fracturing operations - Well construction and
integrity guidelines [Standard] (First ed.). Washington, DC: API Publishing Services.
API (American Petroleum Institute). (2009b). Packers and bridge plugs (Second ed.). (API Spec 11D1).
API (American Petroleum Institute). (2010a). Isolating potential flow zones during well construction
[Standard] (1st ed.). (RP 65-2). Washington, DC: API Publishing Services.
http://www.techstreet.com/products/preview/1695866
API (American Petroleum Institute). (2010b). Specification for cements and materials for well cementing
[Standard] (24th ed.). (ANSI/API SPECIFICATION 10A). Washington, DC: API Publishing Services.
http://www.techstreet.com/products/1757666
API (American Petroleum Institute). (2011). Specification for casing and tubing - Ninth edition [Standard]
(9th ed.). (API SPEC 5CT). Washington, DC: API Publishing Services.
http://www.techstreet.com/products/1802047
API (American Petroleum Institute). (2013). Recommended practice for testing well cements [Standard] (2nd
ed.). (RP 10B-2). Washington, DC: API Publishing Services.
http://www.techstreet.com/products/1855370
Arthur. ID. (2012). Understanding and assessing well integrity relative to wellbore stray gas intrusion issues.
Presentation presented at Ground Water Protection Council Stray Gas - Incidence & Response Forum, July
24-26,2012, Cleveland, OH.
Brufatto. C: Cochran. I: Conn. L: El-Zeghaty. SZA. A: Fraboulet. B: Griffin. T: lames. S: Munk. T: lustus. F: Levine.
IR: Montgomery. C: Murphy. D: Pfeiffer. I: Pornpoch. T: Rishmani. L. (2003). From mud to cement -
Building gas wells. Oilfield Rev 15: 62-76.
CAPP (Canadian Association of Petroleum Producers). (2013). CAPP hydraulic fracturing operating practice:
Wellbore construction and quality assurance. (2012-0034).
http://www.capp.ca/getdoc.aspx?DocId=218137&DT=NTV
Cramer. DP. (2008). Stimulating unconventional reservoirs: Lessons learned, successful practices, areas for
improvement. SPE Unconventional Reservoirs Conference, February 10-12, 2008, Keystone, CO.
Crescent (Crescent Consulting, LLC). (2011). East Mamm creek project drilling and cementing study.
Oklahoma City, OK. http://cogcc.state.co.us/Library/PiceanceBasin/EastMammCreek/ReportFinal.pdf
Crook, R. (2008). Cementing: Cementing horizontal wells. Halliburton.
Dusseault. MB: Gray. MN: Nawrocki. PA. (2000). Why oilwells leak: Cement behavior and long-term
consequences. Paper presented at SPE International Oil and Gas Conference and Exhibition in China,
November 7-10, 2000, Beijing, China.
Enform. (2013). Interim industry recommended practice 24: fracture stimulation: Interwellbore
communication 3/27/2013 (1.0 ed.). (IRP 24). Calgary, Alberta: Enform Canada.
http://www.enform.ca/safety resources/publications/PublicationDetails.aspx?a=29&type=irp
Hyne, Nl. (2012). Nontechnical guide to petroleum geology, exploration, drilling and production. In
Nontechnical guide to petroleum geology, exploration, drilling and production (3 ed.). Tulsa, OK: PennWell
Corporation.
Jackson. RE: Gorody. AW: Mayer. B: Roy. IW: Ryan. MC: Van Stempvoort. DR. (2013). Groundwater protection
and unconventional gas extraction: the critical need for field-based hydrogeological research. Ground
Water 51: 488-510. http://dx.doi.org/10.llll/gwat.12074
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 D-14 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix D
liang. L: Guillot. D: Meraji. M: Kumari. P: Vidick. B: Duncan. B: Gaafar. GR: Sansudin. SB. (2012). Measuring
isolation integrity in depleted reservoirs. SPWLA 53rd Annual Logging Symposium, June 16-20, 2012,
Cartagena, Colombia.
lulian. IY: King. GE: lohns. IE: Sack. IK: Robertson. DB. (2007). Detecting ultrasmall leaks with ultrasonic leak
detection, case histories from the North Slope, Alaska. Paper presented at International Oil Conference and
Exhibition in Mexico, June 27-30, 2007, Veracruz, Mexico.
Kirksey, I. (2013). Optimizing wellbore integrity in well construction. Presentation presented at North
American Wellbore Integrity Workshop, Octoberl6-17,2013, Denver, CO.
Lyons, WC: Pligsa, Gl. (2004). Standard handbook of petroleum and natural gas engineering (2nd ed.).
Houston, TX: Gulf Professional Publishing, http://www.elsevier.com/books/standard-handbook-of-
petroleum-and-natural-gas-engineering/lyons-phd-pe/978-0-7506-7785-l
McDaniel. BW: Rispler. KA. (2009). Horizontal wells with multistage fracs prove to be best economic
completion for many low permeability reservoirs. Paper presented at SPE Eastern Regional Meeting,
September 23-15, 2009, Charleston, WV.
McDaniel. I: Watters. L: Shadravan. A. (2014). Cement sheath durability: Increasing cement sheath integrity to
reduce gas migration in the Marcellus Shale Play. In SPE hydraulic fracturing technology conference
proceedings. Richardson, TX: Society of Petroleum Engineers. http://dx.doi.org/10.2118/168650-MS
MSC (Marcellus Shale Coalition). (2013). Recommended practices: Drilling and completions. (MSC RP 2013-
3). Pittsburgh, Pennsylvania.
Renpu. W. (2011). Advanced well completion engineering (Third ed.). Houston, TX: Gulf Professional
Publishing.
Ross. D: King. G. (2007). Well completions. In MJ Economides; T Martin (Eds.), Modern fracturing: Enhancing
natural gas production (1 ed., pp. 169-198). Houston, Texas: ET Publishing.
Sabins. F. (1990). Problems in cementing horizontal wells. J Pet Tech 42: 398-400.
http://dx.doi.org/10.2118/20005-PA
Stein, D: Griffin Jr. Tl: Dusterhoft, D. (2003). Cement pulsation reduces remedial cementing costs. GasTIPS 9:
22-24.
U.S. EPA (U.S. Environmental Protection Agency). (2015f). Review of well operator files for hydraulically
fractured oil and gas production wells: Well design and construction [EPA Report]. (EPA/601/R-14/002).
Washington, D.C.: Office of Research and Development, U.S. Environmental Protection Agency.
Watson. TL: Bachu. S. (2009). Evaluation of the potential for gas and C02 leakage along wellbores. SPE
Drilling & Completion 24:115-126. http://dx.doi.org/10.2118/106817-PA
Wojtanowicz, AK. (2008). Environmental control of well integrity. In ST Orszulik (Ed.), Environmental
technology in the oil industry (pp. 53-75). Houten, Netherlands: Springer Netherlands.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
Appendix E
Flowback and Produced Water Supplemental
Tables and Information
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
Appendix E. Flowback and Produced Water
Supplemental Tables and Information
E.I. Flowback and Long-Term Produced Water Volumes
1 The EPA estimates of flowback volumes and long-term produced water volumes used to
2 generate the summaries appearing in Table 7-3 of Chapter 7 appear below in Table E-l.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-l. Flowback and long-term produced water characteristics for wells in unconventional formations, formation-level data.
Source:
Basin
Anadarko
Appalachian
Arkoma
Denver-
Julesburg
Resource
Type
Shale
Tight
Shale
Shale
Shale
Tight
Unconventional
Formation
Woodford
Cleveland
Granite Wash
Mississippi Lime
Marcellus
Utica
Fayetteville
Niobrara
Codell
Codell-Niobrara
Drill
Type
H
H
V
H
V
H
H
V
H
H
H
V
D
V
H
D
V
Fracturing Fluid
(Mgal)
Median
4.7
0.81
0.69
6.2
0.56
1.8
4.4
2.6
4.0
5.1
2.6
0.32
0.28
0.27
2.6
0.45
0.30
Range
1.0-12
0.2-4.0
0.11-3
0.2-9.4
0.05-3
0.82-2.4
0.9-11
0.53-6.6
1.0-11
1.7-11
0.73-3.4
0.27-3.3
0.21-0.46
0.13-0.46
0.15-2.7
0.21-0.47
0.13-0.46
Number of
Data Points
2,239
144
4
77
26
428
14,010
66
150
1,668
69
367
78
185
62
116
592
Flowback
(% of Fracturing Fluid Returned)
Median
34
-
-
-
-
-
7
40
4
-
13
11
-
-
7
-
-
Range3
20-50
12-40
-
7-22
-
50
4-47
21-60
2-27
10-20
6-25
7-35
-
-
-
-
-
Number of
Data Points
3
2
2
2
2
1
4,374
7
73
2
16
9
0
0
32
0
0
Long-Term Produced Water Rates
(gpd)
Median
5,500
82
32
1,300
500
-
860
230
510
430
680
340
-
-
34
-
29
Rangeb
3,200-6,400
20-300
6.6-170
0-2,200
170-1,300
37,000-120,000
54-13,000
100-1,200
210-1,200
150-2,300
260-810
240-600
-
-
19-140
-
13-65
Number of
Data Points
198
571
390
273
2,413
4
4,984
714
82
2,305
250
5,474
0
0
32
0
1,677
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Basin
Denver-
Julesburg,
cont.
Fort Worth
Green River
Green River,
cont.
Illinois
Michigan
Permian
Resource
Type
Tight
cont.
Shale
Shale
Tight
Shale
Shale
Shale
Unconventional
Formation
Muddy J
Barnett
Hilliard-Baxter-
Mancos
Lance
Mesaverde
New Albany
Antrim
Avalon & Bone
Spring
Barnett-
Woodford
Drill
Type
D
V
H
V
H
V
D
D
V
H
V
D
H
H
Fracturing Fluid
(Mgal)
Median
0.59
0.28
3.6
1.3
1.7
1.3
1.2
0.23
0.17
--
--
2.2
1.1
2.1
Range
.025-0.62
0.16-0.62
1-7.3
0.4-1.9
1.0-5.6
0.81-3.5
0.76-1.9
0.16-0.31
0.081-
0.29
-
0.05
0.94-4.5
0.73-2.8
0.5-4.5
Number of
Data Points
162
292
23,917
3,589
2
29
180
73
14
0
1
20
17
2
Flowback
(% of Fracturing Fluid Returned)
Median
-
-
30
-
-
3
6
8
21
-
-
13
-
-
Range3
-
-
21-40
-
-
1-50
1-17
0-37
6-83
-
25-75
5-31
-
-
Number of
Data Points
0
0
11
0
0
31
170
61
11
0
2
16
0
0
Long-Term Produced Water Rates
(gpd)
Median
230
55
920
250
37
410
860
190
290
-
-
950
0
-
Rangeb
64-390
9.3-500
160-4,200
170-580
15-58
250-580
360-1,200
150-440
140-610
2,900
4,600
220-2,400
0-2,300
-
Number of
Data Points
3
129
10,349
3,318
7
1,050
1,140
445
1,081
2
1
183
37
0
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Basin
Permian,
cont.
San Juan
TX-LA-MS
Resource
Type
Shale,
cont.
Tight
Tight
Shale
Tight
Unconventional
Formation
Devonian (TX)
Wo If camp
Spraberry
Mesaverde (San
Juan)
Dakota
Bossier
Haynesville
Cotton Valley
Drill
Type
H
V
H
D
V
V
D
V
D
H
V
D
H
V
H
D
V
Fracturing Fluid
(Mgal)
Median
0.32
0.27
1.4
1.3
0.81
--
--
0.2
0.12
2.7
0.4
0.28
5.3
0.61
4.2
.48
.28
Range
0.13-0.89
0.12-1.0
1.1-3.9
0.26-1.7
0.078-1.7
1.0
-
0.063-
0.22
0.07-0.3
1.7-3.6
0.19-1.7
0.13-0.8
0.95-15
.14-3.5
.25-6.0
.084-4.0
.019-.94
Number of
Data Points
10
16
55
12
60
1
0
19
52
2
16
21
3,222
9
30
24
76
Flowback
(% of Fracturing Fluid Returned)
Median
-
-
-
16
-
-
-
-
4
-
-
-
5
-
-
-
-
Range3
-
-
-
15-20
-
-
-
-
1-40
-
-
-
5-30
-
<60
<60
<60
Number of
Data Points
0
0
0
3
0
0
0
0
30
0
0
0
3
0
2
2
2
Long-Term Produced Water Rates
(gpd)
Median
880
400
3,000
310
910
870
18
65
160
750
470
320
1,700
210
770
950
640
Rangeb
310-1,800
150-3,000
210-19,000
22-8,700
130-1,700
100-4,000
12-260
29-120
41-370
610-1,200
180-1,100
130-1,300
84-1,800
56-850
130-2,700
630-1,800
370-1,800
Number of
Data Points
381
162
104
259
926
66
48
6
379
25
1,203
253
1,249
263
335
1801
10,717
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Basin
TX-LA-MS,
cont.
Western Gulf
Williston
Resource
Type
Tight,
cont.
Shale
Tight
Unconventional
Formation
Travis Peak
Eagle Ford
Pearsall
Austin Chalk
Vicksburg
Wilcox Lobo
Olmos
Bakken
Drill
Type
H
V
H
V
H
H
V
D
H
V
D
V
H
V
Fracturing Fluid
(Mgal)
Median
3.0
0.9
5.0
2.9
3.7
0.94
.016
0.11
2.1
0.21
.058
--
2.0
1.1
Range
0.25-6
0.2-4
1.0-14
2.0-4.1
3.3-4.1
0.58-1.3
0.084-0.6
0.1-0.13
0.66-2.6
0.06-0.6
.056-.076
0.15
0.35-10
.35-2.9
Number of
Data Points
2
2
2,485
9
2
15
20
4
4
14
3
2
2,203
12
Flowback
(% of Fracturing Fluid Returned)
Median
-
-
4
-
-
-
-
-
-
-
-
-
19
-
Range3
-
-
2-8
-
-
-
-
-
-
-
-
-
5-47
-
Number of
Data Points
0
0
1,800
0
0
0
0
0
0
0
0
0
206
0
Long-Term Produced Water Rates
(gpd)
Median
200
980
110
-
200
720
1,000
-
330
620
-
-
680
1,000
Rangeb
39-1,700
330-1,800
9.1-250
-
54-370
290-2,400
650-1,900
-
62-740
330-1,400
-
-
380-1,500
340-3,100
Number of
Data Points
5
1,380
498
0
12
1,097
937
0
77
1,514
0
0
1,739
222
"--" indicates no data; H, horizontal well; D, directional well; V, vertical well.
a For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a median value.
b For some formations, the number of data points was not reported in the data source. In these instances, the EPA reported the number of data points as equal to one, even if
the source reported a range and median value.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
E.2. Produced Water Content
E.2.1. Introduction
1 In the main text of Chapter 7, we describe aspects of flowback and produced water composition,
2 including temporal changes in water quality parameters of flowback (Section 7.5) and major classes
3 of compounds in produced water (Section 7.6). In section 7.7 we describe variability as occurring
4 on three levels: between different rock types (e.g., coal vs. sandstone), between formations
5 composed of the same rock types (e.g., Barnett Shale vs. Bakken Shale), and within formations of
6 the same rock type (e.g., northeastern vs. southwestern Marcellus Shale). In this appendix we
7 present data from the literature which illustrates the differences among these three variability
8 levels.
E.2.2. General Water Quality Parameters
9 As noted in Chapter 7, the EPA identified data characterizing the content of unconventional
10 flowback and produced water in a total of 12 shale and tight formations and coalbed methane
11 (CBM) basins. These formations and basins span 18 states. Note that in this subsection we treat all
12 fluids as produced water. As a consequence, the variability of reported concentrations is likely
13 higher than if the data could be standardized to a specific point on the flowback-to-produced water
14 continuum. Table E-2 and Table E-3 provide supporting data on general water quality parameters
15 of produced water for 12 formations.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 E-6 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-2. Reported concentrations of general water quality parameters in produced water for unconventional shale and tight
formations, presented as: average (minimum-maximum) or median (minimum-maximum).
Parameter
States
Acidity
Alkalinity
Ammonium
Bicarbonate
Biochemical
oxygen
demand
(BOD)
Carbonate
Chloride
Chemical
oxygen
demand
Units
n/a
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Shales
Bakken3
MT, ND
-
-
-
291
(122-610)
-
-
119,000
(90,000-
133,000)
-
Barnettb
TX
NC
(ND-ND)
725
(215-1,240)
-
-
582
(101-2,120)
-
34,700
(9,600-
60,800)
2,945
(927-3,150)
Fayettevillec
AR
-
1,347
(811-1,896)
-
-
-
-
9,156
(5,507-
12,287)
-
Marcellus
PAd
NC
(<5-473)
165
(8-577)
-
-
-
-
57,447
(64-
196,000)
15,358
(195-
36,600)
PA, WVe
162
(5-925)
99.8
(7.5-577)
-
-
141
(2.8-12,400)
-
49,000
(64.2-
196,000)
4,670
(195-
36,600)
Tight formations
Cotton Valley
Group'
LA, TX
-
-
89
(40-131)
-
-
-
101,332
(3,167-
221,498.7)
-
Devonian
Sandstone6
PA
-
99
(43-194)
-
524
(ND-8,440)
-
-
132,567
(58,900-
207,000)
-
Mesaverde'
CO, NM, UT,
WY
-
-
-
2,230
(1,281-13,650)
-
227
(ND-1,680)
4,260
(8-
75,000)
-
Oswego'
OK
-
582
(207-1,220)
-
-
-
-
44,567
(23,000-
75,000)
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Parameter
States
DO
DOC
Hardness as
CaCO3
Oil and
grease
pH
Specific
conductivity
Specific
gravity
IDS
Total
Kjeldahl
nitrogen
Units
n/a
mg/L
mg/L
mg/L
mg/L
SU
|oS/cm
--
mg/L
mg/L
Shales
Bakken3
MT, ND
-
-
-
-
5.87
(5.47-6.53)
213,000
(205,000-
220,800)
1.13
(1.0961-
1.155)
196,000
(150,000-
219,000)
-
Barnettb
TX
-
11.2
(5.5-65.3)
5,800
(3,500-21,0
00)
163.5
(88.2-
1,430)
7.05
(6.5-7.2)
111,500
(34,800-
179,000)
-
50,550
(16,400-
97,800)
171
(26-298)
Fayettevillec
AR
-
-
-
-
-
-
-
13,290
(9,972-
15,721)
-
Marcellus
PAd
-
-
34,000
(630-
95,000)
74
(5-802)
6.6
(5.1-8.4)
-
-
106,390
(680-
345,000)
-
PA, WVe
-
117
(3.3-5,960)
25,000
(156-
106,000)
16.85
(4.7-802)
6.5
(4.9-7.9)
183,000
(479-
763,000)
-
87,800
(680-
345,000)
94.9
(5.6-312)
Tight formations
Cotton Valley
Group'
LA, TX
-
-
-
-
-
-
-
164,683
(5,241-
356,666)
-
Devonian
Sandstone8
PA
0.8
(0.2-2.5)
-
-
-
6.3
(5.5-6.8)
184,800
(118,000-
211,000)
-
235,125
(106,000-
354,000)
-
Mesaverde'
CO, NM, UT,
WY
-
-
-
-
8
(5.8-11.62)
-
-
15,802
(1,032-
125,304)
-
Oswego'
OK
-
-
-
-
6.3
(6.1-6.4)
-
-
73,082
(56,541-
108,813)
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Parameter
States
TOC
Total
suspended
solids
Turbidity
Units
n/a
mg/L
mg/L
NTU
Shales
Bakken3
MT, ND
-
-
-
Barnettb
TX
9.75
(6.2-36.2)
242
(120-535)
239
(144-314)
Fayettevillec
AR
-
-
-
Marcellus
PAd
160
(1.2-1,530)
352
(4-7,600)
-
PA, WVe
89.2
(1.2-5,680)
127
(6.8-3,220)
126
(2.3-1,540)
Tight formations
Cotton Valley
Group'
LA, TX
198
(184-212)
-
-
Devonian
Sandstone8
PA
-
-
-
Mesaverde'
CO, NM, UT,
WY
-
-
-
Oswego'
OK
-
-
-
n/a, not applicable; -, no value available; NC, not calculated; ND, not detected., SU= standard units, bolded italic numbers are medians
a SteQ§n_et^lI_[2010}. n = 3. Concentrations were calculated based on Stepan et al.'s raw data. Samples had charge balance errors of 1.74, -0.752, and -0.220%
^ n = 16. This data source reported concentrations without direct presentation of raw data.
c .Warner_et,a,LJ_2013}. n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included.
d Barbot et al. (2013). n = 134-159. This data source reported concentrations without direct presentation of raw data.
eMiM§§120091. n = 31-67. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
f B!ondes_et_iL_{20141. Cotton Valley Group, n=2; Mesa Verde, n = 1-407; Oswego, n = 4-30. Concentrations were calculated based on raw data presented in the U.S.
Geological Survey (USGS) National Produced Water Database v2.0.
5 Drese|_and_Rose_{2010}. n = 3-15. Concentrations were calculated based on Dresel and Rose's raw data.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-3. Reported concentrations of general water quality parameters in produced water
for unconventional coalbed basins, presented as: average (minimum-maximum).
Parameter
States
Alkalinity
Ammonium
Bicarbonate
Carbonate
Chloride
Chemical oxygen
demand
Dissolved oxygen
DOC
Hardness as CaCO3
Hydrogen sulfide
Oil and grease
pH
Phosphate
Specific
conductivity
IDS
Total Kjeldahl
nitrogen
TOC
Total suspended
solids
Turbidity
Units
n/a
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
SU
mg/L
US/cm
mg/L
mg/L
mg/L
mg/L
NTU
Black Warrior3
AL, MS
355 (3-1,600)
3.60(0.16-8.91)
427 (2-1,922)
3 (0-64)
9,078 (11-42,800)
830 (0-10,500)
-
3.37 (0.53-61.41)
871 (3-6,150)
-
-
7.5 (5.3-9.0)
0.435
(0.026-3.570)
20,631
(718-97,700)
14,319
(589-61,733)
6.08(0.15-38.40)
6.03 (0.00-103.00)
78 (0-2,290)
74 (0-539)
Powder Riverb
MT,WY
1,384 (653-2,672)
-
1,080 (236-3,080)
2.17(0.00-139.0)
21 (BDL-282)
-
1.07 (0.11-3.48)
3.18(1.09-8.04)
-
-
-
7.71(6.86-9.16)
BDL(BDL-BDL)
1,598
(413-4,420)
997 (252-2,768)
0.48 (BDL-4.70)
3.52 (2.07-6.57)
11.0 (1.4-72.7)
8.2 (0.7-57.0)
Ratonb
CO, NM
1,107 (130-2,160)
-
1,124 (127-2,640)
51.30
(1.30-316.33)
787 (4.8-8,310)
-
0.39 (0.01-3.52)
1.26 (0.30-8.54)
-
4.41 (BDL-190.0)
9.10(0.60-17.6)
8.19(6.90-9.31)
0.04 (BDL-1.00)
3,199 (742-11,550)
2,512 (244-14,800)
2.61(BDL-26.10)
1.74 (0.25-13.00)
32.3 (1.0-580.0)
4.5 (0.3-25.0)
San Juanb
AZ, CO, NM, UT
3,181 (51-11,400)
-
3,380 (117-13,900)
40.17 (0.00-1,178)
624(BDL-20,100)
-
0.51 (0.04-1.69)
3.21 (0.89-11.41)
-
23.00
(23.00-23.00)
-
7.82 (5.40-9.26)
1.89 (BDL-9.42)
5,308
(232-18,066)
4,693 (150-39,260)
0.46 (BDL-3.76)
2.91(0.95-9.36)
47.2 (1.4-236.0)
61.6 (0.8-810.0)
n/a, not applicable; -, no value available; BDL, below detection limit.
a n = 206. Concentrations were calculated based on raw data presented in the reference.
b Dahm_et_aL_{2011}. Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without
presentation of raw data.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 E-10 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix E
E.2.3. Salinity and Inorganics
1 Table E-4 and Table E-5 provide supporting data on salinity and inorganic constituents of produced
2 water for 12 formations.
£.2.3.1. Processes Controlling Salinity and Inorganics Concentrations
3 Multiple mechanisms likely control elevated salt concentrations in flowback and produced water
4 and are largely dependent upon post-injection fluid interactions and the formation's stratigraphic
5 and hydrogeologic environment [Barbotetal.. 2013]. High inorganic ionic loads observed in
6 flowback and produced water are expressed as TDS.
7 Subsurface brines or formation waters are saline fluids associated with the targeted formation.
8 Shale and sandstone brines are typically much more saline than coalbed waters. After hydraulic
9 fracturing fluids are injected into the subsurface, the injected fluids (which are typically not sources
10 of high TDS) mix with in situ brines, which typically contain high ionic loads [Haluszczak et al..
11 20131.
12 Deep brines, present in over- or underlying strata, may naturally migrate into targeted formations
13 over geologic time or artificially intrude if a saline aquifer is breached during hydraulic fracturing
14 (Chapman etal.. 2012: Maxwell. 2011: Blauchetal.. 20091 Whether it is through natural or induced
15 intrusion, saline fluids may contact the producing formation and introduce novel salinity sources to
16 the produced water [Chapman etal., 2012].
17 The dissolution salts associated with formation solids both increases TDS concentrations and alters
18 formation porosity and permeability [Blauchetal., 2009]. Additionally, the mobilization of connate
19 fluids (deposition-associated pore fluids] and formation fluids during hydraulic fracturing likely
20 contributes to increased TDS levels (Dresel and Rose, 2010: Blauchetal., 2009]. Despite the general
21 use of fresh water for hydraulic fracturing fluid, some elevated salts in produced water may result
22 from the use of reused saline flowback or produced water as a hydraulic fracturing base fluid
23 (Hayes. 2009].
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 E-ll DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-4. Reported concentrations (mg/L) of inorganic constituents contributing to salinity in unconventional shale and tight
formations produced water, presented as: average (minimum-maximum) or median (minimum-maximum).
Parameter
States
Bromide
Calcium
Chloride
Fluoride
Iodine
Nitrate as N
Nitrite as N
Phosphorus
Potassium
Shale
Bakken3
MT, ND
-
9,680
(7,540-
13,500)
119,000
(90,000-
133,000)
-
-
-
-
NC
(ND-0.03)
2,970
(0-5,770)
Barnettb
TX
589
(117-798)
1,600
(1,110-6,730)
34,700
(9,600-60,800)
3.8
(3.5-12.8)
-
-
4.7
(3.5-38.1)
0.395
(0.19-0.7)
316
(80-750)
Fayettevillec
AR
111
(96-144)
317
(221-386)
9,156
(5,507-12,287)
-
-
NC
(ND-ND)
-
-
-
Marcellus
PAd
511
(0.2-1,990)
7,220
(38-41,000)
57,447
(64-
196,000)
-
-
-
-
-
-
PA,WVe
512
(15.8-1,990)
7,465
(173-33,000)
49,000
(64.2-196,000)
0.975
(0.077-32.9)
-
1.7
(0.65-15.9)
11.8
(1.1-146)
0.3 (0,08-21.8)
337
(38-3,950)
Tight Formations
Cotton Valley
Group'
LA, TX
498
(32-1,338)
19,998
(181-51,400)
101,332
(3,167-
221,498.7)
-
20
(1-36)
-
-
-
1,975
(8-7,099)
Devonian
Sandstone6
PA
1,048
(349-1,350)
20,262
(8,930-
34,400)
132,567
(58,900-
207,000)
-
39
(11-56)
-
-
-
858
(126-3,890)
Mesaverde'
CO, NM, UT,
WY
-
212
(1.01-4,580)
4,260
(8-75,000)
-
1.01
(1.01-1.01)
0.6
(0.6-0.6)
-
-
160
(4-2,621)
Oswego'
OK
-
5,903
(3,609-8,662)
44,567
(23,000-75,000)
-
-
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
E-12
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Parameter
States
Silica
Sodium
Sulfate
Sulfide
Sulfite
IDS
Shale
Bakken3
MT, ND
7
(6.41-7)
61,500
(47,100-
74,600)
660
(300-1,000)
-
-
196,000
(150,000-
219,000)
Barnettb
TX
-
18,850
(4,370-28,200)
709
(120-1,260)
NC
(ND-ND)
-
50,550
(16,400-
97,800)
Fayettevillec
AR
52
(13-160)
3,758
(3,152-4,607)
NC
(ND-3)
-
-
13,290
(9,972-
15,721)
Marcellus
PAd
-
21,123
(69-
117,000)
71
(0-763)
-
-
106,390
(680-
345,000)
PA,WVe
-
21,650
(63.8-95,500)
58.9
(2.4-348)
3.2
(1.6-5.6)
12.4
(5.2-73.6)
87,800
(680-345,000)
Tight Formations
Cotton Valley
Group'
LA, TX
4
(4-4)
39,836
(1,320-
85,623.24)
407
(ND-
2,200.46)
-
-
164,683
(5,241-
356,666)
Devonian
Sandstone8
PA
-
58,160
(24,400-
83,300)
20
(1-140)
0.7
(0.1-2.5)
-
235,125
(106,000-
354,000)
Mesaverde'
CO, NM, UT,
WY
-
5,828
(132-48,817)
837
(ND-14,612)
-
-
15,802
(1,032-
125,304)
Oswego'
OK
-
19,460
(13,484-31,328)
183
(120-271)
-
-
73,082
(56,541-
108,813)
-, no value available; NC, not calculated; ND, not detected. Boldeditalic numbers are medians.
a St§Ban_et_aLJ20101- n = 3. Concentrations were calculated based on Stepan et al.'s raw data. Samples had charge balance errors of 1.74, -0.752, and -0.220%
b Mil§i^DiSevennJ^Oj,2bi. n = 16. This data source reported concentrations without presentation of raw data.
c W§£D§L§ljL-i2013). n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included.
d Si£bot_et_aL_(2013|. n = 134-159. This data source reported concentrations without presentation of raw data.
e " = S'65- Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
f BjMHtes_etjLJ20141 Cotton Valley Group, n = 2; Mesa Verde, n = 1-407; Oswego, n = 4-30. Concentrations were calculated based on raw data presented in the USGS
National Produced Water Database v2.0.
n = 3-15. Concentrations were calculated based on Dresel and Rose's raw data.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
E-13
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-5. Reported concentrations (mg/L) of inorganic constituents contributing to salinity in
produced water for unconventional CBM basins, presented as: average
(minimum-maximum).
Parameter
State
Barium
Boron
Bromide
Calcium
Chloride
Fluoride
Magnesium
Nitrate
Nitrite
Phosphorus
Potassium
Silica
Sodium
Strontium
Sulfate
IDS
Black Warrior3
AL, MS
45.540 (0.136-352)
0.185(0-0.541)
-
218 (0-1,640)
9,078 (11-42,800)
6.13 (0.00-22.60)
68.12(0.18-414.00)
8.70 (0.00-127.50)
0.03 (0.00-2.08)
0.32 (0.00-5.76)
12.02 (0.46-74.00)
8.66(1.04-18.10)
4,353 (126-16,700)
11.354 (0.015-142.000)
5.83 (0.00-302.00)
14,319 (589-61,733)
Powder Riverb
MT,WY
0.61(0.14-2.47)
0.17 (BDL-0.39)
0.09 (BDL-0.26)
32.09 (2.00-154.0)
21 (BDL-282)
1.57 (0.40-4.00)
14.66 (BDL-95.00)
-
-
-
11.95 (BDL-44.00)
6.46 (4.40-12.79)
356 (12-1,170)
0.60(0.10-1.83)
5.64 (BDL-300.0)
997 (252-2,768)
Ratonb
CO, NM
1.67 (BDL-27.40)
0.36 (BDL-4.70)
4.86 (0.04-69.60)
14.47 (0.81-269.0)
787 (4.8-8,310)
4.27 (0.59-20.00)
3.31(0.10-56.10)
-
-
-
6.37 (BDL-29.40)
7.05 (4.86-10.56)
989 (95-5,260)
5.87 (BDL-47.90)
14.75 (BDL-253.00)
2,512 (244-14,800)
San Juanb
AZ, CO, NM, UT
10.80 (BDL-74.0)
1.30 (0.21-3.45)
9.77 (BDL-43.48)
53.29 (1.00-5,530)
624(BDL-20,100)
1.76 (0.58-10.00)
15.45 (BDL-511.0)
-
-
-
26.99 (BDL-970.0)
12.37 (3.62-37.75)
1,610 (36-7,834)
5.36 (BDL-27.00)
25.73 (BDL-1,800)
4,693 (150-39,260)
-, no value available; BDL, below detection limit.
a n = 206. Concentrations were calculated based on the authors' raw data.
b Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without
presentation of raw data.
E.2.4. Metals and Metalloids
1 Table E-6 and Table E-7 provide supporting data on metal constituents of produced water for 12
2 formations.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-6. Reported concentrations (mg/L) of metals and metalloids from unconventional shale and tight formation produced
water, presented as: average (minimum-maximum) or median (minimum-maximum).
Note that calcium, potassium, and sodium appear in Table E-4.
Parameter
States
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Chromium
Cobalt
Shale
Bakken3
MT, ND
-
-
-
10
(0-24.6)
-
116
(39.9-192)
-
-
-
Barnettb
TX
0.43
(0.37-2.21)
NC
(ND-ND)
NC
(ND-ND)
3.6
(0.93-17.9)
NC (ND-ND)
30.3
(7.0-31.9)
NC
(ND-ND)
0.03
(0.01-0.12)
0.01
(0.01-0.01)
Fayettevillec
AR
-
-
-
4
(3-5)
-
4.800
(2.395-
21.102)
-
-
-
Marcellus
PAd
-
-
-
2,224
(0.24-13,80
0)
-
-
-
-
-
PA, WVe
2.57
(0.22-47.2)
0.028
(0.018-0.038)
0.101
(0.013-0.124)
542.5
(2.590-
13,900)
-
12.2
(0.808-145)
-
0.079
(0.011-0.567)
-
Tight Formation
Cotton Valley
Group'
LA, TX
-
-
-
160
(ND-400.52)
-
37
(2-100)
-
-
-
Devonian
Sandstone6
PA
-
-
-
1,488
(7-4,370)
-
-
-
-
-
Mesaverde'
CO, NM, UT,
WY
-
-
-
139
(4-257)
-
10
(1-14.2)
-
-
-
Oswego'
OK
-
-
-
-
-
-
-
-
June 2015
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Appendix E
Parameter
States
Copper
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Selenium
Silver
Shale
Bakken3
MT, ND
NC
(ND-0.21)
96
(ND-120)
-
-
1,270
(630-1,750)
7
(4-10.2)
-
NC
(ND-<0.2)
-
-
-
Barnettb
TX
0.29
(0.06-0.52)
24.9
(12.1-93.8)
0.02
(0.01-0.02)
19.0
(2.56-37.4)
255
(149-755)
0.86
(0.25-2.20)
NC
(ND-ND)
0.02
(0.02-0.03)
0.04
(0.03-0.05)
0.03
(0.03-0.04)
-
Fayettevillec
AR
-
7
(1-13)
-
9.825
(2.777-
28.145)
61
(47-75)
2
(2-3)
-
-
-
-
-
Marcellus
PAd
-
-
-
-
632
(17-2,550)
-
-
-
0.1815
(0.007-
0.137)
-
-
PA, WVe
0.506
(0.253-4.150)
53.65
(2.68-574)
0.066
(0.003-0.970)
53.85
(3.410-323)
678
(40.8-2,020)
2.825
(0.369-
18.600)
0.00024
-
0.419
(0.068-0.769)
0.004
4
(3-6)
Tight Formation
Cotton Valley
Group'
LA, TX
0.7
(0.48-1)
-
-
23
(1-53)
1,363
(27-3,712.98)
30.33
(30.33-30.33)
-
-
-
-
-
Devonian
Sandstone8
PA
0.04
(0.01-0.13)
188
(90-458)
0.02
(0.01-0.04)
97.8
(20.2-315)
2,334
(797-3,140)
19
(5.6-68)
-
-
-
-
-
Mesaverde'
CO, NM, UT,
WY
-
9
(1-29)
-
3
(1-33)
74
(1-2,394)
-
-
-
-
-
-
Oswego'
OK
-
61
(41-78)
-
-
753
(486-1,264)
-
-
-
-
-
-
June 2015
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Appendix E
Parameter
States
Strontium
Thallium
Tin
Titanium
Zinc
Shale
Bakken3
MT, ND
764
(518-1,010)
-
-
-
7
(2-11.3)
Barnettb
TX
529
(48-1,550)
NC
(ND-0.14)
NC
(ND-ND)
0.02
(0.02-0.03)
0.15
(0.10-0.36)
Fayettevillec
AR
27
(14-49)
-
-
-
-
Marcellus
PAd
1,695
(0.6-8,460)
-
-
-
-
PA, WVe
1,240
(0.580-8,020)
0.168
-
-
0.391
(0.087-247)
Tight Formation
Cotton Valley
Group'
LA, TX
2,312
(39-9,770)
-
-
-
-
Devonian
Sandstone8
PA
3,890
(404-13,100)
-
-
-
0.20
(0.03-1.26)
Mesaverde'
CO, NM, UT,
WY
-
-
-
-
-
Oswego'
OK
-
-
-
-
-
-, no value available; NC, not calculated; ND, not detected; BDL, below detection limit. Bolded italic numbers are medians.
a Stej>an_et_al._{2010}. n = 3. Concentrations were calculated based on Stepan et al.'s raw data.
b JHa^es^nd_Seyerin_t2012bl. n = 16. This data source reported concentrations without presentation of raw data.
c Warner_et_aL_(2013). n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included.
d Barbo£e££JI_[2013}. n = 134-159. This data source reported concentrations without presentation of data.
e Ha¥§s_{2009}. n = 48. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
f BJ°!ld§s_et_aLJ_2014). Cotton Valley Group, n = 2; Mesa Verde, n = 1-407; Oswego, n = 4-30. Concentrations were calculated based on raw data presented in the USGS
National Produced Water Database v2.0.
g|)reseJ_ajTdJRoseJ2010}. n = 3-15. Concentrations were calculated based on Dresel and Rose's raw data.
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-7. Reported concentrations (mg/L) of metals and metalloids from unconventional
coalbed produced water, presented as: average (minimum-maximum).
Parameter
States
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Cesium
Chromium
Cobalt
Copper
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Rubidium
Selenium
Silver
Sodium
Strontium
Thallium
Tin
Titanium
Black Warrior3
AL, MS
0.037 (0-0.099)
0.006 (0.00-0.022)
0.002 (0.0-0.085)
45.540 (0.136-352)
0.0 (0.0-0.008)
0.185 (0-0.541)
0.001 (0.00-0.015)
218 (0-1,640)
0.011 (0.0-0.072)
0.002 (0.0-0.351)
0.023(0.00-0.162)
0.001 (0.0-0.098)
8.956 (0.045-93.100)
0.008 (0.00-0.250)
1.157 (0-8.940)
68.12(0.18-414.00)
0.245 (0.006-4.840)
0.000 (0.000-0.000)
0.002 (0-0.083)
0.015 (0.0-0.358)
12.02 (0.46-74.00)
0.013(0.0-0.114)
0.002 (0.00-0.063)
0.015 (0.0-0.565)
4,353 (126-16,700)
11.354 (0.015-142.000)
-
0.00 (0.00-0.009)
0.003 (0.0-0.045)
Powder Riverb
MT,WY
0.018 (BDL-0. 124)
BDL(BDL-BDL)
0.001 (BDL-0.004)
0.61(0.14-2.47)
BDL(BDL-BDL)
0.17 (BDL-0.39)
BDL (BDL-0.002)
32.09 (2.00-154.0)
-
0.012 (BDL-0.250)
BDL(BDL-BDL)
0.078 (BDL-1.505)
1.55 (BDL-190.0)
BDL(BDL-BDL)
0.13 (BDL-0.34)
14.66 (BDL-95.00)
0.02 (BDL-0. 16)
-
0.005 (BDL-0.029)
0.141 (BDL-2.61)
11.95 (BDL-44.00)
-
0.006 (BDL-0.046)
0.003 (0.003-0.003)
356 (12-1,170)
0.60(0.10-1.83)
-
0.006 (BDL-0.028)
BDL (BDL-0.002)
Raton b
CO, NM
0.193 (BDL-2,900)
BDL(BDL-BDL)
0.010 (BDL-0.060)
1.67 (BDL-27.40)
BDL(BDL-BDL)
0.36 (BDL-4.70)
0.002 (BDL-0.003)
14.47 (0.81-269.0)
-
0.105 (BDL-3.710)
0.001 (BDL-0.018)
0.091 (BDL-4.600)
7.18(0.09-95.90)
0.023 (BDL-0.233)
0.32 (0.01-1.00)
3.31 (0.10-56.10)
0.11(0.01-2.00)
-
0.002 (BDL-0.035)
0.015 (0.004-0.11)
6.37 (BDL-29.40)
-
0.017 (BDL-0.100)
0.015 (BDL-0.140)
989 (95-5,260)
5.87 (BDL-47.90)
-
0.008 (BDL-0.021)
BDL (BDL-0.002)
San Juanb
AZ, CO, NM, UT
0.069 (BDL-0.546)
BDL(BDL-BDL)
0.001 (BDL-0.020)
10.80 (BDL-74.0)
BDL(BDL-BDL)
1.30 (0.21-3.45)
0.002 (BDL-.006)
53.29 (1.00-5,530)
-
0.002 (BDL-0.023)
0.001 (BDL-0.017)
0.058 (BDL-0.706)
6.20 (BDL-258.0)
0.023 (BDL-0.390)
1.61 (0.21-4.73)
15.45 (BDL-511.0)
0.19(BDL-1.34)
-
0.020 (BDL-0.040)
0.020 (BDL-0.13)
26.99 (BDL-970.0)
-
0.018 (BDL-0.067)
BDL(BDL-BDL)
1,610 (36-7,834)
5.36 (BDL-27.00)
-
0.017 (BDL-0.039)
0.004 (BDL-0.020)
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Parameter
States
Vanadium
Zinc
Black Warrior3
AL, MS
0.001 (0.0-0.039)
0.024 (0.0-0.278)
Powder Riverb
MT,WY
BDL(BDL-BDL)
0.063 (BDL-0.390)
Raton b
CO, NM
0.001 (BDL-0.013)
0.083 (0.010-3.900)
San Juanb
AZ, CO, NM, UT
BDL(BDL-BDL)
0.047 (0.005-0.263)
-, no value available; BDL, below detection limit.
a DOE (2014). n = 206. Concentrations were calculated based on the authors' raw data.
b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without
presentation of raw data.
E.2.4.1. Processes Controlling Mineral Precipitation and Dissolution
1 Hydraulic fracturing treatments introduce fluids into the subsurface that are not in equilibrium
2 with respect to formation mineralogy. Subsurface geochemical equilibrium modeling and
3 saturation indices are therefore used to assess the solution chemistry of unconventional produced
4 water and the subsequent likelihood of precipitation and dissolution reactions [Engle and Rowan,
5 2014: Barbotetal.. 2013). Dissolution and precipitation reactions between fracturing fluids,
6 formation solids, and formation water contribute to the chemistry of flowback and produced water.
7 For example, early flowback fluids may be under-saturated with respect to certain constituents or
8 minerals associated with formation solids. Through time, as fluid-rock geochemistry returns to
9 equilibrium, formation minerals will dissolve into solution and return in flowback.
10 Depending upon the formation chemistry and composition of the hydraulic fracturing fluid, the
11 hydraulic fracturing fluid may initially have a lower ionic strength than existing formation fluids.
12 Consequently, salts, carbonate, sulfate, and silicate minerals may undergo dissolution or
13 precipitation. Proppants may also undergo dissolution or serve as nucleation sites for precipitation
14 [McLinetaL 20111.
15 Currently, relatively little literature quantitatively explores subsurface dissolution and
16 precipitation reactions between hydraulic fracturing fluids and formation solids and water.
17 However, the processes that take place will likely be a function of the solubilities of the minerals,
18 the chemistry of the fluid, pH, redox conditions, and temperature.
19 Documented dissolution processes in unconventional resources include the dissolution of feldspar
20 followed by sodium enrichment in coalbed produced water [Rice etal.. 2008]. Dissolution of
21 barium-rich minerals (barite (BaSCU) and witherite (BaCOs)), and strontium-rich minerals (celestite
22 (SrSCU) and strontianite (SrCOs)) are known to enrich shale produced waters in barium and
23 strontium [Chapman etal.. 2012).
24 Known precipitation processes in unconventional resources include the precipitation of carbonate
2 5 and subsequent reduction of calcium and magnesium concentrations in coalbed produced water
26 [Rice etal.. 2008). Additionally, calcium carbonate precipitation is suspected to cause declines in pH
27 and alkalinity levels in shale produced water [Barbotetal., 2013].
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 The subsurface processes associated with fluid-rock interactions take place over a scale of weeks to
2 months through the generation of flowback and produced water. Note that the types and extent of
3 subsurface dissolution and precipitation reactions change with time, from injection through
4 flowback and production. For instance, Engle and Rowan [2014] found that early Marcellus Shale
5 flowback was under-saturated with respect to gypsum (CaS04-2H20), halite (NaCl), celestite,
6 strontianite, and witherite, indicating that these minerals would dissolve in the subsurface. Fluids
7 were oversaturated with respect to barite. Saturation indices for gypsum, halite, celestite, and
8 barite all increased during production. Knowing when dissolution and precipitation will likely
9 occur is important, because dissolution and precipitation of minerals change formation
10 permeability and porosity, which can affect production [Andre etal., 2006].
11 Additionally, pyrite (FeS2] is an important minor mineral in reduced sedimentary rocks. Pyrite is
12 the primary form of sulfur and iron occurrence in shales [Leventhal and Hosterman. 1982] and is
13 also a common mineral phase generated in coals in which organic matter is closely associated
14 [Ward, 2002]. Pyrite content in shales can vary from less than 1% to several percent [Chermak and
15 Schreiber. 2014: Vulgamore etal.. 2007]. Researchers have found a strong association of trace
16 metals (i.e., nickel, copper, cadmium, chromium, cobalt, lead, selenium, vanadium, and zinc] with
17 pyrite in shales [Chermak and Schreiber. 2014: Tuttle etal.. 2009: Leventhal and Hosterman. 1982].
18 Although studies considering pyrite oxidation within the context of hydraulic fracturing are
19 currently lacking, it is likely that the introduction of oxygenated fluids to freshly exposed surfaces
20 in the subsurface during hydraulic fracturing can initiate limited, short-term pyrite oxidation or
21 dissolution. Pyrite dissolution may increase iron and trace element concentrations and acidity in
22 produced waters [Nordstrom and Alpers. 1999: Moses and Herman. 1991].
23 The extent to which the oxidative dissolution of pyrite would exert a control on post-injection
24 subsurface fluid chemistry is unknown, although an ongoing U.S. Geological Survey (USGS] study
25 anticipates it may be more significant than previously hypothesized [Li and Brantley. 2011].
26 Regardless, relative to other reactions contributing to the composition of flowback and produced
27 water (i.e., dissolution of salts], pyrite oxidation appears to be less significant. Ultimately, reactions
28 resulting from temporary changes in subsurface redox conditions will be less important relative to
29 other reactions that are less redox-dependent
E.2.5. Naturally Occurring Radioactive Material (NORM) and Technically Enhanced Naturally
Occurring Radioactive Material (TENORM)
£.2.5.1. Formation Solids Levels of NORM
3 0 Elevated uranium levels in formation solids have been used to identify potential areas of natural
31 gas production for decades (Fertl and Chilingar. 1988]. Marine black shales are estimated to contain
32 an average of 5-20 ppm uranium depending on depositional conditions, compared to an average of
33 less than 5 ppm among all shales (USGS, 1961]. Shales that bear significant levels of uranium
34 include the Barnett in Texas, the Woodford in Oklahoma, the New Albany in the Illinois Basin, the
35 Chattanooga Shale in the southeastern United States, and a group of black shales in Kansas and
36 Oklahoma fSwanson. 19551
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Hydraulic Fracturing Drinking Water Assessment Appendix E
l identified Marcellus samples with uranium ranging from 4-72 ppm, with an
2 average of 30 ppm. Additionally, shale samples taken from three counties within the Marcellus
3 Shale had uranium concentrations ranging from 8 to 84 ppm (BTGS1_201Jj
4 1981)- QlMBHlLiMJifihra^ compiled mineralogy and trace element data available in the
5 literature for nine U.S. hydrocarbon-producing shales. In this combined data set, uranium levels
6 among different shale plays were found to vary over three orders of magnitude, with samples of the
7 Utica Shale containing approximately 0-5 ppm uranium and samples of the Woodford Shale
8 containing uranium in the several-hundred-ppm range.
9 VineXlSMl reported that the principal uranium-bearing coal deposits of the United States are
10 found in Cretaceous and Tertiary formations in the northern Great Plains and Rocky Mountains; in
11 some areas of the West, coal deposits have been found with uranium concentrations in the range of
12 thousands of ppm or greater. In contrast, most Mississippian, Pennsylvanian, and Permian coals in
13 the north-central and eastern United States contain less than 10 ppm uranium, rarely containing
14 50 ppm or more.
£.2.5.2. Produced Water Levels of TENORM
15 Background data on NORM in the Marcellus Shale and Devonian sandstones are given in Table E-8.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-8. Reported concentrations (in pCi/L) of radioactive constituents in unconventional shale and sandstone produced water,
presented as: average (minimum-maximum) or median (minimum-maximum).
Parameter
States
Gross alpha
Gross beta
Radium-226
Radium-228
Total Radium
Uranium235
Uranium238
Marcellus
NY, PAb
6,845 (ND-123,000)
1,170 (ND-12,000)
1,869(1X10-16,920)
557(ND-2,589)
2,530(0.192-18,045)
1 (ND-20)
42 (ND-497)
Flowbackc
10,700 (288-71,000)
2,400 (742-21,300)
4,500 (551-25,500)
633 (248-1,740)
-
-
-
PA NORM STUDY
Conventional
Produced Waterd
1,835 (465-2,570)
909(402-1,140)
243 (81 - 819)
128 (26 - 896)
371 (107 - 1,715)
-
-
Unconventional
Produced Water0
11,300 (2,240-41,700)
3.445 (1.5-7,600)
6,300 (1,700-26,600)
941 (366-1,900)
7,180 (2,336-28,500)
-
-
Devonian Sandstone3
PA
-
-
2,367 (200-5,000)
-
-
-
-
n/a, not applicable; -, no value available; BDL, below detection limit. Bolded italic numbers are medians.
a £resej_and_Rose_[20101. n = 3. Concentrations presented were calculated based on Dresel and Rose's raw data.
b " = 51. Concentrations presented were calculated based on Rowan et al.'s raw data for Marcellus samples. Uranium data from Barbot et al. (2013) n = 14.
n = 9. Data reported in Table 3-14.
d£^DE£120151. n = 9. Values calculated from Table 3-15 for unfiltered samples.
e PA_DEP_{20151. n = 4. Values calculated from Table 3-15 for unfiltered samples.
June 2015
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£.2.5.3. Mobilization of Naturally Occurring Radioactive Material
1 Similar to conventional oil and gas production, in unconventional oil and gas production,
2 radionuclides native to the targeted formation return to the surface with produced water. The
3 principal radionuclides found in oil and gas produced waters include radium-226 of the uranium-
4 238 decay series and radium-228 of the thorium-232 decay series [White. 1992]. Levels of
5 TENORM in produced water are controlled by geologic and geochemical interactions between
6 injected and formation fluids, and the targeted formation [Bank, 2011]. Mechanisms controlling
7 NORM mobilization into produced water include (1) the TENORM content of the targeted
8 formation; (2) factors governing the release of radionuclides, particularly radium, from the
9 reservoir matrix; and (3) the geochemistry of the produced water [Choppin. 2007. 2006: Fisher.
10 19981.
11 Organic-rich shales and coals are enriched in uranium, thorium, and other trace metals in
12 concentrations several times above those seen in typical shales or sedimentary rocks [Diehl etal.,
13 2004: USGS. 1997: Wignall and Myers. 1988: Tourtelot. 1979: Vine and Tourtelot. 1970). Unlike
14 shales and coals, sandstones are generally not organic-rich source rocks themselves. Instead,
15 hydrocarbons migrate into these formations over long periods of time [Clark and Veil, 2009]. Since
16 TENORM and organic contents are typically positively correlated due to the original, reduced
17 depositional environment [Fertl and Chilingar, 1988], it is unlikely that sandstones would be
18 enriched in TENORM to the same extent as oil- and gas-bearing shales and coals. Therefore, concern
19 related to TENORM within produced water is focused on operations targeting shales and coalbeds.
20 Radium is most soluble and mobile in chloride-rich, high-TDS, reducing environments [Sturchio et
21 al.. 2001: Zapecza and Szabo. 1988: Langmuir and Riese. 1985]. In formation fluids with high TDS,
22 calcium, potassium, magnesium, and sodium compete with dissolved radium for sorption sites,
23 limiting radium sorption onto solids and allowing it to accumulate in solution at higher
24 concentrations [Fisher, 1998: Webster et al., 1995]. The positive correlation between TDS and
25 radium is well established and TDS is a useful indicator of radium and TENORM activity within
26 produced water, especially in lithologically homogenous reservoirs [Rowan etal.. 2011: Sturchio et
27 al.. 2001: Fisher. 1998: Kraemer and Reid. 1984].
28 Uranium and thorium are poorly soluble under reducing conditions and are therefore more
29 concentrated in formation solids than in solution [Fisher, 1998: Kraemer and Reid, 1984: Langmuir
30 and Herman. 1980]. However, because uranium becomes more soluble in oxidizing environments,
31 the introduction of relatively oxygen-rich fracturing fluids may promote the temporary
32 mobilization of uranium during hydraulic fracturing and early flowback. In addition, the physical
33 act of hydraulic fracturing creates fresh fractures and exposes organic-rich and highly reduced
34 surfaces from which radionuclides could be released from the rock into formation fluids.
35 Produced water geochemistry determines, in part, the fate of subsurface radionuclides, particularly
36 radium. Radium may remain in the host mineral or it may be released into formation fluids, where
37 it can remain in solution as the dissolved Ra2+ ion, be adsorbed onto oxide grain coatings or clay
38 particles by ion exchange, substitute for other cations during the precipitation of minerals, or form
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 complexes with chloride, sulfate, and carbonate ions (Rowan_et_aL_2011.: Sturchio_etal.1_2001;
2 LangmuiLandJlieseJ_1985.]. Uranium- and thorium-containing materials with a small grain size, a
3 large surface-to-volume ratio, and the presence of uranium and thorium near grain surfaces
4 promote the escape of radium into formation fluids. Vinsan_et_aL[2009} point to alpha decay along
5 fracture surfaces as a primary control on radium mobilization in crystalline bedrock aquifers.
6 Radium may also occur in formation fluids due to other processes, such as the decay of dissolved
7 parent isotopes and adsorption-desorption reactions on formation surfaces (Sturchio_etaL_2001]-
8 Preliminary results from fluid-rock interaction studies [Bank. 2011] indicate that a significant
9 percentage of uranium in the Marcellus Shale may be subject to mobilization by hydrochloric acid,
10 which is used as a fracturing fluid additive. Understanding these processes will determine the
11 extent to which such processes might influence the TENORM content of flowback and produced
12 water.
E.2.6. Organics
13 Background data on organics in seven formations is given in Table E-9.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-9. Concentrations of select organic parameters from unconventional shale, a tight formation, and coalbed produced
water, presented as: average (minimum-maximum) or median (minimum-maximum).
Parameter
States
TOC
DOC
BOD
Oil and grease
Benzene
Toluene
Ethylbenzene
Unit
n/a
mg/L
mg/L
mg/L
mg/L
Hg/L
Hg/L
Hg/L
Shale
Barnett3
TX
9.75
(6.2-36.2)
11.2
(5.5-65.3)
582
(101-2,120)
163.5
(88.2-1,430)
680
(49-5,300)
760
(79-8,100)
29
(2.2-670)
Marcellus
PAb
160
(1.2-
1,530)
43
(5-695)
-
74
(5-802)
-
-
-
PA, WVC
89.2
(1.2-5680)
117
(3.3-5,960)
141
(2.8-
12,400)
16.9
(4.7-802)
220
(5.8-2,000)
540
(5.1-6,200)
42
(7.6-650)
Tight
Formation
Cotton Valley
Groupd
LA, TX
198
(184-212)
-
-
-
-
-
-
Coal
Powder Rivere
MT,WY
3.52
(2.07-6.57)
3.18
(1.09-8.04)
-
-
-
-
-
Ratone
CO, NM
1.74
(0.25-13.00)
1.26
(0.30-8.54)
-
9.10
(0.60-17.6)
4.7
(BDL-220.0)
4.7 (BDL-78.0)
0.8 (BDL-18.0)
San Juan8
AZ, CO, NM, UT
2.91
(0.95-9.36)
3.21
(0.89-11.41)
-
-
149.7
(BDL-500.0)
1.7
(BDL-6.2)
10.5 (BDL-24.0)
Black Warrior'
AL, MS
6.03
(0.00-103.00)
3.37
(0.53-61.41)
-
-
-
-
-
June 2015
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Parameter
States
Xylenes
Average total BTEXB
Unit
n/a
Hg/L
Hg/L
Shale
Barnett3
TX
360
(43-1,400)
1,829
Marcellus
PAb
-
2,910
PA, WVC
300
(15-6,500)
1,102
Tight
Formation
Cotton Valley
Groupd
LA, TX
-
-
Coal
Powder Rivere
MT,WY
-
-
Raton"
CO, NM
9.9
(BDL-190.0)
20.1
San Juan8
AZ, CO, NM, UT
121.2
(BDL-327.0)
283.1
Black Warrior'
AL, MS
-
-
n/a, not applicable; -, no value available; BDL, below detection limit. Bolded italic numbers are medians.
a jHayes^nd_Severin_[2012b). n = 16. This data source reported concentrations without presentation of raw data.
b Barbot^t^L_{2013}. n = 55; no presentation of raw data.
c Hayes_{2009} n = 13-67. Concentrations were calculated based on Hayes' raw data. Both flowback and produced water included. Non-detects and contaminated blanks
omitted.
d Blondes_et^lI_[2014}. n = 2. Concentrations were calculated based on raw data presented in the USGS National Produced Water Database v2.0.
e Dahm_et_aL_(2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without presentation of raw data.
f DOE_{2014}. n = 206. Concentrations were calculated based on the authors' raw data.
g Average total BTEX was calculated by summing the average/median concentrations of benzene, toluene, ethylbenzene, and xylenes for a unique formation or basin. Minimum
to maximum ranges were not calculated due to inaccessible raw data.
June 2015
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 Several classes of naturally occurring organic chemicals are present in conventional and
2 unconventional produced waters, with large concentration ranges (Lee_MMlNML20il)- These
3 organic classes include total organic carbon (TOG); saturated hydrocarbons; BTEX (benzene,
4 toluene, ethylbenzene, and xylenes); and polyaromatic hydrocarbons (PAHs) (see Table E-9). While
5 TOG concentrations in produced water are detected at the milligrams to grams per liter level,
6 concentrations of individual organic compounds are typically detected at the micrograms to
7 milligrams per liter level.
8 TOG indicates the level of dissolved and undissolved organics in produced water, including non-
9 volatile and volatile organics (AchM^aMMJMll)- TOG concentrations in conventional produced
10 water vary widely from less than 0.1 mg/L to more than 11,000 mg/L. Average TOG concentrations
11 in unconventional produced water range from less than 2.00 mg/L in the Raton CBM basin to
12 approximately 200 mg/L in the Cotton Valley Group sandstones, although individual measurements
13 have exceeded 5,000 mg/L in the Marcellus Shale (see Table E-9).
14 Dissolved organic carbon (DOC) is a general indicator of organic loading and is the fraction of
15 organic carbon available for complexing with metals and supporting microbial growth. DOC values
16 in unconventional produced water range from less than 1.50 mg/L (average) in the Raton Basin to
17 more than 115 mg/L (median) in the Marcellus Shale (see Table E-9). Individual DOC
18 concentrations in the Marcellus Shale produced water approach 6,000 mg/L. For comparison, DOC
19 levels in fresh water systems are typically below 5 mg/L, while raw wastewater can exceed
20 50 mg/L
2 1 Biochemical oxygen demand (BOD) is a conventional pollutant under the U.S. Clean Water Act It is
22 an indirect measure of biodegradable organics in produced water and an estimate of the oxygen
23 demand on a receiving water. Median BOD levels for Barnett and Marcellus Shales produced water
24 exceed 30 mg/L, and both reported maximum concentrations exceeding 12,000 mg/L (Table E-9).
25 In some circumstances wide variation in produced water median BOD levels may be reflective of
26 flowback reuse in fracturing fluids (
27 Lastly, BTEX is associated with petroleum. Benzene was found in produced water from several
28 basins: average produced water benzene concentration from the Barnett Shale was 680 [ig/L, from
29 the Marcellus Shale was 220 [ig/L (median), and from the San Juan Basin was 150 [ig/L (see Table
30 E-9). Total BTEX concentrations for conventional produced water vary widely from less than
31 100 [ig/L to nearly 580,000 [J.g/L. For comparison, average total BTEX concentrations in
32 unconventional produced water range from 20 [J.g/L in the Raton Basin to nearly 3,000 [J.g/L in the
33 Marcellus play (see Table E-9). From these data, average total BTEX levels in shale produced water
34 are one to two orders of magnitude higher than those in CBM produced water.
35 In addition to abundant BTEX, a variety of volatile and semi-volatile organic compounds VOCs and
36 SVOCs have been detected in shale and coalbed produced water. Shale produced water contains
37 naphthalene, alkylated toluenes, and methylated aromatics in the form of several benzene and
38 phenol compounds, as shown in Table E-10. Like BTEX, naphthalene, methylated phenols, and
39 acetophenone are associated with petroleum. Detected shale produced water organics such as
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
1 acetone, 2-butanone, carbon disulfide, and pyridine are potential remnants of chemical additives
2 used as friction reducers or industrial solvents (JHayesJ_2009).
Table E-10. Reported concentrations (u.g/L) of organic constituents in produced water for two
unconventional shale formations, presented as: average (minimum-maximum) or
median (minimum-maximum).
Parameter
States
Acetone
Carbon disulfide
Chloroform
Isopropylbenzene
Naphthalene
Phenolic compounds
1,2,4-Trimethylbenzene
1,3,5-Trimethylbenzene
1,2-Diphenylhydrazine
1,4-Dioxane
2-Methylnaphthalene
2-Methylphenol
2,4-Dichlorophenol
2,4-Dimethylphenol
3-Methylphenol and
4-Methylphenol
Acetophenone
Benzidine
Benzo(a)anthracene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(g,h,i)perylene
Benzo(k)fluoranthene
Benzyl alcohol
Bis(2-Ethylhexyl) phthalate
Butyl benzyl phthalate
Barnett3
TX
145 (27-540)
-
-
35 (0.8-69)
238 (4.8-3,100)
119.65 (9.3-230)
173 (6.9-1,200)
59 (6.4-300)
4.2 (0.5-7.8)
6.5 (3.1-12)
1,362 (5.4-20,000)
28.3 (5.8-76)
(ND-15)
14.5 (8.3-21)
41 (7.8-100)
(ND-4.6)
(ND-35)
(ND-17.0)
(ND-130.0)
42.2 (0.5-84.0)
42.3 (0.7-84.0)
32.8 (0.6-65.0)
81.5 (14.0-200)
210 (4.8-490)
34.3 (1.9-110)
Marcellusb
MD, NY, OH, PA, VA, WY
83 (14-5,800)
400 (19-7,300)
28
120 (86-160)
195 (14-1,400)
-
66.5 (7.7-4,000)
33 (5.2-1,900)
-
-
3.4 (2-120)
13 (11-15)
-
12
11.5 (0.35-16)
13 (10-22)
-
-
6.7
10
6.9
5.9
41 (17-750)
20 (9.6-870)
-
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Parameter
States
Chrysene
Di-n-octyl phthalate
Di-n-butyl phthalate
Dibenz(a,h)anthracene
Diphenylamine
Fluoranthene
Fluorene
lndeno(l,2,3-cd)pyrene
N-Nitrosodiphenylamine
N-Nitrosomethylethylamine
Phenanthrene
Phenol
Pyrene
Pyridine
Barnett3
TX
120 (0.57-240)
(ND-270)
41(1.5-120)
77 (3.2-150)
5.3 (0.6-10.0)
(ND-0.18)
0.8 (0.46-1.3)
71 (2.9-140)
8.9 (7.8-10)
(ND-410)
107 (0.52-1,400)
63 (17-93)
0.2 (ND-0.18)
413 (100-670)
Marcellusb
MD, NY, OH, PA, VA, WY
-
15
14 (11-130)
3.2 (2.3-11)
-
6.1
8.4
3.1 (2.4-9.5)
2.7
-
9.75 (3-22)
10 (2.4-21)
13
250 (10-2,600)
-, no value available; ND, not detected.
a Haves and Severin (2012b). n = 16. Data from days 1-23 of flowback. This data source reported concentrations without
presentation of raw data.
b Hayes (2009). n = 1-35. Data from days 1-90 of flowback. Concentrations were calculated from Hayes' raw data. Non-detects
and contaminated blanks omitted.
1 The organic profile of CBM produced water is characterized by high levels of aromatic and
2 halogenated compounds compared to other unconventional produced waters [Sirivedhin and
3 Dallbauman, 2004]. PAHs and phenols are the most common organic compounds found in coalbed
4 produced water. Produced water from coalbeds in the Black Warrior Basin mainly contains
5 phenols, multiple naphthalic PAHs, and various decanoic and decenoic fatty acids (see Table E-ll).
6 CBM-associated organics are also known to include biphenyls, alkyl aromatics, hydroxypyridines,
7 aromatic amines, and nitrogen-, oxygen-, and sulfur-bearing heterocyclics [Orem etal.. 2014:
8 Pashin etal.. 2014: Benko and Drewes. 2008: Orem etal.. 2007: Fisher and Santamaria. 2002].
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
Table E-ll. Reported concentrations of organic constituents in 65 samples of produced water
from the Black Warrior CBM Basin, presented as average (minimum-maximum).
Parameter
States
Benzothiazole
Caprolactam
Cyclic octaatomic sulfur
Dimethyl-naphthalene
Dioctyl phthalate
Dodecanoic acid
Hexadecanoic acid
Hexadecenoic acid
Methyl-biphenyl
Methyl-naphthalene
Methyl-quinoline
Naphthalene
Octadecanoic acid
Octadecenoic acid
Phenol, 2,4-bis(l,l-dimethyl)
Phenol, 4-(l,l,3,3-tetramethyl)
Phenolic compounds
Tetradecanoic acid
Tributyl phosphate
Trimethyl-naphthalene
Triphenyl phosphate
Number of observations
-
45
10
29
39
57
30
50
25
18
52
31
49
32
29
21
17
-
53
23
23
6
Concentration (|ig/L)a
AL, MS
0.25 (0.01-3.04)
0.75 (0.02-2.39)
1.06(0.10-9.63)
0.79 (0.01-9.51)
0.21 (0.01-2.30)
1.13 (0.67-2.52)
1.58(1.17-3.02)
1.69(1.13-8.37)
0.25(0.01-2.13)
0.77 (0.01-15.55)
0.96 (0.03-3.75)
0.41 (0.01-6.57)
1.95 (1.62-3.73)
1.87 (1.60-3.47)
0.45 (0.01-4.94)
1.65 (0.01-18.34)
19.06 (ND-192.00)
1.51(0.94-5.32)
0.26 (0.01-2.66)
0.65 (0.01-4.49)
1.18(0.01-6.77)
-, no value available.
a Concentrations were calculated based on the authors' raw data.
1 characterized the content of Marcellus Shale produced water including organics (see
2 Table E-10). The author tested for the majority of VOCs and SVOCs, pesticides and PCBs, based on
3 the recommendation of the Pennsylvania and West Virginia Departments of Environmental
4 Protection. Only 0.5% of VOCs and 0.03% of SVOCs in the produced water were detected above
5 1 mg/L. Approximately 96% of VOCs, 98% of SVOCs, and virtually all pesticides and PCBs were at
6 nondetectable levels.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
E.2.7. Chemical Reactions
1 Section E.2.7.1 describes general aspects of subsurface chemical reactions that might occur during
2 hydraulic fracturing operations. Here we augment the discussion by describing subsurface chemical
3 processes.
E.2.7.1. Injected Chemical Processes
4 Hydraulic fracturing injects relatively oxygenated fluids into a reducing environment, which may
5 mobilize trace or major constituents into solution. Injection of oxygenated fluids may lead to
6 short-term changes in the subsurface redox state, as conditions may shift from reducing to
7 oxidizing. The chemical environment in hydrocarbon-rich unconventional reservoirs, such as black
8 shales, is generally reducing, as evidenced by the presence of pyrite and methane [Engle and
9 Rowan, 2014: Dresel and Rose, 2010]. For black shales, reducing conditions are a product of
10 original accumulations of organic matter whose decay depleted oxygen to create rich organic
11 sediments within oil- and gas-producing formations [Tourtelot, 1979: Vine and Tourtelot, 1970].
12 Yet reactions resulting from temporary redox shifts are likely to be less important than those
13 resulting from other longer-term physical and geochemical processes. Temporary subsurface redox
14 shifts may be due to the short timeframe for fluid injection (a few days to a few weeks] and the use
15 of oxygen scavengers to prevent downhole equipment corrosion.
16 Hydraulic fracturing fluid injection introduces novel chemicals into the subsurface.* As such, the
17 geochemistry of injected and native fluids will not be in equilibrium. Over the course of days to
18 months, a complex series of reactions will equilibrate disparate fluid chemistries. The evolution of
19 flowback and produced water geochemistry are dependent upon the exposure of formation solids
20 and fluids to novel chemicals within hydraulic fracturing fluid. Chemical additives interact with
21 reservoir solids and either mobilize constituents or themselves become adsorbed to solids. Such
22 additives include metallic salts, elemental complexes, salts of organic acids, organometallics, and
23 other metal compounds [Montgomery. 2013: House of Representatives. 2011].
24 The salts, elemental complexes, organic acids, organometallics, and other metal-containing
25 compounds may interact with metals and metalloids in the target formation through processes
26 such as ion exchange, adsorption, desorption, chelation, and complexation. For instance, natural
27 organic ligands (e.g., citrate] are molecules that can form coordination compounds with heavy
28 metals such as cadmium, copper, and lead [Martinez and McBride, 2001: Stumm and Morgan, 1981:
29 Bloomfieldetal.. 1976]. Citrate-bearing compounds are used in hydraulic fracturing fluids as
30 surfactants, iron control agents, and biocides. Studies of the additives' interactions with formation
31 solids at concentrations representative of hydraulic fracturing fluids are lacking.
3 2 Furthermore, pH will likely play a role in the nature and extent of these processes, as the low pH of
33 hydraulic fracturing fluids may mobilize trace constituents. The pH of injected fluids may differ
34 from existing subsurface conditions due to the use of dilute acids (e.g., hydrochloric or acetic] used
35 for cleaning perforations and fractures during hydraulic fracturing treatments (Montgomery, 2013:
1 For more information on chemical additive usage, refer to Chapter 5 (Chemical Mixing).
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 GWPC and ALL Consulting, 2009]. Metals within formation solids may be released through the
2 dissolution of acid-soluble phases such as iron and manganese oxides or hydroxides [Yangetal.,
3 2009: Kashemetal..20Q7: Filgueiras etal.. 20021 Thus, the pH of hydraulic fracturing fluids, or
4 changes in system pH that may occur as fluid recovery begins, may influence which metals and
5 metalloids are likely to be retained within the formation and which may be recovered in flowback.
6 Ultimately, more research is needed to fully understand how the injection of hydraulic fracturing
7 fluids affects subsurface geochemistry and resultant flowback and produced water chemistry.
E.2.8. Microbial Community Processes and Content
8 By design, hydraulic fracturing releases hydrocarbons and other reduced mineral species from
9 freshly fractured shale, sandstone, and coal, resulting in saltier in situ fluids, the release of
10 formation solids, and increased interconnected fracture networks with rich colonization surfaces
11 that are ideal for microbial growth [Wuchter et al.. 2013: Curtis. 2002]. Depending upon the
12 formation, microorganisms may be native to the subsurface and/or introduced from non-sterile
13 equipment and fracturing fluids. Additionally, microorganisms compete for novel organics in the
14 form of chemical additives [Wuchter et al., 2 013: Arthur etal., 2009]. Since large portions of
15 hydraulic fracturing fluid can remain emplaced in the targeted formation, long-term microbial
16 activity is supported through these novel carbon and energy resources [Oremetal., 2014: Murali
17 Mohan etal.. 2013a: Struchtemeyer and Elshahed. 2012: Bottero etal.. 2010]. Such physical and
18 chemical changes to the environment at depth stimulate microbial activity and influence flowback
19 and produced water content in important ways.
20 Several studies characterizing produced water from unconventional formations (i.e., the Barnett,
21 Marcellus, Utica, and Antrim Shales] indicate that taxa with recurring physiologies compose shale
22 flowback and produced water microbial communities [Murali Mohan etal.. 2013b: Wuchter etal.,
23 2013]. Such physiologies include sulfur cyclers (e.g., sulfidogens: sulfur, sulfate, and thiosulfate
24 reducers]; fermenters; acetogens; hydrocarbon oxidizers; methanogens; and iron, manganese, and
25 nitrate reducers (Davis etal.. 2012].
26 Based on their physiologies, microorganisms cycle substrates at depth by mobilizing or
2 7 sequestering constituents in and out of solution. Mobilization can occur through biomethylation,
28 complexation, and leaching. Sequestration can occur through intracellular sequestration,
29 precipitation, and sorption to biomass.
30 The extent to which constituents are mobilized or sequestered depends upon the prevailing
31 geochemical environment after hydraulic fracturing and through production. Significant
3 2 environmental factors that influence the extent of microbially mediated reactions are increases in
33 ionic content (i.e., salinity, conductivity, total nitrogen, bromide, iron, and potassium]; decreases in
34 acidity, and organic and inorganic carbon; the availability of diverse electron acceptors and donors;
35 and the availability of sulfur-containing compounds (Cluff etal.. 2014: Murali Mohan etal.. 2013b:
36 Davis etal.. 2012]. Examples follow that illustrate how subsurface microbial activity influences the
37 content of produced water.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 Under prevailing anaerobic and reducing conditions, microorganisms can mobilize or sequester
2 metals found in unconventional produced water [Gadd. 2004]. Microbial enzymatic reduction
3 carried out by chromium-, iron-, manganese-, and uranium-reducing bacteria can both mobilize and
4 sequester metals (Vanengelenetal.. 2008: Garcia etal.. 2004: Mataetal.. 2002: Gauthier etal..
5 1992: Myers and Nealson, 1988: Lovley and Phillips, 1986]. For instance, iron and manganese
6 species go into solution when reduced, while chromium and uranium species precipitate when
7 reduced [Gadd. 2004: Newman. 2001: Ahmannetal.. 1994].
8 Metals can also be microbially solubilized by complexing with extracellular metabolites,
9 siderophores (metal-chelating compounds], and microbially generated bioligands (e.g., organic
10 acids] [Glorius etal.. 2008: Francis. 2007: Gadd. 2004: Hernlemetal.. 1999]. For example,
11 Pseudomonas spp. secrete acids that act as bioligands to form complexes with uranium(VI] [Glorius
12 etal.. 20081
13 Many sulfur-cycling taxa have been found in hydraulic fracturing flowback and produced water
14 communities [Murali Mohan etal.. 2013b: Mohan etal.. 2011]. Immediately following injection,
15 microbial sulfate reduction is stimulated by diluting high-salinity formation waters with fresh
16 water (high salinities inhibit sulfate reduction]. Microbial sulfate reduction oxidizes organic matter
17 and decreases aqueous sulfate concentrations, thereby increasing the solubility of barium [Cheung
18 etal.. 2010: Lovley and Chapelle. 1995].
19 Sulfidogens also reduce sulfate, as well as elemental sulfur and other sulfur species (e.g.,
20 thiosulfate] prevalent in the subsurface, contributing to biogenic sulfide or hydrogen sulfide gas in
21 produced water [Alain etal.. 2002: Ravotetal.. 1997]. Sulfide can also sequester metals in sulfide
22 phases [Ravotetal.. 1997: Lovley and Chapelle. 1995]. Sources of sulfide also include formation
23 solids (e.g., pyrite in shale] and remnants of drilling muds (e.g., barite and sulfonates], or other
24 electron donor sources (Davis etal.. 2012: Kim etal.. 2010: Collado etal.. 2009: Grabowskietal..
25 2005].
2 6 Additionally, anaerobic hydrocarbon oxidizers associated with shale produced water can readily
27 degrade simple and complex carbon compounds across a considerable salinity and redox range
28 (Murali Mohan et al.. 2013b: Fichter etal.. 2012: Timmis. 2010: Lalucat etal.. 2006: Yakimovetal..
29 2005: McGowan etal.. 2004: Hedlund etal.. 2001: Cayol etal.. 1994: Gauthier etal.. 1992: Zeikus et
30 al.. 1983].
31 Lastly, microbial fermentation produces organic acids, alcohols, and gases under anaerobic
32 conditions, as is the case during methanogenesis. Some nitrogen-cycling genera have been
33 identified in unconventional shale gas systems. These include genera involved in nitrate reduction
34 and denitrification fKim etal.. 2010: Yoshizawa etal.. 2010: Yoshizawa etal.. 2009: Lalucat etal..
35 2006]. These genera likely couple sugar, organic carbon, and sulfur species oxidation to nitrate
36 reduction and denitrification processes.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 Consequently, using a variety of recurring physiologies, microorganisms mobilize and sequester
2 constituents in and out of solution to influence the content of flowback and produced water in
3 important ways.
E.3. Produced Water Content Spatial Trends
E.3.1. Variability between Plays of the Same Rock Type
E.3.1.1. Shale Formation Variability
4 The content of shale produced water varies geographically, as shown by data from four formations
5 (the Bakken, Barnett, Fayetteville, and Marcellus Shales; see Table E-2, Table E-4, Table E-6, Table
6 E-9, Table E-10). For several constituents, variability between shale formations is common. The
7 average/median TDS concentrations in the Marcellus (87,800 to 106,390 mg/L) and Bakken
8 (196,000 mg/L) Shales are one order of magnitude greater than the average TDS concentrations
9 reported for the Barnett and Fayetteville Shales (see Table E-2). As Fayetteville produced water
10 contains the lowest reported average TDS concentration (13,290 mg/L), average concentrations for
11 many inorganics (i.e., bromide, calcium, chloride, magnesium, sodium, and strontium) that
12 contribute to dissolved solids loads are the lowest compared to average concentrations for the
13 same inorganics in Bakken, Barnett, and Marcellus produced water (see Table E-4 and Table E-6).
14 Average concentrations for metals reported within Bakken and Marcellus produced water are also
15 higher than those within the Barnett or Fayetteville formations (see Table E-6).
16 Additionally, Marcellus produced water is enriched in barium (average concentration of 2,224 mg/1
17 in Barbotetal. (2013) or median calculated from Hayes (2009) of 542.5 mg/L) and strontium
18 (average concentration of 1,695 mg/L (Barbotetal.. 2013) or median calculated from Hayes
19 f20091of 1,240 mg/L) by one to three orders of magnitude compared to Bakken, Barnett, and
20 Fayetteville produced water (see Table E-6). Subsequently, radionuclide variability expressed as
21 isotopic ratios (e.g., radium-228/radium-226, strontium-87/strontium-86) are being used to
22 determine the reservoir source for produced water (Chapman etal... 2012: Rowan etal... 2011:
23 Blauch et al.. 2009). Lastly, Barnett and Bakken produced waters are enriched in sulfate.
24 Although organic data are limited, average BTEX concentrations are higher in Marcellus compared
25 to Barnett produced water by one order of magnitude, whereas concentrations of benzene alone
26 are marginally higher in Barnett compared to Marcellus produced water (see Table E-9 and Table
27 E-10).
E.3.1.2. Tight Formation Variability
2 8 The average concentrations for various constituents in tight formation produced water vary
29 geographically between sandstone formations (the Cotton Valley Group, Devonian sandstone, and
30 the Mesaverde and Oswego), as shown in Table E-2, Table E-4, and Table E-6. The average TDS
31 concentrations in the Devonian sandstone (235,125 mg/L) and Cotton Valley Group
32 (164,683 mg/L) are one to two orders of magnitude greater than the average TDS concentrations
33 reported for the Mesaverde (15,802 mg/L) and Oswego Formations (73,082 mg/L) (see Table E-2).
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 Mesaverde produced water also contained the lowest average concentrations for many of the
2 inorganic components of TDS (i.e., calcium, chloride, iron, magnesium, and sodium; see Table E-4
3 and Table E-6).
4 Little variability was reported in pH between these four tight formations (see Table E-2).
5 Mesaverde produced water was enriched in sulfate, with an average concentration of 83 7 mg/L
6 (see Table E-4), whereas Devonian produced water was enriched in barium, which had an average
7 concentration of 1,488 mg/L (see Table E-6).
E.3.1.3. Coalbed Variability
8 Geochemical analysis showed that the Powder River Basin is predominately characterized by
9 bicarbonate water types with a large intrusion of sodium-type waters across a large range of
10 magnesium and calcium concentrations (Dahmetal.. 2011).* In contrast, the Raton Basin is typified
11 by sodium-type waters with low calcium and magnesium concentrations. A combination of Powder
12 River and Raton produced water compositional characteristics typifies the San Juan Basin (Dahm et
13 al.. 2011). Lastly, Black Warrior Basin produced water is differentiated based upon its sodium
14 bicarbonate- or sodium chloride-type waters (DOE, 2014: Pashinetal., 2014).
15 Regional variability is observed in average produced water concentrations for various constituents
16 of four CBM basins (Powder River, Raton, San Juan, and Black Warrior; see Table E-3, Table E-5,
17 Table E-7, Table E-9, and Table E-ll), but particularly between produced water of the Black
18 Warrior Basin and the others. As the average TDS concentration in Black Warrior Basin produced
19 water (14,319 mg/L) is one to two orders of magnitude higher than that of the other three
20 presented in Table E-3, average concentrations for TDS contributing ions (i.e., calcium, chloride,
21 and sodium) were also higher than in the Powder River, Raton, and San Juan Basins. These high
22 levels follow from the marine depositional environment of the Black Warrior Basin (Horsey. 1981).
23 Powder River Basin produced water has the lowest average TDS concentration (997 mg/L), which
24 is consistent with Dahmetal. (2011) reporting that nearly a quarter of all the produced water
25 sampled from the Powder River Basin meets the U.S. drinking water secondary standard for TDS
26 (less than 500 mg/L).2 In addition, the Black Warrior Basin appears to be slightly enriched in
27 barium, compared to the other three CBM basins (see Table E-5). Lastly, the three western CBM
28 basins (Powder River, Raton, and San Juan) are much more alkaline and enriched in bicarbonate
29 than their eastern counterpart (the Black Warrior Basin; see Table E-3).
1 Water is classified as a "type" if the dominant dissolved ion is greater than 50% of the total. A sodium-type water
contains more that 50% of the cation milliequivalents (mEq) as sodium. Similarly, a sodium-bicarbonate water contains
50% of the cation mEq as sodium, and 50% of the anion mEq as bicarbonate (USGS. 2002).
2 MCL refers to the highest level of a contaminant that is allowed in drinking water. MCLs are enforceable standards.
These include primary MCLs for barium, cadmium, chromium, lead, mercury, and selenium. National Secondary Drinking
Water Regulations (NSDWRs or secondary standards) are non-enforceable guidelines regulating contaminants that may
cause cosmetic effects (such as skin or tooth discoloration) or aesthetic effects (such as taste, odor, or color) in drinking
water. Secondary MCLs are recommended for aluminum, chloride, copper, iron, manganese, pH, silver, sulfate, TDS, and
others. See http://water.epa.gov/drink/contaminants/index.cfmtfPrimary for more information.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
1 Average concentrations of benzene, ethylbenzene, and xylenes are higher in San Juan compared to
2 Raton produced water by two orders of magnitude, whereas concentrations of toluene are
3 marginally higher in Raton compared to San Juan produced water (see Table E-9).
E.3.2. Local Variability
4 Spatial variability of produced water content frequently exists within a single producing formation.
5 For instance, Marcellus Shale barium levels increase along a southwest to northeast transect
6 [Barbotetal.. 2013]. Additionally, produced water from the northern and southern portions of the
7 San Juan Basin differ in TDS, due to ground water recharge in the northern basin leading to higher
8 chloride concentrations than in the southern portion [Dahm etal.. 2011: Van Voast. 2003).
9 Spatial variability of produced water content also exists at a local level due to the stratigraphy
10 surrounding the producing formation. For example, deep saline aquifers, if present in the over- or
11 underlying strata, may over geologic time encroach upon shales, coals, and sandstones via fluid
12 intrusion processes [Blauch etal.. 2009). Evidence of deep brine migration from adjacent strata into
13 shallow aquifers via natural faults and fractures has been noted previously in the Michigan Basin
14 and the Marcellus Shale [Vengosh etal.. 2014: Warner etal.. 2012: Weaver etal.. 1995]. By
15 extension, in situ hydraulic connectivity, which is stimulated by design during hydraulic fracturing,
16 may lead to the migration of brine-associated constituents in under- and overlying strata into
17 producing formations, as discussed in Chapter 6.
18 As hydrocarbon source rocks often form repeating sedimentary sequences, contact between these
19 layers presents opportunities for an exchange of organics and inorganics [Fredrickson and Balkwill.
20 2006: U.S. EPA. 2004). For instance, diffusion of carbon sources and electron donors occurs at
21 subsurface shale-sandstone interfaces, suggesting a stratigraphic role in the exchange of
22 constituents between formations [Fredrickson and Balkwill, 2006].
E.4. Example Calculation for Roadway Transport
2 3 This section provides background information for the roadway transport calculation appearing in
24 Chapter 7.
E.4.1. Estimation of Transport Distance
25 In a study of wastewater management for the Marcellus Shale, Rahm etal. [2013] used data
26 reported to the Pennsylvania Department of Environmental Protection (PA DEP] to estimate the
27 average distance wastewater was transported. For the period from 2008 to 2010, the distance
28 transported was approximately 100 km, but it was reduced by 30% for 2011. The reduction was
29 attributed to increased treatment infrastructure in Lycoming County, an area of intensive hydraulic
30 fracturing operations in northeastern Pennsylvania. For the part of Pennsylvania within the
31 Susquehanna River Basin, Gilmore etal. [2013] estimated the likely transport distances for drilling
32 waste to landfills (256 km or 159 mi]; produced water to disposal wells (388 km or 241 mi]; and
33 commercial wastewater treatment plants (CWTPs] (158 km or 98 mi]. These distances are longer
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Hydraulic Fracturing Drinking Water Assessment
Appendix E
1 than the values from Rahm_et_aL_[2M3}.. in part, because wells in the Susquehanna Basin are
2 further to the east of Ohio disposal wells and some CWTPs.
E.4.2. Estimation of Wastewater Volumes
3 In an example water balance calculation, Gilrnore_etaLX2013} used 380,000 gal of flowback as the
4 volume transported to CWTPs, 450,000 gal of flowback transported to injection wells, and 130,000
5 gal of un-reusable treated water also transported to injection wells for a total estimated wastewater
6 volume of 960,000 gal per well.
E.4.3. Estimation of Roadway Accidents
7 The U.S. Department of Transportation (DOT) published statistics on roadway accidents (UJL
8 De^artmejit_of_Transportation1_2^12.] which indicate that the combined total of combination truck
9 crashes in 2012 was 179,736, or 110 per 100 million vehicle miles (1.77 million km) (see Table
10 E-12). As an indicator of the uncertainty of these data, DOT reported 122,240 large truck crashes
11 from a differing set of databases (see Table E-13), with a rate of 75 per 100 million vehicle miles,
12 which is 68% of the number of combination truck crashes.
Table E-12. Combination truck crashes in 2012 for the 2,469,094 registered combination
trucks, which traveled 163,458 million miles (U.S. Department of Transportation,
2012).a
Type of crash
Property damage only
Injury
Fatal
Total
Combination trucks
involved in crashes
135,000
42,000
2,736
179,736
Rates per 100 million vehicle miles
traveled by combination trucks
82.8
25.5
1.74
110
3 A combination truck is defined as a truck tractor pulling any number of trailers (Uj
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Appendix E
Table E-13. Large truck crashes in 2012 (U.S. Department of Transportation, 2012).a
Type of crash
Towaway crashes
Injury
Fatal
Totals
Total crashes
72,644
45,794
3,802
122,240
Large trucks with cargo tanks
Number
4,364
3,245
360
7,969
Percentage
6.0%
7.1%
9.5%
6.5%
a A large truck is defined as a truck with a gross vehicle weight rating greater than 10,000 pounds (U.S. Department of
Transportation, 2012).
E.4.4. Estimation of Material Release Rates in Crashes
1 Estimates ranging from 5.6% to 36% have been made for the probability of material releases from
2 crashed trucks. Craft [2004] used data from three databases to estimate the probability of spills in
3 fatality accidents at 3 6%, which may overestimate the probability for all types of accidents [Rozell
4 and Reaven, 2012].l The U.S. Department of Transportation [2012] provides estimates of
5 hazardous materials releases from large truck crashes. For all types of hazardous materials carried,
6 408 of 2,903 crashes, or 14%, were known to have hazardous materials releases. The occurrence of
7 a release was unknown for 18% of the crashes. These crashes were not distinguished by truck type,
8 so they likely overestimated the number of tanker crashes. Harwoodetal. [1993] used accident
9 data from three states (California, Illinois, and Michigan] to develop hazardous materials release
10 rate estimates for different types of roadways, accidents, and settings (urban or rural]. For
11 roadways in rural settings the probability of release ranged from 8.1% to 9.0%, while in urban
12 settings the probability ranged from 5.6% to 6.9%.
E.4.5. Estimation of Volume Released in Accidents
13 Based on the estimated volume (960,000 gal (3.63 million L] per well] and disposal distances used
14 byRahmetal. [2013] and Gilmore etal. [2013], and an assumed 20,000 L (5,300 gal]-containing
15 truck [Gilmore etal.. 2013]. the total travel distance by trucks ranges from 9,620 miles (14,900 km]
16 to 17,760 miles (28,570 km] per well (see Table E-14].
1 The three databases were the Trucks Involved in Fatal Accidents developed by the Center for National Truck Statistics at
the University of Michigan, the National Automotive Sampling System's General Estimates System (GES) produced by the
National Highway Transportation Safety Agency, and the Motor Carrier Management Information System (MCMIS) Crash
File produced by the Federal Motor Carrier Safety Administration.
June 2015
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Appendix E
Table E-14. Estimate of total truck-travel miles per well in the Susquehanna River Basin based
on the transport analysis performed by Gilmore et al. (2013)1
Action
Waste per well
(million gal)
Gilmore et al. (2013) distance estim
Produced water
to CWTP
Produced water
to disposal well
CWTP effluent to
disposal well
Total
Rahm et al. (2013)
Transport 100 km
Transport 70 km
0.38
0.45
0.13
0.96
Trucks
(20 mVtruck)
Miles
traveled
per truck
Total miles
traveled
(per well)
Material release rate bounds
5.6%
36%
Crashes per 100 million miles
75
110
75
110
ates
72
85
25
182
26.9
147
133
1,937
12,495
3,325
17,757
3
4
18
27
distance estimates
0.96
0.96
182
182
62.1
43.5
11,300
9,620
2
1
3
2
12
8
17
12
1 The Susquehanna River Basin Commission reported 1,928 well pads permitted within the basin
2 [SRBC. 2012]. Assuming two wells per pad, the total distance traveled to haul hydraulic fracturing
3 wastewater is 68.4 million miles (110 million km).
4 Combining these data with the DOT crash data gives an estimated 76 crashes per year using the
5 combination truck crash rate or 52 per year using the DOT large truck crash rate. Based on the
6 various assumptions of travel distances, crash rates, and estimated minimum and maximum
7 material release rates, the number of crashes with releases ranges from 1 to 27 (see Table E-14).
8 Several limitations are inherent in this analysis, including differing rural road accident rates and
9 highway rates, differing wastewater endpoints, and differing amounts of produced water transport
10 Further, the estimates present an upper bound on impacts, because not all releases of wastewater
11 would reach or impact drinking water resources.
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Hydraulic Fracturing Drinking Water Assessment Appendix E
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Hydraulic Fracturing Drinking Water Assessment Appendix F
Appendix F
Wastewater Treatment and Waste Disposal
Supplemental Information
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
Appendix F. Wastewater Treatment and Waste
Disposal Supplemental Information
1 This appendix provides additional information for context and background to support the
2 discussions of hydraulic fracturing waste water management and treatment in Chapter 8 of the
3 Hydraulic Fracturing Drinking Water Assessment Information in this appendix includes: estimates
4 compiled for several states for volumes of wastewater generated in regions where hydraulic
5 fracturing is occurring; an overview of the technologies that can be used to treat hydraulic
6 fracturing wastewater; calculations of estimated treatment process effluent concentrations for
7 example constituents; a description of the different discharge options for centralized waste
8 treatment plants; and the water quality needed for wastewater to be reused for hydraulic
9 fracturing. Discussion is also provided on difficulties that can arise during treatment of hydraulic
10 fracturing wastewaters: the potential impacts of hydraulic fracturing wastewater on biological
11 treatment processes; and an overview of the formation of disinfection byproducts.
F.I. Estimates of Wastewater Production in Regions where Hydraulic
Fracturing is Occurring
12 Table F-l presents estimated wastewater volumes for several states in areas with hydraulic
13 fracturing activity. These data were compiled from production data available on state databases
14 and were tabulated by year. For California, data were compiled for Kern County, where about 95%
15 of hydraulic fracturing is taking place (CCST,_2015.). Production records from Colorado, Utah, and
16 Wyoming include the producing formation for each well reported; data from these states were
17 filtered to select data from formations indicated in the literature as targets for hydraulic fracturing.
18 Data presented for these three states include statewide estimates as well as estimates for selected
19 basins. Data from New Mexico are available from the states in files for three basins as well as for the
2 0 state; these data were not filtered further.
21 Results in Table F-l illustrate some of the challenges associated with obtaining estimates of
2 2 hydraulic fracturing wastewater volumes, especially using publicly available data. Some of the
23 values likely include reported values from conventional wells (wells that may not be hydraulically
24 fractured, and are typically not subject to modern, high volume hydraulic fracturing). For example,
25 the well counts for California, Colorado, Utah, and Wyoming were in the thousands or tens of
26 thousands at least as early as 2000, several years before the surge of modern hydraulic fracturing
27 began in the mid-2000s. The data used for California were from Kern County but are not specific to
2 8 hydraulic fracturing activity. Where producing formations are provided, the accuracy of the
29 estimates will depend upon correct selection of hydraulically fractured formations. Thus, both
3 0 underestimation and overestimation may be possible because of a lack of clear indication of which
31 wells were hydraulically fractured.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Table F-l. Estimated volumes (millions of gallons) of wastewater based on state data for selected years and numbers of wells
producing fluid.
State
California
Colorado
Basin
San Joaquin3
All basins
with hy-
draulically
fractured
formations
Denver
Piceance
Principal
lithologies
Shale,
unconsoli-
dated sands
-
Sandstone,
shale
Sandstone
Data type
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
2000
46,000
33,695
7,300
11,264
140
1,829
3,500
1,134
2004
48,000
39,033
11,000
14,934
160
1,511
5,800
2,473
2008
58,000
46,519
21,000
28,282
170
1,277
9,300
6,486
2010
65,000
49,201
14,000
33,929
160
1,204
6,900
9,105
2011
71,000
51,031
12,000
35,999
160
1,193
6,500
10,057
2012
75,000
51,567
12,000
33,371
150
1,131
6,800
10,868
2013
74,000
52,763
7,700
37,613
110
1,072
4,300
10,954
2014
-
-
-
-
-
-
-
-
Comments
Data from CA Department of
Conservation, Oil and Gas
Division.3 Produced water data
compiled for Kern County.
Data may also represent
contributions from production
without hydraulic fracturing.
Data from CO Oil and Gas
Conservation Commission. b
Produced water includes
flowback. Data filtered for
formations indicated in
literature as undergoing
hydraulic fracturing and
matched to corresponding
basins. Example counties
selected for presentation as
well as estimated state total.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
State
Colorado,
cont.
New Mexico
Basin
Raton
San Juan
Permian
Raton
San Juan
Total
Principal
lithologies
Coalbed
methane
Coalbed
methane
Shale,
sandstone
Coalbed
methane
Coalbed
methane
-
Data type
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
2000
2,400
681
1,000
1,183
-
-
-
-
-
-
-
-
2004
4,100
1,634
1,100
1,605
-
-
-
-
-
-
-
-
2008
8,900
2,795
1,300
1,975
-
-
-
-
-
-
-
-
2010
4,300
2,734
2,000
2,220
-
-
-
-
-
-
-
-
2011
3,200
2,778
1,200
2,303
-
-
-
-
-
-
-
-
2012
2,700
2,710
1,100
2,328
31,000
29,839
510
1,495
1,700
22,492
33,000
53,826
2013
2,100
2,545
650
2,333
31,000
30,336
540
1,502
2,000
22,349
34,000
54,237
2014
-
-
-
-
20,000
30,237
310
1,526
1,100
22,076
22,000
53,889
Comments
Data from New Mexico Oil
Conservation Division.0 Data
provided by the state by basin
and for the entire state.
Unclear how much
contribution from production
without hydraulic fracturing.
Produced water includes
flowback.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
State
Utah
Wyoming
Basin
All basins
with hy-
draulically
fractured
formations
Kaiparowits/
Uinta
San Juan/
Uinta
Uinta
All basins
with hy-
draulically
fractured
formations
Principal
lithologies
-
Coalbed
methane
Coalbed
methane
Shale/sand-
stone
-
Data type
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
2000
1,200
3,080
860
1,718
2
62
350
1,067
1,300
2004
1,200
4,377
740
2,517
49
223
420
1,396
1,400
2008
2,300
7,409
1,300
3,761
350
910
560
2,282
1,300
2010
2,400
S,432
1,400
4,329
270
933
680
2,745
1,500
2011
2,700
9,101
1,800
4,838
240
959
700
2,888
1,600
2012
2,900
10,075
2,000
5,538
230
951
640
3,115
1,700
2013
3,400
10,661
2,400
6,046
190
867
830
3,257
1,600
2014
2,800
10,900
1,900
6,334
120
870
790
3,223
1,800
Comments
Data from State of Utah Oil
and Gas Program. d Produced
water includes flowback. Data
filtered by formation indicated
in the literature as hydraul-
ically fractured and matched to
basins. Data presented for
selected basins as well as for
all formations likely to be
hydraulically fractured.
Data from Wyoming Oil and
Gas Conservation
Commission.6 Produced water
may include flowback. Data
filtered by formation indicated
in the literature as
hydraulically fractured and
matched to basins. Data
presented for selected basins
as well as for all formations
likely to be hydraulically
fractured.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
State
Wyoming,
cont.
Basin
Big Horn
Denver
Green River
Powder
River
Wind River/
Powder
River
Principal
lithologies
Sandstone
Sandstone
Sandstone/
shale
Coalbed
methane
Sandstone/
shale
Data type
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
Produced
water
Wells
2000
3,470
380
365
54
142
0
44
690
1,953
130
966
2004
3,373
350
359
44
118
1
44
630
1,900
330
957
2008
3,535
350
387
49
124
2
60
620
2,001
330
1,013
2010
3,620
380
397
59
140
8
67
660
2,028
400
988
2011
3,728
430
412
76
167
5
67
700
2,119
420
963
2012
3,843
440
414
90
204
5
59
840
2,207
290
959
2013
4,030
420
407
97
230
9
64
970
2,352
110
977
2014
4,213
440
403
170
278
15
67
1,100
2,565
41
900
Comments
a California Department of Conservation, Oil and Gas Division. Oil & Gas - Online Data. Monthly Production and Injection Databases:
ftp://ftp.consrv.ca.gov/pub/oil/new database format/.
b Colorado Oil and Gas Conservation Commission. Data: Downloads: Production Data: http://cogcc.state.co.us/data2.htmlff/downloads.
c New Mexico Oil Conservation Division. Production Data. Production Summaries: All Wells Data: http://gotech.nmt.edu/gotech/Petroleum Data/allwells.aspx.
d Utah Department of Natural Resources. Division of Oil, Gas, and Mining. Data Research Center. Database Download Files:
http://oilgas.ogm.utah.gov/Data Center/DataCenter.cfmffproduction.
e Wyoming Oil and Gas Conservation Commission. Production files by county and year:
http://wogcc.state.wy. us/prod uctioncountvvear.cfm?Oops=#oops#&RequestTimeOut=6500.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
F.2. Overview of Treatment Processes for Treating Hydraulic Fracturing
Wastewater
1 Treatment technologies discussed in this appendix are classified as basic or advanced. Basic
2 treatment technologies are ineffective for reducing total dissolved solids (TDS) and are typically not
3 labor intensive. Advanced treatment technologies can remove TDS and/or are complex in nature
4 (e.g., energy- and labor-intensive).
F.2.1. Basic Treatment
5 Basic treatment technologies include physical separation, coagulation/oxidation,
6 electrocoagulation, sedimentation, and disinfection. These technologies are effective at removing
7 total suspended solids (TSS), oil and grease, scale-forming compounds, and metals, and they can
8 minimize microbial activity. Basic treatment is typically incorporated in a permanent treatment
9 facility (i.e., fixed location) but can also be part of a mobile unit for onsite treatment applications.
F.2.1.1. Physical Separation
10 The most basic treatment need for oil and gas wastewaters, including those from hydraulic
11 fracturing operations, is separation to remove suspended solids, and oil and grease. The separation
12 method largely depends on the type of resource (s) targeted by the hydraulic fracturing operation.
13 Down-hole separation techniques, including mechanical blocking devices and water shut-off
14 chemicals to prevent or minimize water flow to the well, may be used during production in shale
15 plays containing greater amounts of liquid hydrocarbons. To treat water at the surface, separation
16 technologies such as hydrocyclones, dissolved air or induced gas flotation systems, media (sand)
17 filtration, and biological aerated filters can remove suspended solids and some organics from
18 hydraulic fracturing wastewater.
19 Media filtration can also remove hardness and some metals if chemical precipitation (i.e.,
20 coagulation, lime softening) is also employed (Boschee.JJllJ:). An example of a centralized waste
21 treatment facility (CWT) that uses chemical precipitation and media filtration to treat hydraulic
22 fracturing waste is the Water Tower Square Gas Well Wastewater Processing Facility in
23 Pennsylvania (see Table 8-7). One or more of these technologies is typically used prior to advanced
24 treatment such as reverse osmosis (RO) because advanced treatment processes foul, scale, or
25 otherwise do not operate effectively in the presence of TSS, certain organics, and/or some metals
26 and metalloid compounds (BosA^S±MHA', Drewes^aij^iKW). The biggest challenge associated
27 with use of these separation technologies is solids disposal from the resulting sludge (IgunmLind
28 OieiLlQll).
F.2.1.2. Coagulation/Oxidation
29 Coagulation is the process of agglomerating small, unsettleable particles into larger particles to
30 promote settling. Chemical coagulants such as alum, iron chloride, and polymers can be used to
31 precipitate TSS, some dissolved solids (except monovalent ions such as sodium and chloride), and
32 metals from hydraulic fracturing wastewater. Adjusting the pH using chemicals such as lime or
33 caustic soda can increase the potential for some constituents, including dissolved metals, to form
34 precipitates. Chemical precipitation is often used in industrial wastewater treatment as a
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
1 pretreatment step to decrease the pollutant loading on subsequent advanced treatment
2 technologies; this strategy can save time, money, energy consumption and the lifetime of the
3 infrastructure.
4 Processes using advanced oxidation and precipitation have been applied to hydraulic fracturing
5 wastewaters in on-site and mobile systems. Hydroxyl radicals generated by cavitation processes
6 and the addition of ozone can degrade organic compounds and inactivate micro-organisms. The
7 process can also aid in the precipitation of elements, which cause hardness and scaling in the
8 treated water (e.g. calcium, magnesium). The process can also reduce sulfate and carbonate
9 concentrations in the treated water. This type of treatment can be very effective for on-site reuse of
10 waste water [Ely etal.. 2011].
11 The produced solid residuals from coagulation/oxidation processes typically require further
12 treatment, such as de-watering [Duraisamy etal., 2013: Hammer and VanBriesen, 2012].
F.2.1.3. Electrocoagulation
13 Electrocoagulation (EC] (Figure F-l] combines the principles of coagulation and electrochemistry
14 into one process (Gomes etal.. 2009]. An electrical current added to the wastewater produces
15 coagulants that then neutralize the charged particles, causing them to destabilize, precipitate, and
16 settle. EC may be used in place of, or in addition to, chemical coagulation. EC can be effective for
17 removal of organics, TSS, and metals, but it is less effective for removing TDS and sulfate. Although
18 it is still considered an emerging technology for unconventional oil and gas wastewater treatment,
19 EC has been used in mobile treatment systems to treat hydraulic fracturing wastewaters
20 (Halliburton. 2014: Igunnu and Chen. 2014]. Limitations with this technology are the potential for
21 scaling, corrosion, and bacterial growth (Gomes etal.. 2009].
Figure F-l. Electrocoagulation unit.
Source: Dunkel (2013).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
F.2.1.4. Sedimentation
1 Treatment plants may include sedimentation tanks, clarifiers, or some other form of settling basin
2 to allow larger particles to settle out of the water where they can eventually be collected,
3 dewatered, and disposed of. These types of tanks/basins all serve the same purpose - to reduce the
4 amount of solids going to subsequent processes (i.e., overload the media filters).
F.2.1.5. Disinfection
5 Some hydraulic fracturing applications may require disinfection to kill bacteria after treatment and
6 prior to reuse. Chlorine is a common disinfectant. Chlorine dioxide, ozone, or ultraviolet light can
7 also be used. This is an important step for reused water because bacteria can cause problems for
8 further hydraulic fracturing operations by multiplying rapidly and causing build-up in the well
9 bore, which decreases gas extraction efficiency.
F.2.2. Advanced Treatment
10 Advanced treatment technologies consist of membranes (reverse osmosis (RO), nanofiltration,
11 ultrafiltration, microfiltration, electrodialysis, forward osmosis, and membrane distillation),
12 thermal distillation technologies, crystallizers, ion exchange, and adsorption. These technologies
13 are effective for removing TDS and/or targeted compounds. They typically require pretreatment to
14 remove solids and other constituents that may damage or otherwise impede the technology from
15 operating as designed. Advanced treatment technologies can be energy intensive and are typically
16 employed when a purified water effluent is necessary for direct discharge, indirect discharge, or
17 reuse. In some instances, these water treatment technologies can make use of methane generated
18 by the gas well as an energy source. Some advanced treatment technologies can be made mobile for
19 on-site treatment.
F.2.2.1. Membranes
20 Pressure-driven membrane processes including microfiltration, ultrafiltration, nano filtration, and
21 RO (Figure F-2) are being used in some settings to treat oil and gas wastewater. These processes
22 use hydraulic pressure to overcome the osmotic pressure of the influent waste stream, forcing clean
23 water through the membrane (Drewes^taL_2009_). Microfiltration and ultrafiltration processes do
24 not reduce TDS but can remove TSS and some metals and organics (Drewes^taL.2009.). RO and
25 nano filtration are capable of removing TDS, including anions and radionuclides. RO, however, may
26 be limited to treating TDS levels of approximately 40,000 mg/L TDS (Shaffer_etaL_2013j Younos
27
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Figure F-2. Photograph of reverse osmosis system.
Source: Thinkstock.
f.2.2.2. Electrodialysis
1 Electrodialysis relies on positively and negatively charged particles and coated membranes to
2 separate contaminants from the water (Figure F-3). Electrodialysis has been considered for use by
3 the shale gas industry, but it is not currently widely utilized [ALL Consulting. 2013). IDS
4 concentrations above 15,000 mg/L are difficult to treat by electrodialysis [ALL Consulting, 2013],
5 and oil and divalent cations (e.g. Ca, Fe, Mg) can foul the membranes (Hayes and Severin, 2012b:
6 Guolinetal.,2008].
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Figure F-3. Picture of mobile electrodialysis units in Wyoming.
Source: DOE (2006). Permission: ALL Consulting.
F.2.2.3. Forward Osmosis/Membrane Distillation
1 Forward osmosis, an emerging technology for treating hydraulic fracturing wastewater, uses an
2 osmotic pressure gradient across a membrane to draw the contaminants from a low osmotic
3 solution (the feed water) to a high osmotic solution [Drewes etal.. 2009]. The selection of the
4 constituents for the draw solution is very important as the constituents should be more easily
5 removed from solution than the compounds (e.g. salts) in the feed. Alternatively, draw solutions can
6 contain components that are more easily reused or recycled. Another emerging technology,
7 membrane distillation, relies on a thermal gradient across a membrane surface to volatilize pure
8 water and capture it in the distillate (Drewes et al., 2009).
F.2.2.4. Thermal Distillation
9 Thermal distillation technologies, such as mechanical vapor recompression (MVR) (Figure F-4) and
10 dewvaporation, use liquid-vapor separation by applying heat to the waste stream, vaporizing the
11 water to separate out impurities, and condensing the vapor into distilled water (Drewes etal.,
12 2009: LEauLLC. 2008: Hamieh and Beckman. 20061 MVR and dewvaporation can treat high-TDS
13 waters and have been proven in the field as effective for treating oil and gas wastewater (Hayes and
14 Severin. 2012b: Drewes etal.. 2009). Like RO, these processes are energy intensive and are used
15 when the objective is very clean water (i.e., TDS less than 500 mg/L) for direct/indirect discharge
16 or if clean water is needed for reuse. As with membrane processes, scaling is an issue with these
17 technologies, and scale inhibitors may be needed for them to operate effectively (Igunnu and Chen.
18 2014).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Figure F-4. Picture of a mechanical vapor recompression unit near Decatur, Texas.
Source: Drewes et al. (2009). Permission provided.
1 CWTs such as the Judsonia Central Water Treatment Facility in Arkansas, and the Casella-Altela
2 Regional Environmental Services and Clarion Altela Environmental Services, both in Pennsylvania,
3 have NPDES permits and use MVR or thermal distillation for IDS removal. Figure F-5 shows a
4 diagram of the treatment train at another facility, the Maggie Spain facility in Texas, which uses
5 MVR in its treatment of Barnett Shale wastewater [Hayes and Severin. 2012a).
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Flowback
Delivery
Flash Mixer
Lime and
Polymer,
pHIO
Concentrated
Brine to
Deep Well
or Reuse
Surge Tank
Acid to pH 4
Product Water Storage
Filtrate
Product Water
to Reuse or Discharge
Sludge Cake
to Landfill
Figure F-5. Mechanical vapor recompression process design - Maggie Spain Facility.
Adapted from: Hayes and Severin (2012a).
1 Crystallizers can be employed at CWTs to treat high-TDS waters or to further concentrate the waste
2 stream from a distillation process, reducing residual waste disposal volumes. The crystallized salt
3 can be landfilled, deep-well injected, or used to produce pure salt products that may be salable
4 [ErteletaL 20131.
5 Another thermal method, freeze-thaw evaporation, involves spraying wastewater onto a freezing
6 pad, allowing ice crystals to form, and the brine mixture that remains in solution to drain from the
7 ice [Drewes etal.. 2009]. In warmer weather, the ice thaws and the purified water is collected. This
8 technology cannot treat waters with high methanol concentrations and is only suitable for areas
9 where the temperature is below freezing in the winter months [Igunnu and Chen. 2014). In
10 addition, freeze-thaw evaporation can only reduce TDS concentrations to approximately 1,000
11 mg/L, which is higher than the 500 mg/L TDS surface water discharge limit required by most
12 permits [Igunnu and Chen, 2014].
F.2.2.5. Ion Exchange and Adsorption
13 Ion exchange (Figure F-6) is the process of exchanging ions on a media referred to as resin for
14 unwanted ions in the water. Ion exchange is used to treat for target ions that may be difficult to
15 remove by other treatment technologies or that may interfere with the effectiveness of advanced
16 treatment processes.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Figure F-6. Picture of a compressed bed ion exchange unit.
Source: Drewes et al. (2009). Permission provided.
1 Adsorption is the process of adsorbing contaminants onto a charged granular media surface.
2 Adsorption technologies can effectively remove organics, heavy metals, and some anions [Igunnu
3 and Chen. 2014]. With ion exchange and adsorption processes, the type of resin or adsorptive
4 media used (e.g., activated carbon, organoclay, zeolites) dictates the specific contaminants that will
5 be removed from the water [Drewes etal.. 2009: Fakhru'1-Razi et al.. 2009).
6 Because they can be easily overloaded by contaminants, ion exchange and adsorption treatment
7 processes are generally used as a polishing step following other treatment processes or as a unit
8 process in a treatment train rather than as stand-alone treatment [Drewes etal., 2009]. Stand-alone
9 units require more frequent regeneration and/or replacement of the spent media making these
10 technologies more costly to operate [Igunnu and Chen, 2014]. Figure F-7 shows a schematic of the
11 Pinedale Anticline Water Reclamation Facility located in Wyoming, which uses an ion exchange unit
12 with boron-selective resin as a polishing step to treat hydraulic fracturing wastewater specifically
13 for boron [Boschee. 2012].
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Figure F-7. Discharge water process used in the Pinedale Anticline field.
Source: Boschee (2012).
F.3. Treatment Technology Removal Capabilities
1 Table F-2 provides removal efficiencies for common hydraulic fracturing wastewater constituents
2 by treatment technology. With the exception of TSS and TDS, the studies cited demonstrate removal
3 for a subset of constituents in a category [e.g.. Gomes et al.. 2009] reported that electrodialysis was
4 an effective treatment for oil and grease, not all organics). The removal efficiencies include ranges
5 of 1 to 33% (denoted by +), 34% to 66% (denoted by ++), and greater than 66% removal (denoted
6 by +++). Cells denoted with "--" indicate that the treatment technology is not suitable for removal of
7 that constituent or group of constituents. If a particular treatment technology only lists removal
8 efficiencies for TDS, it can be assumed that in some cases, cations and anions would also be
9 removed by that technology; therefore, where specific results were not provided in literature, cells
10 denoted with "Assumed" refer to cations and anions that comprise TDS.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Table F-2. Removal efficiency of different hydraulic fracturing wastewater constituents using
various wastewater treatment technologies.3
Treatment
Technology
Hydrocyclones
Evaporation
(freeze-thaw
evaporation)
Filtration
(granular media)
Chemical
precipitation
Sedimentation
(clarifier)
Dissolved air
flotation
Electro-
coagulation
Advanced
oxidation and
precipitation
Hydraulic Fracturing Wastewater Constituents
TSS
+++
(Duraisamy et
al.,2013)
+++
(Igunnu and
Chen, 2014;
Drewes et al..
2009)
+++
(Barrett, 2010)
+++
(Fakhru'l-Razi
etal., 2009)
++
(NMSU DACC
WUTAP, 2007)
+++
(Shammas,
2010)
+++
(Igunnu and
Chen, 2014;
Bukhari, 2008)
TDS
"
+++
(Igunnu and
Chen, 2014;
Drewes et al..
2009; Arthur
etal., 2005)
+
(Abrams,
2013)
Anions
Assumed
Metals
+++
(Igunnu and
Chen, 2014;
Drewes et al..
2009; Arthur
et al., 2005)
+++b
(Duraisamv et
al.,2013)
+++
(Fakhru'l-Razi
et al., 2009;
AWWA, 1999)
+
(Igunnu and
Chen, 2014)
+/+++
(Abrams,
2013)
Radio-
nuclides
"
+++c
(Zhang et al..
2014)
Organics
++
(Duraisamv et al.,
2013)
+++
(Igunnu and
Chen, 2014;
Duraisamv et al.,
2013; Drewes et
al., 2009)
+++
(Shafer, 2011;
Drewes et al.,
2009)
+++
(Fakhru'l-Razi et
al., 2009)
++/+++
(Duraisamv et al..
2013; Fakhru'l-
Razi et al., 2009)
+++
(Igunnu and
Chen, 2014;
Duraisamv et al..
2013; Fakhru'l-
Razi et al., 2009)
+++d
(Duraisamv etal..
2013)
(Fakhru'l-Razi et
al., 2009)
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Treatment
Technology
Reverse osmosis
Membrane
filtration (UF/MF)
Forward osmosis
Distillation,
including thermal
distillation (e.g.,
mechanical vapor
recompression
(MVR))
Ion exchange
Crystallization
Electrodialysis
Capacitive
deionization
(emerging
technology)
Hydraulic Fracturing Wastewater Constituents
TSS
+++
(Arthur et al.,
2QQ5)
-
TDS
++/+++e
(Alzahrani et
al., 2013;
Drewes et al..
2009)
+++
(Drewes et al..
2009)
+++'
(Haves et al.,
2014; Bruff
and Jikich,
2011; Drewes
etal., 2009)
+++
(ER, 2014)
+++k
(Drewes et al..
2009; Gomes
et al., 2009;
Arthur et al.,
2005)
+++'
(Drewes etal..
2009)
Anions
+++
(Alzahrani et
al.,2013)
(Arthur etal..
2QQ5)
Assumed
+++
(Bruff and
Jikich, 2011;
Drewes et al..
2009)
+++
(Drewes et
al., 2009)
Assumed
++/+++
(Banasiak and
Schafer,
2009)
Metals
++/+++f
(Alzahrani et
al.,2013)
(Drewes et al..
2009; AWWA,
1999)
+++
(Fakhru'l-Razi
et al., 2009)
Assumed
+++
(Haves et al.,
2014; Bruff
and Jikich,
2011; Drewes
et al., 2009)
+++
(Drewes et al..
2009; Arthur
et al., 2005)
Assumed
+/++/+++
(Banasiak and
Schafer, 2009)
Radio-
nuclides
+++
(Drewes et
al., 2009)
+++
(Bruff and
Jikich, 2011;
Drewes et
al., 2009)
+++
(Drewes et
al., 2009)
-
Organics
+/++/+++S
(Drewes et al.,
2009; Munter,
2000)
++/+++
(Duraisamy et al.,
2013; Fakhru'l-
Razi et al., 2009;
Haves and
Arthur, 2004;
AWWA, 1999)h
+/++/+++
(Haves et al..
2014; Duraisamy
et al., 2013;
Drewes et al.,
2009; Fakhru'l-
Razi et al., 2009)
+/++/+++
(Fakhru'l-Razi et
al., 2009;
Munter, 2000 )J
-
+++
(Gomes et al..
2009)
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-16 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Treatment
Technology
Adsorption"1
Biological
treatment
Constructed
wetland/reed
beds
Hydraulic Fracturing Wastewater Constituents
TSS
+++
(Igunnu and
Chen, 2014;
Drewes et al..
2009)
++/+++
(Manios et al..
2QQ3)
TDS
+
(Arthur et al..
2005)
Anions
+/++/+++"
(Habuda-
Stanic et al..
2014)
Metals
+++
(Igunnu and
Chen, 2014;
Drewes et al..
2009)
++/+++
(Fakhru'l-Razi
et al., 2009)
Radio-
nuclides
Organics
+/++/+++
(Arthur et al.,
2005; Haves and
Arthur, 2004;
Munter, 2000)
+/++/+++
(Igunnu and
Chen, 2014;
Drewes et al.,
2009; Fakhru'l-
Razi et al., 2009)
+/+++
(Fakhru'l-Razi et
al., 2009; Arthur
et al., 2005)
a To the extent possible, removal efficiencies are based on an individual treatment technology that does not assume extensive
pretreatment or combined treatment processes. However, it should be noted that some processes cannot effectively operate
without pretreatment (e.g., RO, media filtration, sedimentation).
b Pretreatment (pH adjustment, aeration, solids separation) required.
c Radium co-precipitation with barium sulfate.
d The Fenton process.
e Typically requires pretreatment. Not a viable technology if TDS influent >50,000 mg/L.
f Iron and manganese oxides will foul the membranes.
g Some organics will foul the membranes (e.g., organic acids).
h Ultrafiltration membrane was modified with nanoparticles.
' Can typically handle high TDS concentrations.
J Resin consisted of modified zeolites that targeted removal of BTEX.
k Influent TDS for this technology should be <8,000 mg/L.
1 Specific technology was an electronic water purifier which is a hybrid of capacitive deionization. Influent TDS for this
technology should be <3,000 mg/L.
m Typically polishing step, otherwise can overload bed quickly with organics.
" Removal efficiency is dependent on the type of adsorbent used and the water quality characteristics (e.g., pH).
1 Given the variety of properties among classes of organic constituents, different treatment processes
2 may be required depending upon the types of organic compounds needing removal. Table F-3 lists
3 treatment processes and the classes of organic compounds they can treat
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-17 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Table F-3. Treatment processes for hydraulic fracturing wastewater organic constituents.
Treatment processes
Adsorption with activated carbon
Adsorption with organoclay media
Aeration
Dissolved air flotation
Freeze/thaw evaporation3
Ion exchange (with modified
zeolites)
Distillation
Chemical precipitation
Chemical Oxidation
Media filtration (walnut shell
media or sand)
Microfiltration
Ultrafiltration
Reverse osmosisb
Electrocoagulation
Biologically aerated filters
Reed bed technologies
Hydrocyclone separators
Organic compounds removed
Soluble organic compounds
Insoluble organic compounds
Volatile organic compounds
Volatile organic compounds, dispersed oil
TPH, volatile organic compounds, semi-
volatile organic compounds
BTEX, chemical oxygen demand,
biochemical oxygen demand
BTEX, polycyclic aromatic hydrocarbons
(PAHs)
Oil & grease
Oil & grease
Oil & grease
Oil & grease
Oil & grease, BTEX
Dissolved organics
Chemical oxygen demand, Biochemical
oxygen demand
Oil & grease, TPH, BTEX
Oil & grease, TPH, BTEX
Dispersed oil
References
Fakhru'l-Razietal. (2009)
Fakhru'l-Razietal. (2009)
Tchobanoglous et al. (2013)
Drewes et al. (2009)
Duraisamy et al. (2013); Drewes
etal. (2009)
Haves et al. (2014); Duraisamy et
al. (2013); Drewes et al. (2009);
Fakhru'l-Razietal. (2009);
Munter (2000)
Hayes et al. (2014); Duraisamy et
al. (2013); Drewes et al. (2009);
Fakhru'l-Razietal. (2009).
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Drewes et al. (2009); Fakhru'l-
Razi et al. (2009)
Drewes etal. (2009); U.S. EPA
(2005)
Fakhru'l-Razietal. (2009)
Fakhru'l-Razietal. (2009)
Fakhru'l-Razietal. (2009)
Drewes et al. (2009)
a Technology cannot be used if the methanol concentration in the hydraulic fracturing wastewater exceeds 5%.
b RO will remove specific classes of organic compounds with removal efficiencies dependent on the compound's structure and
the physical and chemical properties of the hydraulically fractured wastewater. Organoacids will foul membranes.
1 Table F-4 presents estimated effluent concentrations that could be produced by a variety of unit
2 treatment processes for several example constituents and for various influent concentrations. This
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-18 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix F
1 analysis uses treatment process removal efficiencies from literature used to develop Table F-2 and
2 average wastewater concentrations of several constituents presented in Chapter 7 and Appendix E.
3 These estimates were done to illustrate the combined effects of influent wastewater composition
4 and treatment process choice on achievable effluent concentrations. The removal efficiencies
5 represent a variety of studies, primarily at bench and pilot scale, and done with either conventional
6 or hydraulic fracturing wastewater. Removal efficiency for a given treatment process can vary due
7 to a number of factors, and constituent removal may be different in a full-scale facility that uses
8 several processes. Thus, the calculations shown in Table F-4 are intended to be rough
9 approximations for illustrative purposes.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-19 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Table F-4. Estimated effluent concentrations for example constituents based on treatment process removal efficiencies.
Shale/
Sandstone
Play
Bakken
Barnett
Fayetteville
Marcellus
Cotton
Valley
Mesaverde
Marcellus
Bakken
Barnett
Fayetteville
Marcellus
Cotton
Valley
Devonian
Sandstone
Marcellus
Contaminant
Barium
Barium
Barium
Barium
Barium
Barium
Cadmium
Strontium
Strontium
Strontium
Strontium
Strontium
Strontium
Radium 226
MCL
2
2
2
2
2
2
5
-
-
-
-
—
-
-
Avg.
Influent
Cone.
10
3.6
4
2200
160
140
25
760
530
27
1700
2300
3900
620
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
pCi/L
0
+j
E
8
e-Thaw Eva
N
01
£
LL.
2.5
E
O
E
iZ
re
0)
S
i
0.4
0.4
220
16
14
2.5
76
53
2.7
170
230
390
E
O
s
Q.
£
CL
8
E
O)
u
32
-
440
LL.
-------
Hydraulic Fracturing Drinking Water Assessment
Appendix F
Shale/
Sandstone
Play
Devonian
Sandstone
Marcellus
Marcellus
Barnett
Marcellus
Cotton
Valley
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Contaminant
Radium 226
Radium 228
Total Radium
TOC
TOC
TOC
BOD
BOD
O&G
O&G
Benzene
Benzene
Toluene
Toluene
Ethyl benzene
Ethyl benzene
Xylenes
Xylenes
BTEX
MCL
~
-
5
-
-
-
-
-
-
-
5
5
1,000
1,000
700
700
10,000
10,000
-
Avg.
Influent
Cone.
2400
120
2500
9.8
160
200
580
40
160
74
680
360
760
1100
29
150
360
1300
1800
Units
pCi/L
pCi/L
pCi/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Freeze-Thaw Evaporation
68
36
76
110
2.9
15
36
130
180
Media Filtration
16
7.4
0
«
4-»
'5.
•o
01
^
Q.
8
E
01
.c
u
120
6.2
130
-
-
-
1700
85
1800
Flotation (DAF)
17
90
Electro-coagulation
58
4
Advanced Oxidation and
precipitation
7.3
Reverse osmosis
24
1.2
25
Membrane Filtration
(UF/MF)
0.2
3.2
4
16
7.4
310
170
350
510
170
600
Distillation
24
1.2
25
-
-
-
6.8
3.6
91
71
3.6
76
Ion exchange
170
8.4
180
290
20
270
-
-
-
440
30
550
Electrodialysis
8
3.7
Adsorption
0.98
16
20
1.6
0.74
110
58
84
120
3.2
17
14
52
3.7
-
-
-
-
2.9
48
59
91
Biological Treatment
(biodisks, BAFs)
2.1
35
44
29
2
43
19
-
-
-
-
-
4
58
71
87
6
Constructed Wetland
1
16
20
47
3.2
9.8
4.4
ND
ND
ND
ND
ND
ND
ND
ND
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
F-21
DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Shale/
Sandstone
Play
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Barnett
Marcellus
Contaminant
BTEX
Naphthalene
Naphthalene
1,2,4-
Trimethyl-
benzene
1,2,4-
Trimethyl-
benzene
1,2,4-
Trimethyl-
benzene
1,2,4-
Trimethyl-
benzene
MCL
-
-
-
-
-
-
-
Avg.
Influent
Cone.
2900
240
360
170
430
59
310
Units
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
Mg/L
c
o
5.
ze-Thaw Evapo
£
LL.
290
c
Media Filtratio
0
*-
arnica! Precipite
U
1-_s
Flotation (DAF
c
o
ectro-coagulat
IS
c
anced Oxidatio
precipitation
•a
12
0.95
1.4
0.69
1.7
0.24
1.2
(A
Reverse osmos
c
embrane Filtrat
(UF/MF)
c
o
5
150
Ion exchange
440
-
870
Electrodialysis
Adsorption
5.8
-
150
•£
01 . — .
ological Treatm
(biodisks, BAFs
IS
nstructed Wetl
u
ND = Non-detect
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
F-22
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Hydraulic Fracturing Drinking Water Assessment Appendix F
F.4. Centralized Waste Treatment Facilities and Waste Management Options
1 CWTs are designed to treat for site-specific wastewater constituents so that the effluent meets the
2 requirements of the designated disposal option(s) (i.e., reuse, direct/indirect discharge). The most
3 basic treatment processes that a CWT might use include (Eastolk2ill4j DuhorL_2012.):
4 • Physical treatment technologies such as dissolved air or gas flotation technologies, media
5 filtration, hydrocyclones, and clarification;
6 • Chemical treatment technologies such as chemical precipitation and chemical oxidation;
7 and
8 • Biological treatment technologies such as biological aerated filter systems and reed beds.
9 While these technologies are effective at removing oil and grease, suspended solids, scale-forming
10 compounds, and some heavy metals, if IDS should be reduced as required by the intended disposal
11 option, advanced processes such as RO, thermal distillation, or evaporation are necessary.
F.4.1. Discharge Options for CWTs
12 Direct discharge CWTs are allowed to discharge treated wastewater directly to surface waters
13 under the NPDES permit program. Discharge limitations may be based on water quality standards
14 in the NPDES and technology-based effluent limitation guidelines under 40 CFR Part 437. In
15 addition, permitting authorities have permitted facilities for discharge under 40 CFR 435, Subpart
16 E. Judsonia Central Water Treatment Facility in Sunnydale, Arkansas is permitted to directly
17 discharge treated effluent from produced and flowback waters from the Fayetteville Shale play to
18 Byrd pond located on the property. Pinedale Anticline Field Wastewater Treatment Facility in
19 Wyoming, WY, originally designed to treat produced water from tight gas plays in the Pinedale
20 Anticline Field to levels suitable for reuse, was upgraded to include RO treatment for discharge to a
21 local river. CWTs with NPDES discharge permits may also opt to treat oil and gas wastewater for
22 reuse. Some facilities have the ability to treat wastewater to different qualities (e.g., with or without
23 TDS removal), which they might do to target various reuse water quality criteria. Both the Judsonia
24 facility and Pinedale facility discussed above have the ability to employ either TDS- or non-TDS-
25 removal treatment depending on the customers' needs.
26 Indirect discharge CWTs may treat hydraulic fracturing wastewater and then discharge the treated
27 wastewater effluent to a POTW. Discharge to the POTW is controlled by an Industrial User
28 mechanism, which incorporates pretreatment standards established in 40 CFR Part 437. Two
29 facilities located in Pennsylvania (Eureka Resources) and Ohio (Patriot Water Treatment) include
30 indirect discharge as an option in wastewater treatment. The Eureka-Williamsport facility accepts
31 wastewater (primarily from the Marcellus Shale play) and either treats it for reuse or discharges it
32 to the local POTW. The Patriot facility offers services to hydraulic fracturing operators in the
33 Marcellus and Utica Shale plays for removal of solids and metals using chemical treatment. As of
34 March 2015, however, the Patriot facility is limited by the Ohio Environmental Protection Agency in
35 accepting only "low salinity" (<50,000 mg/L TDS) produced water and may only discharge 100,000
36 gallons (380,000 L) per day to the Warren Ohio POTW.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-23 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Zero- discharge CWTs do not discharge treated wastewater; instead, the wastewater is treated and
reused in subsequent hydraulic fracturing operations. WVWEJJ2Q12J state that this practice
reduces potential effects on surface drinking water sources by reducing both direct and indirect
discharges. Zero-discharge facilities may offer different levels of treatment including minimal
treatment (for example, filtration), low-level treatment (chemical precipitation), and/or advanced
treatment (evaporation, crystallization). Reserved Environmental Services (RES) Mt Pleasant,
Pennsylvania, is a zero liquid discharge facility permitted by PA DEP to treat wastewater from the
Marcellus Shale play for reuse. Residual solids are dewatered and sent to a landfill. Treated
wastewater effluent is stored, monitored, and chlorinated for reuse (QWlSiyre^^
F.5. Water Quality for Reuse
As of 2015, there is no consensus on the water quality requirements for reuse of wastewater for
hydraulic fracturing, and operator opinions vary on the minimum standards for the water quality
needed for fracturing fluids (ffidic^eLaL.JOllj MhmjsMM^Mi]. Table F-5 provides a list of
constituents and the recommended or observed target concentrations for reuse applications. The
wide concentration ranges for many constituents (e.g., TDS ranges from 500 to 70,000 mg/L),
suggest that water quality requirements for reuse are dictated by operation-specific requirements,
including operator preference and selection of fracturing fluid chemistry.
Table F-5. Water quality requirements for reuse.
Source: U.S.EPA(2015g).
Constituent
TDS
Chloride
Sodium
Reasons for Limiting
Concentrations
Fluid stability
Fluid stability
Fluid stability
Recommended or observed base fluid target
concentrations (mg/L, after blending)b
500 - 70,000
2,000 - 90,000
2,000 - 5,000
Metals
Iron
Strontium
Barium
Silica
Calcium
Magnesium
Sulfate
Potassium
Scale formers3
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
1-15
1
2-38
20
50 - 4,200
10 - 1,000
124 - 1,000
100 - 500
2,500
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-24 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Constituent
Reasons for Limiting
Concentrations
Recommended or observed base fluid target
concentrations (mg/L, after blending)b
Other
Phosphate
TSS
Oil
Boron
pH(S.U.)
Bacteria (count s/mL)
Not Reported
Plugging
Fluid stability
Fluid stability
Fluid stability
Bacterial growth
10
50 - 1,500
5-25
0-10
6.5-8.1
0 - 10,000
a Includes total of barium, calcium, manganese, and strontium.
b Unless otherwise noted.
1 Wastewater quality can be managed for reuse by either blending it with freshwater and allowing
2 dilution to bring the concentrations of problematic constituents to an acceptable range or through
3 treatment [VeiL_201fl]. Treatment, if needed, can be conducted at facilities that are mobile, semi-
4 permanent modular systems, or fully permanent CWTs (NIicot_etaL_2012.). At a minimum, hydraulic
5 fracturing service providers generally prefer that the wastewater be treated to remove TSS,
6 microorganisms, and constituents that form scale or inhibit crosslinking in gelled fluid systems
7 (Eoscheei2QJA}- Figure F-8 shows a schematic of a treatment system to treat wastewater for reuse
8 that can remove suspended solids, hardness, and organic constituents.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-25 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix F
Oil
Byproduct
Lime or
Caustic
Sodium
Sulfate
Soda
Ash
Acid
Frac
Flowback
Water
Treated
Water
am*
Air
GAC:
Organics Polish
P ..'!».IJ*. .-
.;;-,..' f.
Precip/CIarifier:
Hardness Removal
Sand Filter:
TSS Removal
Oxidation:
Chlorine Dioxide
Figure F-8. Diagram of treatment for reuse of flowback and produced water.
Source: KimbalL(2010l-
1 In the Marcellus, the wastewater to be reused is first generally treated with oil/gas-water
2 separation, filtration, and dilution (MjLgtiiLJJ0,1,4). Although many Marcellus treatment facilities
3 only supply basic reuse treatment that removes oil and solids, advanced treatment facilities that
4 use techniques such as RO or distillation methods are also in operation (VeiL_2010.).
5 Reuse concerns can vary with the type of hydraulic fracturing fluid used (e.g., slickwater, linear gel,
6 crosslinked gel, foam) (Wasylishen and Fulton, 2012) and the anticipated changes in water
7 chemistry over time (transition from flowback to produced water) (Hammer_and_VanBriesen1
8 2iH2). Elevated TDS is a concern, but residual constituents from previous fluid mixtures (e.g.,
9 breakers) may also cause difficulties when reusing water for subsequent fracturing operations
10 (Montgomery. 2013: Walsh. 2013).
11 On-Site Treatment for Reuse
12 On-site systems that treat produced water for reuse can reduce potential impacts to drinking water
13 resources associated with transportation and disposal and facilitate the logistics of reuse by
14 preparing the water close to well sites. These systems sometimes consist of mobile units containing
15 one or more treatment processes that can be moved from site to site to treat waters in newly
16 developed sites that are not yet producing at full-scale. Semi-permanent facilities that serve a
17 specific area also exist (HalJdorson^jZillSj Bosc!ieeJM12,).
18 Treatment systems are typically tailored for site-specific produced water chemical concentrations
19 and desired water quality treatment goals, including whether significant TDS removal is needed. If
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-26 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix F
1 low IDS water is needed, more advanced treatment will be required (see Section 8.5 of Chapter 8),
2 which can increase the treatment costs to three to four times higher than for treatment systems
3 that do not remove IDS [Halldorson. 2013). On-site facilities may be warranted where truck
4 hauling or seasonal accessibility to and from a central facility is an issue [Boschee, 2014: Tiemann
5 etal., 2014]. Operators may also consider on-site facilities if they have not fully committed to an
6 area and the well counts are initially low. In those instances, they can later decide to add or remove
7 units based on changing production volumes [Boschee, 2014].
F.6. Hydraulic Fracturing Impacts on POTWs
F.6.1. Potential Impacts on Treatment Processes
8 Wastewater treatment processes used by POTWs are generally not designed or operated for
9 wastewater containing high salt concentrations (>0.1-5% salt]. Four basic problems for biological
10 treatment of saline water have been described [Woolard and Irvine. 1995]: 1] microbes in
11 conventional treatment systems tend to be sensitive to changes in ionic strength, 2] microbial
12 metabolic functions are disrupted leading to decreased degradation of carbon compounds, 3]
13 effluent suspended solids are increased due to cell lysis and/or a reduction in organisms that
14 promote flocculation, and 4] the extent of salt acclimation is limited in conventional systems.
15 Biological pre-treatment may be beneficial as an added process in pre-treatment (e.g. prior to
16 indirect discharge from a CWT to a POTW] for removal of organic contaminants. Specialized
17 treatment systems using salt-tolerant bacteria may be beneficial as an additional level of treatment
18 for pre-treating (or polishing] waste waters in centralized treatment systems. (These processes
19 differ from conventional biological processes in standard wastewater treatment, which are not
20 suitable for large volumes of UOG wastewater.] In particular, membrane bioreactors (MBRs] have
21 been examined for the treatment of oil and gas wastewater (Dao etal.. 2013: Kose etal.. 2012:
22 Miller, 2011]. MBRs provide advantages over conventional aeration basin processes as they can be
23 implemented into existing treatment trains more easily and have a much smaller footprint than
24 aeration basins.
25 Because sudden increases in chloride concentration, above 5-8 g/L, may cause problems for
26 wastewater treatment (Ludzack and Noran. 1965]. POTWs planning to accept indirect discharge in
27 the future may find it valuable to restrict influent salt concentrations to a level that will not disturb
28 existing biological treatment processes.
F.7. Hydraulic Fracturing and DBFs
F.7.1.1. Disinfection By-Products
29 This section provides background information on disinfection by-products (DBFs] and their
30 formation to support the discussion in Section 8.6.1 of Chapter 8 regarding impacts on surface
31 waters and downstream drinking water utilities due to elevated bromide and iodide in hydraulic
3 2 fracturing waste waters.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 F-27 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment Appendix F
1 Regulated DBFs are a small subset of the full spectrum of DBFs that include other chlorinated and
2 brominated DBFs as well as nitrogenous and iodated DBFs. Some of the emerging unregulated
3 DBFs may be more toxic than their regulated counterparts [Harkness etal.. 2015: McGuireetal..
4 2014: Parker etal., 2014]. Of the many types of DBFs that can form when drinking water is
5 disinfected, SDWA's Stage 1 and Stage 2 DBF Rules regulate four total trihalomethanes (TTHMs),
6 five haloacetic acids (HAASs], bromate, and chlorite [U.S. EPA, 2006].
7 Most brominated DBFs form when water containing organic material and bromide reacts with a
8 disinfectant such as chlorine during drinking water treatment Parameters that affect DBF
9 formation include concentration and type of organic material, disinfectant concentration, pH, water
10 temperature, and disinfectant contact time. In addition, many studies have found that elevated
11 bromide levels correlate with increased DBF formation [Singer, 2010: Obolensky and Singer, 2008:
12 Matamoros etal.. 2007: Huaetal.. 2006: Yang and Shang. 2004]. Some studies found similar results
13 for iodide as well [McGuire etal.. 2014: Parker etal.. 2014]. Pope etal. [2007] reported that
14 increased bromide levels are the second best indicator of DBF formation, with pH being the first.
15 In addition, research finds that higher levels of bromide and iodide contribute to increased
16 concentrations of the brominated and iodated forms of DBFs (both regulated and unregulated],
17 which tend to be more cytotoxic, genotoxic, and carcinogenic than chlorinated species [McGuire et
18 al.. 2014: Parker etal.. 2014: States etal.. 2013: Krasner. 2009: Richardson etal.. 2007]. Studies
19 generally report that the ratios of halogen incorporation into DBFs reflect the ratio of halogen
20 concentrations in the source water [Criquetetal.. 2012: Tones etal.. 2012: Obolensky and Singer.
21 2008].
22 From a regulatory perspective, elevated bromide levels create difficulties in meeting drinking water
23 MCLs. When the TTHMs are predominately in the form of brominated DBFs, the higher molecular
24 weight of bromide (79.9 g/mol] relative to chloride (35.5 g/mol] causes the overall mass of the
25 TTHM sum to increase. This can lead to elevated concentrations of TTHM, in turn potentially
26 leading to violations of the TTHM MCL for the drinking water utility (Francis etal.. 2009].
27 High bromide levels are also cited as causing formation of nitrogenous DBF N-
28 nitrosodimethylamine (NDMA] in water disinfected with chloramines (Luh and Marinas. 2012].
29 Although NDMA is not regulated by the EPA as of early 2015, it is listed as a priority toxic pollutant,
30 and the EPA is planning to evaluate NDMA and other nitrosamines as candidates for regulation
31 during the six-year review of the Microbial and Disinfection Byproducts (MDBP] rules (U.S. EPA.
32 2014a].
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
Hayes. T: Severin. BF. (2012b). Evaluation of the aqua-pure mechanical vapor recompression system in the
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix F
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Hydraulic Fracturing Drinking Water Assessment Appendix F
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This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix G
Appendix G
Identification and Hazard Evaluation of
Chemicals across the Hydraulic Fracturing
Water Cycle Supplemental Tables and
Information
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix G
Appendix G. Identification and Hazard Evaluation of
Chemicals across the Hydraulic Fracturing Water Cycle
Supplemental Tables and Information
1 Appendix G provides detail and supporting information on the oral reference values (RfVs) and oral
2 slope factors (OSFs) that were identified in Chapter 9 of this assessment1 Section G.I provides
3 detail on the criteria used to select sources of RfVs and OSFs for chemicals used or detected in
4 hydraulic fracturing processes, and lists all sources of RfVs and OSFs that were considered for this
5 study. Section G.2 provides a glossary of the toxicity value terminology that is used by these various
6 sources. Lastly, all of the RfVs and OSFs collected from these sources are provided in Table G-l and
7 Table G-2. Tables G-la through G-ld show the available RfVs and OSFs for chemicals used in
8 hydraulic fracturing fluids, and Tables G-2 a through G-2d show the available RfVs and OSFs for
9 chemicals detected in hydraulic fracturing flowback and wastewater. These tables provide cancer
10 weight-of-evidence (WOE) characterizations for these chemicals where available, and indicate
11 whether each chemical has available data on physicochemical properties or occurrence.
G.I. Criteria for Selection and Inclusion of Reference Value (RfV) and Oral
Slope Factor (OSF) Data Sources
12 The criteria listed below were used to evaluate the quality of RfVs and OSFs considered for use in
13 the hazard analyses conducted in Chapter 9. These criteria were originally outlined in the hydraulic
14 fracturing research plan (U '•> U'/-,, ,:dl 1.1) and interim progress report (U1S._EPA1_2012c). Only data
15 sources that met these criteria were considered of sufficient quality to be included in the analyses.
16 The following criteria had to be met for a source to be deemed of sufficient quality:
17 1) The body or organization generating or producing the peer-reviewed RfVs, peer-reviewed OSFs,
18 or peer reviewed qualitative assessment must be a governmental or intergovernmental body.
19 a. Governmental bodies include sovereign states, and federated states/units.
20 b. Intergovernmental bodies are those whose members are sovereign states, and the
21 subdivisions or agencies of such intergovernmental bodies. The United Nations is an
2 2 example of an intergovernmental body. The International Agency for Research on
23 Cancer (IARC) is an agency of the World Health Organization (WHO), which is itself an
24 agency of the United Nations. Thus, IARC is considered a subdivision of the United
25 Nations.
1 As defined in Chapter 9, the term RfV refers to reference values for noncancer effects occurring via the oral route of
exposure and for chronic durations, except where noted.
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Hydraulic Fracturing Drinking Water Assessment Appendix G
1 2) The data source must include peer-reviewed RfVs, peer-reviewed OSFs, or peer reviewed
2 qualitative assessments.
3 a. A committee that is established to derive the RfVs, OSFs, or qualitative assessments can
4 have members of that same committee provide the peer review, so long as either the
5 entire committee, or members of the committee who did not participate in the
6 derivation of a specific section of a work product, conduct the review.
7 b. Peer reviewers who work for grantees of the organization deriving the RfVs, OSFs, or
8 qualitative assessments are generally allowed, and this will not be considered to
9 constitute a conflict/duality of interest.
10 c. Peer reviewers may work in the same or different office, so long as they did not
11 participate in any way in the development of the product, and these individuals must be
12 free of conflicts/duality of interest with respect to the chemical(s) assigned.
13 i. For instance, peer reviewers for Program X, conducted by Office A, may also be
14 employed by Office A so long as they did not participate in the creation of the
15 Program X product they are reviewing.
16 3) The RfVs, OSFs, or qualitative assessments must be based on peer-reviewed scientific data.
17 a. There are cases where industry reports that were not published in a peer-reviewed,
18 scholarly journal maybe used, if the industry report has been adequately peer-reviewed
19 by an external body (external to the group generating the report, and external to the
20 group generating the peer-reviewed RfVs, peer-reviewed OSFs, or peer-reviewed
21 qualitative assessment) that is free of conflicts/dualities of interest
22 4) The RfVs, OSFs, or qualitative assessments must be focused on protection of the general public.
23 a. Sources that are focused on workers are not appropriate as workers are assumed to
24 accommodate additional risk than the general public due to their status as workers.
25 5) The body generating the values or qualitative assessments must be free of conflicts of interest
26 with respect to the chemicals for which it derives RfVs, OSFs, or qualitative assessments.
27 a. If a body generating the RfVs, OSFs, or qualitative assessments accepts funding from an
2 8 interested party (i.e., a company or organization that may be impacted by past, present,
29 or future values or qualitative assessments), then the body has a conflict of interest
30 b. For instance, if a non-profit organization is funded by an industry trade group, and the
31 non-profit generates RfVs, OSFs, or qualitative assessments for chemicals that trade
3 2 group is interested in, then the non-profit is considered to have a conflict of interest
3 3 with respect to those chemicals.
34 It is important to note that having a conflict/duality of interest for one chemical is sufficient to
3 5 disqualify the entire database, as it is assumed that conflicts/dualities of interest may exist for
36 other chemicals as well.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix G
G.I.I. Included Sources
1 We applied our criteria to 16 different sources of RfVs and/or OSFs. After application of our criteria,
2 we were left with eight sources. For those sources which did not meet our criteria, we provide an
3 explanation of why they were excluded.
4 The following sources were evaluated, met our criteria, and were selected as sources of reference
5 doses or cancer slope factors for this analysis:
6 • U.S. EPA Integrated Risk Information System (IRIS)
7 • U.S. EPA Human Health Benchmarks for Pesticides (HHBP)
8 • U.S. EPA Provisional Peer-Reviewed Toxicity Values (PPRTVs)
9 • U.S. Agency for Toxic Substances and Disease Registry (ATSDR) Minimum Risk
10 Levels (MRLs)
11 • California EPA Toxicity Criteria Database
12 • International Programme On Chemical Safety (IPCS) Concise International Chemical
13 Assessment Documents (CICAD)
14 The following sources were evaluated, met our criteria, and were selected as sources of qualitative
15 cancer classifications:
16 • International Agency for Research on Cancer (IARC)
17 • US National Toxicology Program Report on Carcinogens (RoC)
18 RfVs and/or OSFs from these data sources are listed in Tables G-la through G-ld for chemicals used
19 in hydraulic fracturing fluid formulation, and Tables G-2a through G-2d for chemicals reported in
2 0 hydraulic fracturing flowback and produced water.
21 In addition, Table G-l and Table G-2 also list the EPA's drinking water maximum contaminant levels
22 (MCLs) and maximum contaminant goal levels (MCLG) when available. These values are generally
23 based on IRIS values, and are treatment-based. MCL and MCLG values are listed for reference only,
24 and were not considered in the hazard analysis presented in Chapter 9.
G.I.2. Excluded Sources
25 • American Conference of Governmental Industrial Hygienists: The assessments
2 6 derived by this body are specific to workers and are not generalizable to the general
27 public. In addition, this body is not a governmental or intergovernmental body. Thus, these
2 8 values were excluded based on criteria 1 and 4.
29 • European Chemicals Bureau, Classification and Labeling Annex I of Directive
30 67/548/EEC: These assessments are not based on peer-reviewed values, but are based on
31 data supplied by manufacturers. Further, the enabling legislation states that
32 "Manufacturers, importers, and downstream users shall examine the information...to
3 3 ascertain whether it is adequate, reliable and scientifically valid for the purpose of the
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Hydraulic Fracturing Drinking Water Assessment Appendix G
1 evaluation..." This clearly demonstrates that the data and the evaluation are not required
2 to be peer-reviewed. Thus, these values were excluded based on criterion 2.
3 • Toxicology Excellence for Risk Assessment's (TERA's) International Toxicity
4 Estimates for Risk Assessment (ITER): The ITER database is developed by TERA a
5 501(c)(3) non-profit TERA accepts funding from various sources, including interested
6 parties that may be impacted by their assessment work. Thus, ITER is excluded based on
7 criteria 1 and 5.
8 • Other U.S. states: The EPA evaluated values from all states that had values reported on
9 their websites. If a state's values were determined to be largely duplicative of the EPA's
10 values (e.g., the state adopts EPA values, such as the regional screening levels, and does
1 1 not typically generate its own peer-reviewed values), that state's values were no longer
12 considered. The EPA contacted those states whose values were determined to not be
1 3 duplicative of EPA's values, and confirmed whether or not a peer review process was used
14 to develop the state's values. The EPA determined that of the states with values not
1 5 duplicative of the EPA's values, only California's values met all of the EPA's criteria for this
16 report Other states with publicly accessible RfVs and/or OSFs include: Alabama, Florida,
17 Hawaii, and Texas.
18 • WHO Guidelines for Drinking- Water Quality: The WHO Guidelines' values are not RfVs,
19 but rather drinking water values.
G.2. Glossary of Toxicity Value Terminology
20 This section defines the toxicity values and qualitative cancer classifications that are frequently
2 1 found in the sources identified above.
22 Lowest-observed-adverse-effect level (LOAEL): The lowest exposure level at which there are
23 biologically significant increases in frequency or severity of adverse effects between the exposed
24 population and its appropriate control group. Source: IlJS
25 Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive
26 toxicant at which the chemical would have no observable adverse reproductive effect, assuming
27 exposure at 1,000 times that level. Source: OEHHA|2012}.
28 Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in
29 drinking water. MCLs are set as close to MCLGs as feasible using the best available treatment
30 technology and taking cost into consideration. MCLs are enforceable standards. Source: lISJiPA
31 ClMbi
32 Maximum contaminant level goal (MCLG): The level of a contaminant in drinking water below
3 3 which there is no known or expected risk to health. MCLGs allow for a margin of safety and are
34 nonenforceable public health goals. Source: HJ
35 Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance
36 at or below which the substance is unlikely to pose a measurable risk of harmful (adverse),
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Hydraulic Fracturing Drinking Water Assessment Appendix G
1 noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a
2 specified time period (acute, intermediate, or chronic). MRLs should not be used as predictors of
3 harmful (adverse) health effects.
4 • Chronic MRL: Duration of exposure is 365 days or longer.
5 • Intermediate MRL: Duration of exposure is >14 to 364 days.
6 • Acute MRL: Duration of exposure is 1 to 14 days.
7 Source :ATSDR_C2009J.
8 No-observed-adverse-effect level (NOAEL): The highest exposure level at which there are no
9 biologically significant increases in the frequency or severity of adverse effect between the exposed
10 population and its appropriate control; some effects may be produced at this level, but they are not
11 considered adverse or precursors of adverse effects. Source: lLS._EPA_£2t)l tc]L
12 Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased
13 cancer risk from a lifetime oral exposure to an agent. This estimate, usually expressed in units of
14 proportion (of a population) affected per mg/kg-day, is generally reserved for use in the low-dose
15 region of the dose-response relationship, that is, for exposures corresponding to risks less than 1 in
16 100. Source: O
17 Reference dose (RfD) (U.S. EPA IRIS and PPRTV definition): An estimate (with uncertainty
1 8 spanning perhaps an order of magnitude) of a daily oral exposure to the human population
19 (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects
20 during a lifetime. It can be derived from a NOAEL, LOAEL, or benchmark dose, with uncertainty
2 1 factors generally applied to reflect limitations of the data used. The RfD is generally used in the
22 EPA's noncancer health assessments.
23 • Chronic RfD: Duration of exposure is up to a lifetime.
24 • Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average lifespan.
2 5 Source : IL
26 Reference dose (RfD) (U.S. EPA HHBP definition): The particular concentration of a chemical
2 7 that is known not to cause health problems. A standard that also may be referred to as the
28 acceptable daily intake. Derived using the same EPA guidance for IRIS and PPRTV RfD
29 determination. Source: yjLEPA_£2015eJ.
30 Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass
3 1 basis, to which an individual in a (sub) population may be exposed daily over its lifetime without
3 2 appreciable health risk. Source : WHQX2Q15J.
33 Weight-of-evidence (WOE) characterization for carcinogenicity: A system used for
34 characterizing the extent to which the available data support the hypothesis that an agent causes
3 5 cancer in humans.
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Hydraulic Fracturing Drinking Water Assessment Appendix G
1 • EPA 1986 guidelines: Under the EPA's 1986 risk assessment guidelines, the WOE was
2 described by categories "A through E," with Group A for known human carcinogens through
3 Group E for agents with evidence of noncarcinogenicity. Five standard WOE descriptors
4 were used:
5 o A: Human carcinogen
6 o Bl: Probable human carcinogen—based on limited evidence of carcinogenicity in
7 humans and sufficient evidence of carcinogenicity in animals
8 o B2: Probable human carcinogen—based on sufficient evidence of carcinogenicity in
9 animals
10 o C: Possible human carcinogen
11 o D: Not classifiable as to human carcinogenicity
12 o E: Evidence of noncarcinogenicity for humans
13 Source: HSJPAI201M,
14 • EPA 1996 proposed guidelines: The EPA's 1996 proposed guidelines outlined a major
15 change in the way hazard evidence was weighted in reaching conclusions about the human
16 carcinogenic potential of agents. These guidelines replaced the WOE letter categories with
17 the use of standard descriptors of conclusions incorporated into a brief narrative. Three
18 categories of descriptors with the narrative were used:
19 o Known/likely
20 o Cannot be determined
21 o Not likely
22 Source: USS!_EPAX1996J.
23 • EPA 1999 guidelines: The 1999 guidelines adopted a framework incorporating hazard
24 identification, dose-response assessment, exposure assessment, and risk characterization
2 5 with an emphasis on characterization of evidence and conclusions in each part of the
26 assessment. Five descriptors summarizing the WOE in the narrative were used:
27 o Carcinogenic to humans
28 o Likely to be carcinogenic to humans
29 o Suggestive evidence of carcinogenicity, but not sufficient to assess human
30 carcinogenic potential
31 o Data are inadequate for an assessment of human carcinogenic potential
32 o Not likely to be carcinogenic to humans
33 Source: US.EPAXI999J.
34 • EPA 2005 guidelines: The approach outlined in the EPA's 2005 guidelines for carcinogen
3 5 risk assessment considers all scientific information in determining whether and under what
36 conditions an agent may cause cancer in humans and provides a narrative approach to
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix G
1 characterize carcinogenicity rather than categories. Five standard WOE descriptors are
2 used as part of the narrative:
3 o Carcinogenic to humans
4 o Likely to be carcinogenic to humans
5 o Suggestive evidence of carcinogenic potential
6 o Inadequate information to assess carcinogenic potential
7 o Not likely to be carcinogenic to humans
8 Source: Hi£PA£20He],
9 • IARC Monographs on the evaluation of carcinogenic risks to humans: The IARC
10 classifies carcinogen risk as a matter of scientific judgement that reflects the strength of the
11 evidence derived from studies in humans, in experimental animals, from mechanistic data,
12 and from other relevant data. Five WOE classifications are used:
13 o Group 1: Carcinogenic to humans
14 o Group 2A: Probably carcinogenic to humans
15 o Group 2B: Possibly carcinogenic to humans
16 o Group 3: Not classifiable as to its carcinogenicity to humans
17 o Group 4: Probably not carcinogenic to humans
18 Source: IAKCJ2015J.
19 • NTP: The NTP describes the results of individual experiments on a chemical agent and
20 notes the strength of the evidence for conclusions regarding each study. Negative results, in
21 which the study animals do not have a greater incidence of neoplasia than control animals,
22 do not necessarily mean that a chemical is not a carcinogen, inasmuch as the experiments
23 are conducted under a limited set of conditions. Positive results demonstrate that a
24 chemical is carcinogenic for laboratory animals under the conditions of the study and
25 indicate that exposure to the chemical has the potential for hazard to humans. For each
26 separate experiment, one of the following five categories is selected to describe the findings.
27 These categories refer to the strength of the experimental evidence and not to potency or
28 mechanism.
29 o Clear evidence of carcinogenic activity
30 o Some evidence of carcinogenic activity
31 o Equivocal evidence of carcinogenic activity
32 o No evidence of carcinogenic activity
33 o Inadequate study of carcinogenic activity
34 Source: NTP_C2014a}.
35 • The RoC is a congressionally mandated, science-based, public health report that identifies
36 agents, substances, mixtures, or exposures (collectively called "substances") in our
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Hydraulic Fracturing Drinking Water Assessment Appendix G
1 environment that may potentially put people in the United States at increased risk for
2 cancer. NTP prepares the RoC on behalf of the Secretary of the Health and Human Services.
3 The listing criteria in the RoC Document are:
4 o Known to be a human carcinogen
5 o Reasonably anticipated to be a human carcinogen
6
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
G.3. Tables
Table G-la. Chemicals reported to be used in hydraulic fracturing fluids, with available federal chronic RfVs and OSFs.
Chemicals from the FracFocus database are listed first, ranked by IRIS reference dose (RfD). The "--" symbol indicates that no value was available
from the sources consulted. Additionally, an "x" indicates the availability of usage data from FracFocus and physicochemical
properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in both fracturing fluids and flowback/produced water.
Chemical Name
Acrylamide
Propargyl alcohol
Furfural
Benzene
Dichloromethane
Naphthalene
CASRN
79-06-1
107-19-7
98-01-1
71-43-2
75-09-2
91-20-3
Frac-
Focus
data
available
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
0.002
0.002
0.003
0.004
0.006
0.02
OSFb
(per
mg/
kg-day)
0.5
-
-
0.015-
0.055
0.002
-
Cancer WOE
character-
ization
"Likely to be
carcinogenic
to humans"
-
-
A
"Likely to be
carcinogenic
in humans"
"Data are
inadequate to
assess human
carcinogenic
potential"
PPRTV
Chronic
RfDa
(mg/
kg-day)
-
-
-
-
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
Cancer
WOE
character-
ization
-
-
-
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
0.001
-
-
0.0005
0.06
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
0.01
-
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
0
-
-
0
0
-
MCI"
(mg/L)
-
-
-
0.005
0.005
-
June 2015
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Appendix G
Chemical Name
1,4-D/oxane
Sodium chlorite
Chlorine dioxide
1,3-
Dichloropropene
Bisphenol A
Toluene
Ethylbenzene
CASRN
123-91-1
7758-19-2
10049-04-4
542-75-6
80-05-7
108-88-3
100-41-4
Frac-
Focus
data
available
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
0.03
0.03
0.03
0.03
0.05
0.08
0.1
OSFb
(per
mg/
kg-day)
0.1
__
__
0.05
-
-
Cancer WOE
character-
izationc
"Likely to be
carcinogenic
to humans"
"Data are
inadequate to
assess human
carcinogen-
icity"
"Data are
inadequate to
assess human
carcinogen-
icity"
"Likely to be a
human
carcinogen"
-
"Inadequate
information to
assess the
carcinogenic
potential"
D
PPRTV
Chronic
RfDa
(mg/
kg-day)
-
..
..
-
-
-
OSFb
(per
mg/
kg-day)
-
..
..
-
-
-
Cancer
WOE
character-
izationc
-
..
..
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
0.1
__
__
0.03
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
..
..
-
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
1
..
-
-
1
0.7
MCI"
(mg/L)
-
0.8
..
-
-
1
0.7
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Appendix G
Chemical Name
1-Butanol
Cumene
Acetophenone
2-Butoxyethanol
Xylenes
Formaldehyde
Phenol
2-Methyl-l-
propanol
CASRN
71-36-3
98-82-8
98-86-2
111-76-2
1330-20-7
50-00-0
108-95-2
78-83-1
Frac-
Focus
data
available
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
0.1
0.1
0.1
0.1
0.2
0.2
0.3
0.3
OSFb
(per
mg/
kg-day)
-
-
-
-
—
-
-
-
Cancer WOE
character-
izationc
D
D
D
"Not likely to
be carcino-
genic to
humans"
"Data are
inadequate to
assess the
carcinogenic
potential"
Bl
"Data are
inadequate
for an
assessment of
human
carcinogenic
potential"
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
-
-
-
-
—
-
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
—
-
-
-
Cancer
WOE
character-
izationc
-
-
-
-
—
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
-
0.2
0.2
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
—
-
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
-
-
-
10
-
-
-
MCI"
(mg/L)
-
-
-
-
10
-
-
-
June 2015
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Appendix G
Chemical Name
Acetone
Ethyl acetate
Ethylene glycol
Methanol
Benzole acid
Aniline
Benzyl chloride
(E)-Crotonaldehyde
N,N-Dimethylform
amide
Epichlorohydrin
1,2-Propylene
glycol
CASRN
67-64-1
141-78-6
107-21-1
67-56-1
65-85-0
62-53-3
100-44-7
123-73-9
68-12-2
106-89-8
57-55-6
Frac-
Focus
data
available
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
0.9
0.9
2
2
4
-
-
-
-
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
-
0.0057
0.17
-
-
0.0099
-
Cancer WOE
character-
izationc
"Data are
inadequate
for an
assessment of
human
carcinogenic
potential"
-
-
-
D
B2
B2
C
-
B2
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
-
-
-
-
-
0.007
0.002
0.001
0.1
0.006
20
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
izationc
-
IN
-
-
-
-
-
-
IN
-
NL
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
-
-
-
-
-
-
-
-
0
-
MCI"
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
June 2015
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Appendix G
Chemical Name
2-(2-Butoxyethoxy)
ethanol
Hexanedioicacid
Quinoline
Ethylenediamine
Formic acid
Sodium chlorate
Quaternary
ammonium
compounds,
benzyl-C12-16-
alkyldimethyl,
chlorides
Benzenesulfonic
acid, C10-16-alkyl
derivs.
Ammonium
phosphate
Didecyldimethylam
monium chloride
2-(Thiocyano
methylthio)benzot
hiazole
CASRN
112-34-5
124-04-9
91-22-5
107-15-3
64-18-6
7775-09-9
68424-85-1
68584-22-5
7722-76-1
7173-51-5
21564-17-0
Frac-
Focus
data
available
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
OSFb
(per
mg/
kg-day)
-
-
3
-
-
-
-
-
-
-
-
Cancer WOE
character-
izationc
-
-
"Likely to be
carcinogenic
in humans"
D
-
-
-
-
-
-
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
0.03
2
-
0.09
0.9
-
-
-
49
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
izationc
IN
-
-
IN
IN
-
-
-
IN
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
0.03
0.44
0.5
-
0.1
0.01
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
MCI"
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
June 2015
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Appendix G
Chemical Name
Mineral oil -
includes paraffin
oil
Trisodium
phosphate
Triphosphoric acid,
pentasodium salt
Aluminum
Phosphoric acid
Iron
Tricalcium
phosphate
Bis(2-chloroethyl)
ether
Dodecylbenzenesul
fonic acid
Hydrazine
Tetrasodium
pyrophosphate
CASRN
8012-95-1
7601-54-9
7758-29-4
7429-90-5
7664-38-2
7439-89-6
7758-87-4
111-44-4
27176-87-0
302-01-2
7722-88-5
Frac-
Focus
data
available
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
-
1.1
-
3
-
Cancer WOE
character-
izationc
-
-
-
-
-
-
-
B2
-
B2
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
3
49
49
1
48.6
0.7
49
-
-
-
49
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
izationc
IN
IN
IN
IN
IN
IN
IN
-
-
-
IN
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
1
-
-
-
-
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
0.5
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
MCI"
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
G-14
DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Potassium
phosphate, tribasic
Sodium
trimetaphosphate
Arsenic
Phosphine
Acrolein
Chromium (VI)
Di(2-ethylhexyl)
phthalate
Chlorine
Styrene
CASRN
7778-53-2
7785-84-4
7440-38-2
7803-51-2
107-02-8
18540-29-9
117-81-7
7782-50-5
100-42-5
Frac-
Focus
data
available
X
X
Physico-
chemical
data
available
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
-
-
0.0003
0.0003
0.0005
0.003
0.02
0.1
0.2
OSFb
(per
mg/
kg-day)
-
-
1.5
-
-
-
0.014
-
-
Cancer WOE
character-
izationc
-
-
A
D
"Data are
inadequate
for an
assessment of
human
carcinogenic
potential"
A (inhaled);
D(oral)
B2
-
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
49
49
-
-
-
-
-
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
izationc
IN
IN
-
-
-
-
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
0.0003
-
-
0.0009
0.06
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
-
0
-
-
-
0
-
0.1
MCI"
(mg/L)
-
-
0.010
-
-
-
0.006
-
0.1
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
G-15
DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Zinc
Acrylic acid
Chromium (III)
Phthalic anhydride
Cyclohexanone
1,2-Propylene
oxide
2-(2-Ethoxyethoxy)
ethanol
Tributyl phosphate
2-Methoxyethanol
Polyphosphoric
acids, sodium salts
Phosphoric acid,
diammonium salt
CASRN
7440-66-6
79-10-7
16065-83-1
85-44-9
108-94-1
75-56-9
111-90-0
126-73-8
109-86-4
68915-31-1
7783-28-0
Frac-
Focus
data
available
Physico-
chemical
data
available
X
X
X
X
X
X
X
IRIS
Chronic
RfDa
(mg/
kg-day)
0.3
0.5
1.5
2
5
-
-
-
-
-
-
OSFb
(per
mg/
kg-day)
-
-
-
-
-
0.24
-
-
-
-
-
Cancer WOE
character-
izationc
"Inadequate
information to
assess
carcinogenic
potential"
-
"Data are
inadequate
for an
assessment of
human
carcinogenic
potential"
-
-
B2
-
-
-
-
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
-
-
-
-
-
-
0.06
0.01
0.005
49
49
OSFb
(per
mg/
kg-day)
-
-
-
-
-
-
-
0.009
-
-
-
Cancer
WOE
character-
izationc
-
IN
-
-
IN
-
IN
LI
IN
IN
IN
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
0.3
-
-
-
-
-
-
0.08
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
0.001
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
MCI"
(mg/L)
-
-
-
-
-
-
-
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
G-16
DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Sodium
pyrophosphate
Phosphoric acid,
aluminium sodium
salt
CASRN
7758-16-9
7785-88-8
Frac-
Focus
data
available
Physico-
chemical
data
available
IRIS
Chronic
RfDa
(mg/
kg-day)
-
OSFb
(per
mg/
kg-day)
-
Cancer WOE
character-
izationc
-
PPRTV
Chronic
RfDa
(mg/
kg-day)
49
49
OSFb
(per
mg/
kg-day)
-
Cancer
WOE
character-
izationc
IN
IN
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
National Primary
Drinking Water
Regulations
Public
health goal'
(MCLG)
(mg/L)
-
MCI*
(mg/L)
-
ATSDR = Agency for Toxic Substances and Disease Registry; CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional
Peer Reviewed Toxicity Values; HHBP = Human Health Benchmarks for Pesticides
a Reference dose (RfD) (IRIS and PPRTV definition): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population
(including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level
(NOAEL), lowest observed-adverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is
generally used in the EPA's noncancer health assessments. Chronic RfD: Duration of exposure is up to a lifetime.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime oral exposure to an agent. This estimate, usually
expressed in units of proportion (of a population) affected per mg/kg-day, is generally reserved for use in the low dose region of the dose response relationship, that is, for
exposures corresponding to risks less than 1 in 100.
c Weight of evidence (WOE) characterization for carcinogenicity: A system used for characterizing the extent to which the available data support the hypothesis that an agent
causes cancer in humans. See glossary for details.
d Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of
harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs
should not be used as predictors of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer.
e Reference dose (RfD) (HHBP definition): The particular concentration of a chemical that is known not to cause health problems. A standard that also may be referred
to as the acceptable daily intake. Derived using the same EPA guidance for RfD determination.
f Maximum contaminant level goal (MCLG): The level of a contaminant in drinking water below which there is no known or expected risk to health. MCLGs allow for a margin of
safety and are nonenforceable public health goals.
g Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to MCLGs as feasible using the best available
treatment technology and taking cost into consideration. MCLs are enforceable standards.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-17 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Table G-lb. Chemicals reported to be used in hydraulic fracturing fluids, with available state
chronic RfVs and OSFs.
Chemicals from the FracFocus database are listed first, ranked by California EPA maximum allowable
daily level (MADL). The "--" symbol indicates that no value was available from the sources consulted.
Additionally, an "x" indicates the availability of usage data from FracFocus and
physicochemical properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in
both fracturing fluids and flowback/produced water.
Chemical name
Ethylene oxide
Benzene
N-Methyl-2-pyrrolidone
Acrylamide
Aniline
Benzyl chloride
1,4-Dioxane
Epichlorohydrin
Ethylbenzene
Nitrilotriacetic acid
Nitrilotriacetic acid trisodium
monohydrate
Thiourea
Bis(2-chloroethyl) ether
1,3-Butadiene
Hydrazine
1,3-Dichloropropene
Dichloromethane
Lead
Chromium (VI)
2-Methoxyethanol
2-Ethoxyethanol
CASRN
75-21-8
71-43-2
872-50-4
79-06-1
62-53-3
100-44-7
123-91-1
106-89-8
100-41-4
139-13-9
18662-53-8
62-56-6
111-44-4
106-99-0
302-01-2
542-75-6
75-09-2
7439-92-1
18540-29-9
109-86-4
110-80-5
FracFocus
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
California
Oral MADLa
(u,g/day)
20
24
17000
140
-
-
-
-
-
-
-
-
-
-
-
-
-
0.5
8.2
63
750
OSFb (per
mg/kg-day)
0.31
0.1
-
4.5
0.0057
0.17
0.027
0.08
0.011
0.0053
0.01
0.072
2.5
0.6
3
0.091
0.014
0.0085
0.5
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-18 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical name
Di(2-ethylhexyl) phthalate
1,2-Propylene oxide
Arsenic
CASRN
117-81-7
75-56-9
7440-38-2
FracFocus
data
available
Physico-
chemical
data
available
X
X
California
Oral MADLa
(Hg/day)
20 (neonate male)
58 (infant male)
410 (adult)
-
-
OSFb (per
mg/kg-day)
0.003
0.24
9.5
a Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive toxicant at which the chemical
would have no observable adverse reproductive effect, assuming exposure at 1,000 times that level.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime
oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per mg/kg day, is
generally reserved for use in the low-dose region of the dose-response relationship, that is, for exposures corresponding to
risks less than 1 in 100.
Table G-lc. Chemicals reported to be used in hydraulic fracturing fluids, with available
international chronic RfVs and OSFs.
Chemicals from the FracFocus database are listed first, ranked by CICAD reference dose (TDI, or
tolerable daily intake). An "x" indicates the availability of usage data from FracFocus (U^
and physicochemical properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found
in both fracturing fluids and flowback/produced water.
Chemical name
D-Limonene
Potassium iodide
Sodium iodide
Copper(l) iodide
Glyoxal
Ethylene glycol
N-Methyl-2-pyrrolidone
Strontium chloride
Chromium (VI)
CASRN
5989-27-5
7681-11-0
7681-82-5
7681-65-4
107-22-2
107-21-1
872-50-4
10476-85-4
18540-29-9
FracFocus data
available
X
X
X
X
X
X
X
Physicochemical
data available
X
X
X
X
IPCS Chronic TDIa
(mg/kg-day)
0.1
0.01
0.01
0.01
0.2
0.05
0.6
0.13
0.0009
IPCS = International Programme on Chemical Safety; CICAD = Concise International Chemical Assessment Documents
a Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass basis, to which an individual
in a (sub) population may be exposed daily over its lifetime without appreciable health risk.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-19 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Table G-ld. Chemicals reported to be used in hydraulic fracturing fluids, with available less-
than-chronic RfVs and OSFs.
Chemicals from the FracFocus database are listed first, ranked by PPRTV subchronic reference dose
(sRfD). The "--" symbol indicates that no value was available from the sources consulted. Additionally,
an "x" indicates the availability of usage data from FracFocus and physicochemical
properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in both fracturing
fluids and flowback/produced water.
Chemical name
Benzyl chloride
Epichlorohydrin
(E)-Crotonaldehyde
Benzene
Ethylbenzene
Ethylenediamine
N,N-
Dimethylformamide
2-(2-
Butoxyethoxy)ethanol
Hexane
Xylenes
Antimony trioxide
Iron
Toluene
Formic acid
Hexanedioicacid
Benzoicacid
1,2-Propylene glycol
Mineral oil - includes
paraffin oil
Phosphoric acid
Ammonium phosphate
Trisodium phosphate
Triphosphoric acid,
pentasodium salt
CASRN
100-44-7
106-89-8
123-73-9
71-43-2
100-41-4
107-15-3
68-12-2
112-34-5
110-54-3
1330-20-7
1309-64-4
7439-89-6
108-88-3
64-18-6
124-04-9
65-85-0
57-55-6
8012-95-1
7664-38-2
7722-76-1
7601-54-9
7758-29-4
FracFocus
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PPRTV
sRfDa
(mg/kg-day)
0.002
0.006
0.01
0.01
0.05
0.2
0.3
0.3
0.3
0.4
0.5
0.7
0.8
0.9
2
4
20
30
48.6
49
49
49
ATSDR
Acute oral
MRLb
(mg/kg-day)
-
-
-
-
-
-
-
-
-
1
-
-
0.8
-
-
-
-
-
-
-
-
-
Intermediate
oral MRLC
(mg/kg-day)
-
-
-
-
0.4
-
-
-
-
0.4
-
-
0.02
-
-
-
-
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-20 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical name
Tricalcium phosphate
Tetrasodium
pyrophosphate
Potassium phosphate,
tribasic
Sodium
trimetaphosphate
Acrylamide
1,4-Dioxane
Ethylene glycol
Naphthalene
Phenol
Sodium chlorite
Acetone
2-Butoxyethanol
Aluminum
Formaldehyde
1,3-Dichloropropene
Dichloromethane
Antimony trichloride
2-Methoxyethanol
Tributyl phosphate
Acrylic acid
2-(2-Ethoxyethoxy)
ethanol
Cyclohexanone
Polyphosphoric acids,
sodium salts
Phosphoric acid,
diammonium salt
Sodium
pyrophosphate
CASRN
7758-87-4
7722-88-5
7778-53-2
7785-84-4
79-06-1
123-91-1
107-21-1
91-20-3
108-95-2
7758-19-2
67-64-1
111-76-2
7429-90-5
50-00-0
542-75-6
75-09-2
10025-91-9
109-86-4
126-73-8
79-10-7
111-90-0
108-94-1
68915-31-1
7783-28-0
7758-16-9
FracFocus
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PPRTV
sRfDa
(mg/kg-day)
49
49
49
49
-
-
-
-
-
-
-
-
-
-
-
-
0.0004
0.02
0.03
0.2
0.6
2
49
49
49
ATSDR
Acute oral
MRLb
(mg/kg-day)
-
-
-
-
0.01
5
0.8
0.6
1
-
-
0.4
-
-
-
0.2
-
-
1.1
-
-
-
-
-
-
Intermediate
oral MRLC
(mg/kg-day)
-
-
-
-
0.001
0.5
0.8
0.6
-
0.1
2
0.07
1
0.3
0.04
-
-
-
0.08
-
-
-
-
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-21 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical name
Phosphoric acid,
aluminium sodium salt
Acrolein
Di(2-ethylhexyl)
phthalate
Styrene
Arsenic
Chromium (VI)
Copper
Zinc
CASRN
7785-88-8
107-02-8
117-81-7
100-42-5
7440-38-2
18540-29-9
7440-50-8
7440-66-6
FracFocus
data
available
Physico-
chemical data
available
X
X
X
PPRTV
sRfDa
(mg/kg-day)
49
-
-
-
-
-
-
-
ATSDR
Acute oral
MRLb
(mg/kg-day)
-
-
-
0.1
0.005
-
0.01
-
Intermediate
oral MRLC
(mg/kg-day)
-
0.004
0.1
-
-
0.005
0.01
0.3
a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the
human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during
a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-adverse-effect level (LOAEL),
or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is
generally used in the EPA's noncancer health assessments. Subchronic RfD (sRFD): Duration of exposure is up to 10% of an
average lifespan.
b Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the
substance is unlikely to pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of
exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as
predictors of harmful (adverse) health effects. Acute MRL: Duration of exposure is 1 to 14 days.
c Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the
substance is unlikely to pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of
exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as
predictors of harmful (adverse) health effects. Intermediate MRL: Duration of exposure is >14 to 364 days.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-22 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Table G-2a. Chemicals reported to be detected in flowback or produced water, with available federal chronic RfVs and OSFs.
Chemicals are ranked by IRIS reference dose (RfD). The "--" symbol indicates that no value was available from the sources consulted. Additionally,
an "x" indicates the availability of measured concentration data in flowback or produced water (see Appendix E) and physicochemical properties
data from EPI Suite™ (see Appendix C). Italicized chemicals are found in both fracturing fluids and flowback/produced water.
Chemical Name
Heptachlor
epoxide
Phosphorus
Aldrin
Dieldrin
Arsenic
Lindane
Antimony
Acrolein
Cadmium
Heptachlor
CASRN
1024-57-3
7723-14-0
309-00-2
60-57-1
7440-38-2
58-89-9
7440-36-0
107-02-8
7440-43-9
76-44-8
Concen-
tration
data
available
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
0.000013
0.00002
0.00003
0.00005
0.0003
0.0003
0.0004
0.0005
0.0005
(water)
0.0005
OSFb
(per mg/
kg-day)
9.1
-
17
16
1.5
-
-
-
-
4.5
Cancer WOE
character-
ization"
B2
D
B2
B2
A
-
-
"Data are
inadequate for
an assessment
of human
carcinogenic
potential"
Bl
B2
PPRTV
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
ization"
-
-
-
-
-
-
IN
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
0.00003
0.00005
0.0003
-
-
-
0.0001
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
0
-
-
-
0
0.0002
0.006
-
0.005
0
MCLs
(mg/L)
0.0002
-
-
-
0.010
0.0002
0.006
-
0.005
0.0004
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Cyanide
Pyridine
Methyl bromide
Beryllium
Chromium (VI)
Benzene
2-Methylnaphth
alene
Molybdenum
Silver
Selenium
Dichloromethane
CASRN
57-12-5
110-86-1
74-83-9
7440-41-7
18540-29-9
71-43-2
91-57-6
7439-98-7
7440-22-4
7782-49-2
75-09-2
Concen-
tration
data
available
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
0.0006
0.001
0.0014
0.002
0.003
0.004
0.004
0.005
0.005
0.005
0.006
OSFb
(per mg/
kg-day)
-
-
-
-
-
0 015-
0.055
-
-
-
0.002
Cancer WOE
character-
ization
"Inadequate
information to
assess the
carcinogenic
potential"
-
D
Bl
A (inhaled);
D(oral)
A
"Data are
inadequate to
assess human
carcinogenic
potential"
-
D
D
"Likely to be
carcinogenic in
humans"
PPRTV
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
-
-
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
ization
-
-
-
-
-
-
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
0.002
0.0009
0.0005
0.04
-
-
0.005
0.06
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
0.02
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
0.2
-
-
0.004
-
0
-
-
0.05
0
MCLs
(mg/L)
0.2
-
-
0.004
-
0.005
-
-
0.05
0.005
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
1,2,4-
Trichlorobenzene
Tetrachloroethyl
ene
Chloroform
Di(2-ethylhexyl)
phthalate
Naphthalene
2,4-
Dimethylphenol
Chlorodibromom
ethane
Bromoform
Bromodichlorom
ethane
Diphenylamine
1,4-Dioxane
CASRN
120-82-1
127-18-4
67-66-3
117-81-7
91-20-3
105-67-9
124-48-1
75-25-2
75-27-4
122-39-4
123-91-1
Concen-
tration
data
available
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
X
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
0.01
0.006
0.01
0.02
0.02
0.02
0.02
0.02
0.02
0.025
0.03
OSFb
(per mg/
kg-day)
-
0.0021
-
0.014
-
-
0.084
0.0079
0.062
-
0.1
Cancer WOE
character-
ization
D
"Likely to be
carcinogenic in
humans"
B2
B2
"Data are
inadequate to
assess human
carcinogenic
potential"
-
C
B2
B2
-
"Likely to be
carcinogenic to
humans"
PPRTV
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
OSFb
(per mg/
kg-day)
0.029
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
ization
LI
-
-
-
-
IN
-
-
-
IN
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
0.1
0.008
0.01
0.06
-
-
0.09
0.02
0.02
-
0.1
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
-
0.1
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
0.07
0
-
0
-
-
-
-
-
-
-
MCLs
(mg/L)
0.07
0.005
-
0.006
-
-
-
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Pyrene
Fluoranthene
Fluorene
m-Cresol
o-Cresol
Toluene
Chlorine
Ethylbenzene
Cumene
Acetophenone
Carbon disulfide
Dibutyl phthalate
CASRN
129-00-0
206-44-0
86-73-7
108-39-4
95-48-7
108-88-3
7782-50-5
100-41-4
98-82-8
98-86-2
75-15-0
84-74-2
Concen-
tration
data
available
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
X
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
0.03
0.04
0.04
0.05
0.05
0.08
0.1
0.1
0.1
0.1
0.1
0.1
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
-
Cancer WOE
character-
ization
D
D
D
C
C
"Inadequate
information to
assess the
carcinogenic
potential"
-
D
D
D
-
D
PPRTV
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
-
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
ization
-
IN
-
-
IN
-
-
-
-
-
-
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
-
-
-
-
-
1
-
0.7
-
-
-
-
MCLs
(mg/L)
-
-
-
-
-
1
-
0.7
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Nitrite
Manganese
Xylenes
Barium
Boron
Zinc
Phenol
CASRN
14797-65-0
7439-96-5
1330-20-7
7440-39-3
7440-42-8
7440-66-6
108-95-2
Concen-
tration
data
available
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
0.1
0.14
0.2
0.2
0.2
0.3
0.3
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
—
Cancer WOE
character-
ization
-
D
"Data are
inadequate to
assess the
carcinogenic
potential"
"Not likely to
be carcinogenic
to humans"
"Data are
inadequate to
assess the
carcinogenic
potential"
"Inadequate
information to
assess
carcinogenic
potential"
"Data are
inadequate to
assess human
carcinogenicity
rr
PPRTV
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
Cancer
WOE
character-
ization
-
-
-
-
-
-
—
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
0.2
0.2
-
0.3
—
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
1
-
10
2
-
-
—
MCLs
(mg/L)
1
-
10
2
-
-
—
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Strontium
Methyl ethyl
ketone
Diethyl phthalate
Acetone
Chromium (III)
Nitrate
Ethylene glycol
Methanol
1,2-Propylene
glycol
Formic acid
Aluminum
CASRN
7440-24-6
78-93-3
84-66-2
67-64-1
16065-83-1
14797-55-8
107-21-1
67-56-1
57-55-6
64-18-6
7429-90-5
Concen-
tration
data
available
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
0.6
0.6
0.8
0.9
1.5
1.6
2
2
-
-
-
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
Cancer WOE
character-
ization
-
"Data are
inadequate to
assess
carcinogenic
potential"
D
"Data are
inadequate to
assess human
carcinogen/city
rr
"Data are
inadequate to
assess human
carcinogenicity
rr
-
-
-
-
-
-
PPRTV
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
-
20
0.9
1
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
ization
-
-
-
-
-
-
-
-
NL
IN
IN
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
1
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
-
-
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
-
-
-
-
-
10
-
-
-
-
-
MCLs
(mg/L)
-
-
-
-
-
10
-
-
-
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Iron
Bis(2-chloroethyl)
ether
Benzyl alcohol
Butylbenzene
Acrylonitrile
Phorate
beta-Hexachloro
cyclohexane
Benzo(a)pyrene
p,p'-DDE
Lithium
CASRN
7439-89-6
111-44-4
100-51-6
104-51-8
107-13-1
298-02-2
319-85-7
50-32-8
72-55-9
7439-93-2
Concen-
tration
data
available
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
IRIS
Chronic
RfDa (mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
OSFb
(per mg/
kg-day)
-
1.1
-
-
0.54
-
1.8
7.3
0.34
-
Cancer WOE
character-
ization
-
B2
-
-
Bl
-
C
B2
B2
-
PPRTV
Chronic
RfDa (mg/
kg-day)
0.7
-
0.1
0.05
-
-
-
-
-
0.002
OSFb
(per mg/
kg-day)
-
-
-
-
-
-
-
-
-
-
Cancer
WOE
character-
ization
IN
-
IN
IN
-
-
-
-
-
IN
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
-
0.04
-
-
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
-
-
0.0005
-
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
-
-
-
-
-
-
-
0
-
-
MCLs
(mg/L)
-
-
-
-
-
-
-
0.0002
-
-
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical Name
Cobalt
Vanadium
N-Nitrosodiphen
ylamine
CASRN
7440-48-4
7440-62-2
86-30-6
Concen-
tration
data
available
X
X
X
Physico-
chemical
data
available
X
IRIS
Chronic
RfDa (mg/
kg-day)
-
-
-
OSFb
(per mg/
kg-day)
-
-
0.0049
Cancer WOE
character-
ization
-
-
B2
PPRTV
Chronic
RfDa (mg/
kg-day)
0.0003
0.00007
-
OSFb
(per mg/
kg-day)
-
-
-
Cancer
WOE
character-
ization
LI
IN
-
ATSDR
Chronic
oral MRLd
(mg/
kg-day)
-
-
-
HHBP
Chronic
RfDe
(mg/kg-
day)
-
-
-
National Primary
Drinking Water
Regulations
Public
health
goal'
(MCLG)
(mg/L)
-
-
-
MCLs
(mg/L)
-
-
-
ATSDR = Agency for Toxic Substances and Disease Registry; CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional
Peer Reviewed Toxicity Values; HHBP = Human Health Benchmarks for Pesticides
a Reference dose (RfD) (IRIS and PPRTV definition): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population
(including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level
(NOAEL), lowest observed-adverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is
generally used in the EPA's noncancer health assessments. Chronic RfD: Duration of exposure is up to a lifetime.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime oral exposure to an agent. This estimate, usually
expressed in units of proportion (of a population) affected per mg/kg day, is generally reserved for use in the low dose region of the dose response relationship, that is, for
exposures corresponding to risks less than 1 in 100.
c Weight of evidence (WOE) characterization for carcinogenicity: A system used for characterizing the extent to which the available data support the hypothesis that an agent
causes cancer in humans. See glossary for details.
d Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of
harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs
should not be used as predictors of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer.
e Reference dose (RfD) (HHBP definition): The particular concentration of a chemical that is known not to cause health problems. A standard that also may be referred to as the
acceptable daily intake. Derived using the same EPA guidance for RfD determination.
f Maximum contaminant level goal (MCLG): The level of a contaminant in drinking water below which there is no known or expected risk to health. MCLGs allow for a margin of
safety and are nonenforceable public health goals.
g Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to MCLGs as feasible using the best available
treatment technology and taking cost into consideration. MCLs are enforceable standards.
June 2015
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Table G-2b. Chemicals reported to be detected in flowback or produced water, with available
state chronic RfVs and OSFs.
Chemicals are ranked by California EPA maximum allowable daily level (MADL). The "--" symbol
indicates that no value was available from the sources consulted. Additionally, an "x" indicates the
availability of measured concentration data in flowback or produced water (see Appendix E) and
physicochemical properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in
both fracturing fluids and flowback/produced water.
Chemical name
Lead
Cadmium
Chromium (VI)
Dibutyl phthalate
Benzene
Acrylonitrile
1,4-Dioxane
Ethylbenzene
Di(2-ethylhexyl) phthalate
Arsenic
Bis(2-chloroethyl) ether
Heptachlor epoxide
1,2,4-Trichlorobenzene
Tetrachloroethylene
lndeno(l,2,3-cd)pyrene
Benzo(b)fluoranthene
Benzo(k)fluoranthene
Aldrin
beta-Hexachlorocyclohexane
Benzo(a)pyrene
Dibenz(a,h)anthracene
7,12-Dimethylbenz(a)anthracene
Lindane
Dieldrin
Chloroform
CASRN
7439-92-1
7440-43-9
18540-29-9
84-74-2
71-43-2
107-13-1
123-91-1
100-41-4
117-81-7
7440-38-2
111-44-4
1024-57-3
120-82-1
127-18-4
193-39-5
205-99-2
207-08-9
309-00-2
319-85-7
50-32-8
53-70-3
57-97-6
58-89-9
60-57-1
67-66-3
Concen-
tration
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
California
Oral MADLa
(u,g/day)
0.5
4.1
8.2
8.7
24
-
-
-
20 (neonate male)
58 (infant male)
410 (adult)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
OSFb (per
mg/kg-day)
0.0085
15
0.5
-
0.1
1
0.027
0.011
0.003
9.5
2.5
5.5
0.0036
0.051
1.2
1.2
1.2
17
1.5
2.9
4.1
250
1.1
16
0.019
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-31 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical name
p,p'-DDE
Bromoform
Bromodichloromethane
Heptachlor
N-Nitrosodiphenylamine
Safrole
Dichloromethane
CASRN
72-55-9
75-25-2
75-27-4
76-44-8
86-30-6
94-59-7
75-09-2
Concen-
tration
data
available
X
Physico-
chemical
data
available
X
X
X
X
X
X
X
California
Oral MADLa
(Hg/day)
-
-
-
-
-
-
-
OSFb (per
mg/kg-day)
0.34
0.011
0.13
4.1
0.009
0.22
0.014
3 Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive toxicant at which the chemical
would have no observable adverse reproductive effect, assuming exposure at 1,000 times that level.
b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime
oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per mg/kg day, is
generally reserved for use in the low-dose region of the dose-response relationship, that is, for exposures corresponding to
risks less than 1 in 100.
This document is a draft for review purposes only and does not constitute Agency policy.
June 2015 G-32 DRAFT—DO NOT CITE OR QUOTE
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Table G-2c. Chemicals reported to be detected in flowback or produced water, with available
international chronic RfVs and OSFs.
Chemicals are ranked by CICAD reference dose (TDI -Tolerable Daily Intake). An "x" indicates the
availability of measured concentration data in flowback or produced water (see Appendix E) and
physicochemical properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in
both fracturing fluids and flowback/produced water.
Chemical name
Heptachlor
Strontium
Chloroform
Mercury
Barium
Beryllium
Ethylene glycol
Tetrachloroethene
Chromium (VI)
Diethyl phthalate
CASRN
76-44-8
7440-24-6
67-66-3
7439-97-6
7440-39-3
7440-41-7
107-21-1
127-18-4
18540-29-9
84-66-2
Concentration
data available
X
X
X
X
X
Physicochemical
data available
X
X
X
X
X
IPCS Chronic TDIa
(mg/kg-day)
0.0001
0.13
0.015
0.002
0.02
0.002
0.05
0.05
0.0009
5
IPCS = International Programme on Chemical Safety; CICAD = Concise International Chemical Assessment Documents
a Tolerable Daily Intake (TDI): An estimate of the intake of a substance, expressed on a body mass basis, to which an individual
in a (sub) population may be exposed daily over its lifetime without appreciable health risk.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Table G-2d. Chemicals reported to be detected in flowback or produced water, with available
less-than-chronic RfVs and OSFs.
Chemicals are ranked by PPRTV subchronic reference dose (sRfD). The "--" symbol indicates that no
value was available from the sources consulted. Additionally, an "x" indicates the availability of
measured concentration data in flowback or produced water (see Appendix E) and physicochemical
properties data from EPI Suite™ (see Appendix C). Italicized chemicals are found in both fracturing
fluids and flowback/produced water.
Chemical name
Aldrin
Antimony
Vanadium
Lithium
Cobalt
2-Methylnaphthalene
Methyl bromide
Bromodichloromethane
1,2,3-Trichlorobenzene
Benzene
p-Cresol
Bromoform
Ethylbenzene
2,4-Dimethylphenol
Chlorodibromomethane
1,2,4-Trichlorobenzene
Butylbenzene
Benzyl alcohol
Pyrene
Xylenes
Iron
Toluene
Formic acid
1,2-Propylene glycol
CASRN
309-00-2
7440-36-0
7440-62-2
7439-93-2
7440-48-4
91-57-6
74-83-9
75-27-4
87-61-6
71-43-2
106-44-5
75-25-2
100-41-4
105-67-9
124-48-1
120-82-1
104-51-8
100-51-6
129-00-0
1330-20-7
7439-89-6
108-88-3
64-18-6
57-55-6
Concen-
tration
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PPRTV
sRfDa
(mg/kg-day)
0.00004
0.0004
0.0007
0.002
0.003
0.004
0.005
0.008
0.008
0.01
0.02
0.03
0.05
0.05
0.07
0.09
0.1
0.3
0.3
0.4
0.7
0.8
0.9
20
ATSDR
Acute oral
MRLb
(mg/kg-day)
0.002
-
-
-
-
-
-
0.04
-
-
-
0.7
-
-
0.1
-
-
-
-
1
-
0.8
-
-
Intermediate
oral MRLC
(mg/kg-day)
-
-
0.01
-
0.01
-
0.003
-
-
-
-
0.2
0.4
-
-
0.1
-
-
-
0.4
-
0.02
-
-
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical name
Acrolein
1,4-Dioxane
Ethylene glycol
Di(2-ethylhexyl)
phthalate
Naphthalene
Phenol
Acetone
Arsenic
Chromium (VI)
Copper
Zinc
Aluminum
Acrylonitrile
Dioctyl phthalate
Tetrachloroethylene
Fluoranthene
beta-
Hexachlorocyclohexane
Lindane
Dieldrin
Chloroform
Strontium
Tin
Barium
Boron
Cadmium
Carbon disulfide
Heptachlor
Phosphorus
CASRN
107-02-8
123-91-1
107-21-1
117-81-7
91-20-3
108-95-2
67-64-1
7440-38-2
18540-29-9
7440-50-8
7440-66-6
7429-90-5
107-13-1
117-84-0
127-18-4
206-44-0
319-85-7
58-89-9
60-57-1
67-66-3
7440-24-6
7440-31-5
7440-39-3
7440-42-8
7440-43-9
75-15-0
76-44-8
7723-14-0
Concen-
tration
data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Physico-
chemical data
available
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
PPRTV
sRfDa
(mg/kg-day)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
0.1
-
-
-
-
-
-
-
-
-
-
-
-
ATSDR
Acute oral
MRLb
(mg/kg-day)
-
5
0.8
-
0.6
1
-
0.005
-
0.01
-
-
0.1
3
0.008
-
0.05
0.003
-
0.3
-
-
-
0.2
-
0.01
0.0006
-
Intermediate
oral MRLC
(mg/kg-day)
0.004
0.5
0.8
0.1
0.6
-
2
-
0.005
0.01
0.3
1
0.01
0.4
0.008
0.4
0.0006
0.00001
0.0001
0.1
2
0.3
0.2
0.2
0.0005
-
0.0001
0.0002
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix G
Chemical name
Diethyl phthalate
Dibutyl phthalate
Fluorene
Dichloromethane
CASRN
84-66-2
84-74-2
86-73-7
75-09-2
Concen-
tration
data
available
X
X
Physico-
chemical data
available
X
X
X
X
PPRTV
sRfDa
(mg/kg-day)
-
-
-
-
ATSDR
Acute oral
MRLb
(mg/kg-day)
7
0.5
-
0.2
Intermediate
oral MRLC
(mg/kg-day)
6
-
0.4
-
a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the
human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during
a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-adverse-effect level (LOAEL),
or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is
generally used in the EPA's noncancer health assessments. Subchronic RfD (sRFD): Duration of exposure is up to 10% of an
average lifespan.
b Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the
substance is unlikely to pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of
exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as
predictors of harmful (adverse) health effects. Acute MRL: Duration of exposure is 1 to 14 days.
c Minimum risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the
substance is unlikely to pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of
exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as
predictors of harmful (adverse) health effects. Intermediate MRL: Duration of exposure is >14 to 364 days.
G.4. References for Appendix G
ATSDR (Agency for Toxic Substances and Disease Registry). (2009). Glossary of terms. Available online at
http://www.atsdr.cdc.gov/glossary.html
IARC (International Agency for Research on Cancer). (2015). IARC monographs - Classifications. Available
online at http://monographs.iarc.fr/ENG/Classification/index.php
NTP (National Toxicology Program). (2014a). Definition of carcinogenicity results. Available online at
http://ntp.niehs.nih.gov/results/pubs/longterm/defs/index.html
NTP (National Toxicology Program). (2014b). Report on carcinogens. Thirteenth edition. Research Triangle
Park, NC: U.S. Department of Health and Human Services, Public Health Service.
http://ntp.niehs.nih.gov/pubhealth/roc/rocl3/index.html
25701 (2012).
OEHHA. Title 27. California Code of Regulations Article 8. No Observable Effect Levels.
http://www.oehha.ca.gov/prop65/law/pdf zip/RegsArt8.pdf
U.S. EPA (U.S. Environmental Protection Agency). (1996). Proposed guidelines for carcinogen risk assessment
[EPA Report]. (EPA/600/P-92/003C). Washington, DC: U.S. Environmental Protection Agency, Risk
Assessment Forum.
U.S. EPA (U.S. Environmental Protection Agency). (1999). Guidelines for carcinogen risk assessment [review
draft] [EPA Report]. (NCEA-F-0644). Washington, DC.
http://www.epa.gov/raf/publications/pdfs/CANCER GLS.PDF
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix C
U.S. EPA (U.S. Environmental Protection Agency). (2011a). Plan to study the potential impacts of hydraulic
fracturing on drinking water resources [EPA Report]. (EPA/600/R-11/122). Washington, DC: U.S.
Environmental Protection Agency, Office of Research and Development.
http://www2.epa.gov/hfstudy/plan-study-potential-impacts-hydraulic-fracturing-drinking-water-
resources-epa600r-11122
U.S. EPA (U.S. Environmental Protection Agency). (2011c). Terminology services (TS): Vocabulary catalog -
IRIS glossary. Available online at
http://ofmpub.epa.gov/sor internet/registry/termreg/searchandretrieve/glossariesandkeywordlists/se
arch.do?details=&glossaryName=IRIS%20Glossary (accessed May 21, 2015).
U.S. EPA (U.S. Environmental Protection Agency). (2012c). Study of the potential impacts of hydraulic
fracturing on drinking water resources: Progress report. (EPA/601/R-12/011). Washington, DC: U.S.
Environmental Protection Agency, Office of Research and Development.
http://nepis.epa.gov/exe/ZyPURL.cgi?Dockey=P100FH8M.txt
U.S. EPA (U.S. Environmental Protection Agency). (2014b). Drinking water contaminants. Available online at
http://water.epa.gov/drink/contaminants/
U.S. EPA (U.S. Environmental Protection Agency). (2015a). Analysis of hydraulic fracturing fluid data from the
FracFocus chemical disclosure registry 1.0 [EPA Report]. (EPA/601/R-14/003). Washington, D.C.: Office
of Research and Development, U.S. Environmental Protection Agency.
http://www2.epa.gov/hfstudy/analysis-hydraulic-fracturing-fluid-data-fracfocus-chemical-disclosure-
registry-1-pdf
U.S. EPA (U.S. Environmental Protection Agency). (2015e). Human health benchmarks for pesticides.
Available online at http://iaspub.epa.gov/apex/pesticides/f?p=HHBP:HOME
WHO (World Health Organization). (2015). Concise international chemical assessment documents. Available
online at http://www.who.int/ipcs/publications/cicad/en/
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix H
Appendix H
Description of EPA Hydraulic Fracturing Study
Publications Cited in This Assessment
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix H
Appendix H. Description of EPA Hydraulic Fracturing
Study Publications Cited in This Assessment
Table H-l. Titles, descriptions, and citations for EPA hydraulic fracturing study publications
cited in this assessment.
Research project
Description
Citations
Analysis of existing data
Literature Review
Review and assessment of existing
papers and reports, focusing on
peer-reviewed literature
Literature review is incorporated into this document.
Spills Database
Analysis
Characterization of hydraulic
fracturing-related spills using
information obtained from
selected state and industry data
sources
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Review of state and industry spill data:
characterization of hydraulic fracturing-related spills
[EPA Report]. (EPA/601/R-14/001). Washington, D.C.:
Office of Research and Development, U.S.
Environmental Protection Agency.
Service Company
Analysis
Analysis of information provided
by nine hydraulic fracturing service
companies in response to a
September 2010 information
request on hydraulic fracturing
operations
Analysis of data received is incorporated into this
document.1
Well File Review
Analysis of information provided
by nine oil and gas operators in
response to an August 2011
information request for 350 well
files
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Review of well operator files for hydraulically
fractured oil and gas production wells: Well design and
construction [EPA Report]. (EPA/601/R-14/002).
Washington, D.C.: Office of Research and Development,
U.S. Environmental Protection Agency.
Analysis of data received is also incorporated into this
document.2
1 Data received and incorporated into this document is cited as: U.S. EPA (U.S. Environmental Protection Agency). (2013).
Data received from oil and gas exploration and production companies, including hydraulic fracturing service companies
2011 to 2013. Non-confidential business information source documents are located in Federal Docket ID: EPA-HQ-
ORD2010-0674. Available at MsiUMMMim^M^SS&gSI.
2 Data received and incorporated into this document is cited as: U.S. EPA (U.S. Environmental Protection Agency). (2011).
Sampling data for flowback and produced water provided to EPA by nine oil and gas well operators (non-confidential
business information). US Environmental Protection Agency.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix H
Research project
FracFocus Analysis
Description
Analysis of data compiled from
FracFocus 1.0, the national
hydraulic fracturing chemical
registry operated by the Ground
Water Protection Council and the
Interstate Oil and Gas Compact
Commission
Citations
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Analysis of hydraulic fracturing fluid data from
the FracFocus chemical disclosure registry 1.0 [EPA
Report]. (EPA/601/R- 14/003). Washington, D.C.: Office
of Research and Development, U.S. Environmental
Protection Agency, http://www2.epa.gov/hfstudy/
analysis-hydraulic-fracturing-fluid-data-fracfocus-
chemical-disclosure-registry-1-pdf
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Analysis of hydraulic fracturing fluid data from
the FracFocus chemical disclosure registry 1.0: project
database. Washington, D.C.: U.S. Environmental
Protection Agency, Office of Research and
Development.
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Analysis of hydraulic fracturing fluid data from
the FracFocus chemical disclosure registry 1.0: Data
management and quality assessment report [EPA
Report]. (EPA/601/R- 14/006). Washington, D.C.: U.S.
Environmental Protection Agency, Office of Research
and Development, http://www2.epa.gov/sites/
production/files/2015-03/documents/fracfocus data
management report final 032015 508.pdf
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix H
Research project
Description
Citations
Scenario evaluations
Subsurface
Migration
Modeling
Numerical modeling of subsurface
fluid migration scenarios that
explore the potential for fluids,
including liquids and gases to move
from the fractured zone to drinking
water aquifers
Kim, J; Moridis, GJ. (2013). Development of the T+M
coupled flow-geomechanical simulator to describe
fracture propagation and coupled flow-thermal-
geomechanical processes in tight/shale gas systems.
Computers and Geosciences 60: 184-198.
http://dx.doi.0rg/10.1016/i.cageo.2013.04.023
Kim, J; Moridis, GJ. (In Press). Numerical analysis of
fracture propagation during hydraulic fracturing
operations in shale gas systems. International Journal of
Rock Mechanics and Mining Sciences.
Kim, J; Urn, ES; Moridis, GJ. (2014). Fracture
Propagation, Fluid Flow, and Geomechanics of Water-
Based Hydraulic Fracturing in Shale Gas Systems and
Electromagnetic Geophysical Monitoring of Fluid
Migration. SPE Hydraulic Fracturing Technology
Conference, The Woodlands, Texas, USA.
http://dx.doi.org/10.2118/168578-MS
Reagan, MT; Moridis, GJ; Johnson, JN; Keen, ND. (2015).
Numerical simulation of the environmental impact of
hydraulic fracturing of tight/shale gas reservoirs on
near-surface groundwater: background, base cases,
shallow reservoirs, short-term gas and water transport.
Water Resour Res 51: 1-31. http://dx.doi.org/10.1002/
2014WR016086
Rutqvist, J; Rinaldi, AP; Cappa, F; Moridis, GJ. (2013).
Modeling of fault reactivation and induced seismicity
during hydraulic fracturing of shale-gas reservoirs.
Journal of Petroleum Science and Engineering 107: 31-
44. http://dx.doi.0rg/10.1016/i.petrol.2013.04.023
Rutqvist, J; Rinaldi, AP; Cappa, F; Moridis, GJ. (2015).
Modeling of fault activation and seismicity by injection
directly into a fault zone associated with hydraulic
fracturing of shale-gas reservoirs. Journal of Petroleum
Science and Engineering 127: 377-386.
http://dx.doi.0rg/10.1016/i.petrol.2015.01.019
Surface Water
Modeling
Modeling of concentrations of
selected chemicals at public water
supplies downstream from
wastewater treatment facilities
that discharge treated hydraulic
fracturing wastewater to surface
waters
Weaver, JW; Xu, J; Mravik, SC. (In Press) Scenario
analysis of the impact on drinking water intakes from
bromide in the discharge of treated oil and gas waste
water. J Environ Eng.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix H
Research project
Description
Citations
Water Availability
Modeling
Assessment and modeling of
current and future scenarios
exploring the impact of water
usage for hydraulic fracturing on
drinking water availability in the
Upper Colorado River Basin and
the Susquehanna River Basin
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Case study analysis of the impacts of water
acquisition for hydraulic fracturing on local water
availability [EPA Report]. (EPA/600/R-14/179).
Washington, D.C.
Laboratory studies
Source
Apportionment
Studies
Identification and quantification of
the source(s) of high bromide and
chloride concentrations at public
water supply intakes downstream
from wastewater treatment plants
discharging treated hydraulic
fracturing wastewater to surface
waters
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Sources contributing bromide and inorganic
species to drinking water intakes on the Allegheny river
in western Pennsylvania [EPA Report]. (EPA/600/R-
14/430). Washington, D.C.
Analytical Method
Development
Development of analytical
methods for selected chemicals
found in hydraulic fracturing fluids
or wastewater
DeArmond, PD; DiGoregorio, AL (2013).
Characterization of liquid chromatography-tandem
mass spectrometry method for the determination of
acrylamide in complex environmental samples. Anal
Bioanal Chem 405: 4159-4166. '
DeArmond, PD; DiGoregorio, AL (2013). Rapid liquid
chromatography-tandem mass spectrometry-based
method for the analysis of alcohol ethoxylates and
alkylphenol ethoxylates in environmental samples. J
Chromatogr A 1305:154-163. httfiI//d)tdoLo£g/
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix H
Research project
Description
Citations
Analytical Method
Development
(cont.)
Development of analytical
methods for selected chemicals
found in hydraulic fracturing fluids
or wastewater (cont.)
U.S. EPA (U.S. Environmental Protection Agency).
(2014). Development of rapid radiochemical method for
gross alpha and gross beta activity concentration in
flowback and produced waters from hydraulic
fracturing operations [EPA Report]. (EPA/600/R-
14/107). Washington, D.C. http://www2.epa.gov/
hfstudy/development-rapid-radiochemical-method-
gross-alpha-and-gross-beta-activity-concentration
U.S. EPA (U.S. Environmental Protection Agency).
(2014). The verification of a method for detecting and
quantifying diethylene glycol, triethylene glycol,
tetraethylene glycol, 2-butoxyethanol and 2-
methoxyethanol in ground and surface waters [EPA
Report]. (EPA/600/R-14/008). Washington, D.C.
http://www2.epa.gov/hfstudv/verification-method-
detecting-and-quantifving-diethvlene-glycol-
triethylene-glycol
Retrospective case studies
Investigations of whether reported drinking water impacts may be associated with or caused by hydraulic
fracturing activities
Las Animas and
Huerfano
Counties, Colorado
Investigation of potential drinking
water impacts from coalbed
methane extraction in the Raton
Basin
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Retrospective case study in the Raton Basin,
Colorado: study of the potential impacts of hydraulic
fracturing on drinking water resources [EPA Report].
(EPA 600/R-14/091). Washington, D.C.
Dunn County,
North Dakota
Investigation of potential drinking
water impacts from a well blowout
during hydraulic fracturing for oil
in the Bakken Shale
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Retrospective case study in Killdeer, North
Dakota: study of the potential impacts of hydraulic
fracturing on drinking water resources [EPA Report].
(EPA 600/R-14/103). Washington, D.C.
Bradford County,
Pennsylvania
Investigation of potential drinking
water impacts from shale gas
development in the Marcellus
Shale
U.S. EPA (U.S. Environmental Protection Agency).
(2014). Retrospective case study in northeastern
Pennsylvania: study of the potential impacts of
hydraulic fracturing on drinking water resources [EPA
Report]. (EPA 600/R-14/088). Washington, D.C.
Washington
County,
Pennsylvania
Investigation of potential drinking
water impacts from shale gas
development in the Marcellus
Shale
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Retrospective case study in southwestern
Pennsylvania: study of the potential impacts of
hydraulic fracturing on drinking water resources [EPA
Report]. (EPA 600/R-14/084). Washington, D.C.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix H
Research project
Description
Citations
Wise County,
Texas
Investigation of potential drinking
water impacts from shale gas
development in the Barnett Shale
U.S. EPA (U.S. Environmental Protection Agency).
(2015). Retrospective case study in Wise County, Texas:
study of the potential impacts of hydraulic fracturing on
drinking water resources [EPA Report]. (EPA 600/R-
14/090). Washington, D.C.
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment Appendix I
Appendix I
Unit Conversions
This document is a draft for review purposes only and does not constitute Agency policy.
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Hydraulic Fracturing Drinking Water Assessment
Appendix I
Appendix I. Unit Conversions
LENGTH
2
3
4
5
6
7
8
1 in (inch)
1 ft (foot)
1 mi (mile)
2.54 cm (centimeters)
25.4 mm (millimeters)
25,400 |im (microns)
0.3048m (meters)
30.48cm
5,280 ft
1,609.344m
1.6093 km (kilometers)
10 AREA
11 1 ft2 (square foot)
1 acre
12
13
14
15
16 1 mi2
17
18
0.0929 m2 (square meters)
43,560 ft2
0.0016 mi2 (square miles)
0.4047 ha (hectares)
4,046.825 m2
639.9974 ac
258.9988 ha
2.5899 km2 (square kilometers)
19 MASS
20 lib (pound)
21
22 1 ton (short ton, U.S.)
23
24
453.5924 g (grams)
0.4536 kg (kilograms)
2,000 Ibs
907.185kg
0.9072 metric tons
This document is a draft for review purposes only and does not constitute Agency policy.
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Appendix I
VOLUME OR CAPACITY (LIQUID MEASURE)
2
3
4
5
6
7
10
11
12
13
14
15
1 bbl (barrel)
Igal
1 Mgal (million gallons)
1ft3
1 mi3 (cubic mile)
42 gal (gallons, U.S.)
158.9873 L (liters)
231 in3 (cubic inches)
0.1337 ft3 (cubic feet)
3.7854 L
0.0039 m3 (cubic meters)
3.7854 x 10-9 Mm3 (million cubic meters)
1.3368x105 ft3
1,728 in3
7.4805 gal
28.3169 L
0.0283m3
4.1682 km3 (cubic kilometers)
16 CONCENTRATION
17
18
19
20
21
22
1 mg/L (milligram per liter)
1.0 x IQ-6 kg/L (kilograms per liter)
1.0 x IQ-3 g/L (grams per liter)
1,000 |ig/L (micrograms per liter)
1.001 ppm (parts per million)
8.3454 x IQ-6 Ib/gal (pounds per gallon)
6.2428 x lO-5 lb/ft3 (pounds per cubic foot)
23
24
25
SPEED
1 mi/hr (mile per hour)
1.4666 ft/s (feet per second)
0.4470 m/s (meters per second)
26
27
28
DENSITY
Ig/mL
1,000 g/L
1.0 x 106mg/L
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Appendix I
VOLUME PER UNIT TIME
1 ft3/s (cubic foot per second)
2
3
4
5
6 1 ft3/day (cubic feet per day)
7
10 1 bbl/day (barrel per day)
11
448.8312 gpm (gallons per minute)
0.6163 Mgpd (million gallons per day)
28.3169 L/s (liters per second)
0.0283 m3/s (cubic meters per second)
0.0052 gpm
7.4805 gpd
0.0283 m3/d (cubic meters per day)
42 gpd
158.9873 L/d (liters per day)
12
PRESSURE
13 1 psi (pound per square inch)
14
6,894.7573 Pa (pascals)
0.068 atm (standard atmospheres)
15 RADIATION
16 Activity
17 1 Ci (curie)
18 1 Bq (becquerel)
19
20 IpCi
21
22
3.7 x 1010 decays per second
2.703 x ID-" Ci
27.027 pCi (picocuries)
0.037 Bq
0.037 decays per second
2.22 decays per minute
2 3 Exposure
24 1 rem (roentgen equivalent in man)
25 ISv
O.OlSv(sieverts)
1 J/kg (joule per kilogram)
26
27
28
29
30
31
ELECTRIC CONDUCTANCE
1 S (siemen)
1 fl-1 (reciprocal of resistance)
1 A/V (ampere per volt)
1 kg-1 • nr2 • s3 • A2 (second cubed- ampere squared
per kilogram-square meter)
1.0 x 106 [j.S (microsiemens)
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Hydraulic Fracturing Drinking Water Assessment Appendix I
1 TEMPERATURE
2 [°F (degrees, Fahrenheit) - 32] x 5/9 = °C (degrees, Celsius)
3 PERMEABILITY
4 1cm2 = 1.Ox 10-4 m2
5 « 1.0 x 108D (darcys)
6 ID * 1.0xlO-i2m2
7 = 1,000 mD (millidarcys)
8 1.0 x 106 |iD (microdarcys)
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Hydraulic Fracturing Drinking Water Assessment Appendix J
Appendix J
Glossary
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Appendix J. Glossary
J.I. Glossary Terms and Definitions
1 Acid mine drainage: Flow of water from areas that have been mined for coal or other mineral ores.
2 The water has a low pH because of its contact with sulfur-bearing material and is harmful to
3 aquatic organisms. (U.S. EPA, 2013d]
4 Additive: A single chemical or chemical mixture designed to serve a specific purpose in the
5 hydraulic fracturing fluid.1
6 Adsorption: Adhesion of molecules of gas, liquid, or dissolved solids to a surface. (U.S. EPA. 2013d]
7 Advection: A mechanism for moving chemicals in flowing water, where a chemical moves along
8 with the flow of the water itself.
9 Aeration: A process that promotes biological degradation of organic matter in water. The process
10 may be passive (as when waste is exposed to air] or active (as when a mixing or bubbling device
11 introduces the air]. (U.S. EPA. 2013d]
12 Aerobic mesophiles: Microorganisms that use oxygen for energy production and are tolerant of
13 moderate temperatures.
14 Analyte: The element, ion, or compound that an analysis seeks to identify; the compound of
15 interest fU.S. EPA. 2013dl
16 Annulus: Refers to either the space between the casing of a well and the wellbore or the space
17 between any two strings of tubing or casing. (U.S. EPA. 2013d]
18 API number: A unique identifying number for all oil and gas wells drilled in the United States. The
19 system was developed by the American Petroleum Institute. (Oil and Gas Mineral Services, 2010]
2 0 Aquifer: An underground geological formation, or group of formations, containing water. A source
21 of ground water for wells and springs. (U.S. EPA. 2013d]
22 Base fluid: The fluid into which additives and proppants are mixed to formulate a hydraulic
23 fracturing fluid.
24 Basin: A depression in the crust of the earth, caused by plate tectonic activity and subsidence, in
25 which sediments accumulate. Sedimentary basins vary from bowl-shaped to elongated troughs.
26 Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental
2 7 margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with
2 8 appropriate depth and duration of burial, then a petroleum system can develop within the basin.
1 Definitions that have no associated citation in this glossary were developed for this assessment.
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1 Most basins contain some amount of shale, thus providing opportunities for shale gas exploration
2 and production. [Schlumberger. 2014]
3 Biogenic: Methane that is produced in shallower formations by bacterial activity in anaerobic
4 conditions. It is the ultimate dissimilation product of microbially mediated reactions of organic
5 molecules.
6 Blowout preventer (BOP): Casinghead equipment that prevents the uncontrolled flow of oil, gas,
7 and mud from the well by closing around the drill pipe or sealing the hole. [Oil and Gas Mineral
8 Services. 2010]
9 Brackish water: Mixed fresh and salt waters. Used here to qualitatively refer to water that contains
10 higher total dissolved solids (TDS] than that typically used for fresh drinking water.
11 BTEX: An acronym for benzene, toluene, ethylbenzene, and xylenes. These chemicals are a group of
12 single ringed aromatic hydrocarbon based on the benzene structure. These compounds are found in
13 petroleum and are of specific importance because of their health effects.
14 Caliper log: A log that is used to check for any wellbore irregularities. It is run prior to primary
15 cementing as a means of calculating the amount of cement needed. Also run in conjunction with
16 other open hole logs for log corrections or run on cased holes to evaluate metal loss. [NYSDEC,
17 2011]
18 Capillarity: The action by which the surface of a liquid where it is in contact with a solid is elevated
19 or depressed depending on the relative attraction of the molecules of the liquid for each other and
20 for those of the solid. Capillary forces arise from the differential attraction between immiscible
21 fluids and solid surfaces; these are the forces responsible for capillary rise in small-diameter tubes
22 and porous materials. [Adapted from Pake, 1978]
23 Casing: Steel pipe that is lowered into a wellbore. Casing extends from the bottom of the hole to the
24 surface. [Schlumberger. 2014]
2 5 Casing inspection logs: An in situ record of casing thickness and integrity, to determine whether
26 and to what extent the casing has undergone corrosion. The term refers to an individual
27 measurement, or a combination of measurements using acoustic, electrical, and mechanical
28 techniques, to evaluate the casing thickness and other parameters. The log is usually presented
29 with the basic measurements and an estimate of metal loss. It was first introduced in the early
30 1960s. Today the terms casing-evaluation log and pipe-inspection log are used synonymously.
31 fSchlumberger. 20141
3 2 Cation exchange capacity: The total amount of cations (positively charged ions] that a soil can
33 hold.
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1 Cement: Material used to support and seal the well casing to the rock formations exposed in the
2 borehole. Cement also protects the casing from corrosion and prevents movement of injectate up
3 the borehole. fU.S. EPA. 2013dl
4 Cement squeeze: A remedial cementing operation designed to force cement into leak paths in
5 wellbore tubulars. The required squeeze pressure is achieved by carefully controlling pump
6 pressure. Squeeze cementing operations may be performed to repair poor primary cement jobs,
7 isolate perforations, or repair damaged casing or liner. [Schlumberger. 2014]
8 Centralized waste treatment facility (CWT): any facility that treats (for disposal, recycling or
9 recovery of material) any hazardous or non-hazardous industrial wastes, hazardous or non-
10 hazardous industrial waste water, and/or used material received from off-site. [U.S. EPA. 2012b]
11 Coalbed methane: Methane contained in coal seams. A coal seam is a layer or stratum of coal
12 parallel to the rock stratification. [U.S. EPA. 2013d]
13 Collapse pressure: The pressure at which a tube, or vessel, will catastrophically deform as a result
14 of differential pressure acting from outside to inside of the vessel or tube. [Schlumberger. 2014]
15 Collar: A threaded coupling used to join two lengths of pipe such as production tubing, casing, or
16 liner. The type of thread and style of collar varies with the specifications and manufacturer of the
17 tubing. [Schlumberger. 2014]
18 Combination truck: A truck tractor or a truck tractor pulling any number of trailers. [U.S.
19 Department of Transportation. 2012]
2 0 Community water systems: Public water systems that supply water to the same population year-
21 round. fU.S. EPA. 2013d
2 2 Completion: A term used to describe the assembly of equipment at the bottom of the well that is
23 needed to enable production from an oil or gas well. It can also refer to the activities and methods
24 (including hydraulic fracturing] used to prepare a well for production following drilling.
25 Complexation: A reaction between two chemicals that form a new complex, either through
26 covalent bonding or ionic forces. This often results in one chemical solubilizing the other.
27 Compressive strength: Measure of the ability of a substance to withstand compression. [NYSDEC.
28 2011]
29 Conductor casing: This large diameter casing is usually the first string of casing in a well. It is set
30 or driven into the unconsolidated material where the well will be drilled to keep the loose material
31 from caving in. [NYSDEC. 2011]
32 Confidential business information (CBI): Information that contains trade secrets, commercial or
33 financial information, or other information that has been claimed as confidential by the submitter.
34 The EPA has special procedures for handling such information. [U.S. EPA. 2013d]
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1 Contaminant: A substance that is either present in an environment where it does not belong or is
2 present at levels that might cause harmful (adverse) health effects. [U.S. EPA. 2013d]
3 Conventional reservoir: A reservoir in which buoyant forces keep hydrocarbons in place below a
4 sealing caprock. Reservoir and fluid characteristics of conventional reservoirs typically permit oil
5 or natural gas to flow readily into wellbores. The term is used to make a distinction from shale and
6 other unconventional reservoirs, in which gas might be distributed throughout the reservoir at the
7 basin scale, and in which buoyant forces or the influence of a water column on the location of
8 hydrocarbons within the reservoir are not significant. [Schlumberger. 2014]
9 Crosslinked gels: linear gels that are linked together by chemicals called crosslinkers, which may
10 link two or more chains together.
11 Crude oil: A general term for unrefined petroleum or liquid petroleum. [Schlumberger. 2014]
12 Cumulative effects: Refers to combined changes in the environment that can take place as a result
13 of multiple activities over time and/or space.
14 Cumulative water use/cumulative water: Refers to the amount of water used or consumed by all
15 hydraulic fracturing wells in a given area per year.
16 Cyclical stress: Refers to stress caused by frequent or rapid changes in temperature or pressure.
17 Deviated well: Any non-horizontal well in which the well bottom is intentionally located at a
18 distance (e.g., hundreds of feet] laterally from the wellhead.
19 Discharge: Any emission (other than natural seepage], intentional or unintentional. Includes, but is
20 not limited to, spilling, leaking, pumping, pouring, emitting, emptying, or dumping. (U.S. EPA.
21 2013d]
22 Disinfection byproduct (DBF): A compound formed by the reaction of a disinfectant such as
23 chlorine with organic material in the water supply. (U.S. EPA. 2013d]
24 Domestic water use: Includes indoor and outdoor water uses at residences, and includes uses such
25 as drinking, food preparation, bathing, washing clothes and dishes, flushing toilets, watering lawns
26 and gardens, and maintaining pools. (USGS, 2015]
27 Drill bit: The tool used to crush or cut rock. Most bits work by scraping or crushing the rock as part
28 of a rotational motion, while some bits work by pounding the rock vertically. (Schlumberger, 2014]
29 Drill collar: A component of a drill string that provides weight on the bit for drilling. Drill collars
30 are thick-walled tubular pieces machined from solid bars of steel, usually plain carbon steel but
31 sometimes of nonmagnetic nickel-copper alloy or other nonmagnetic premium alloys.
32 (Schlumberger. 2014]
3 3 Drill cuttings: Ground rock produced by the drilling process.
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1 Drill string: The combination of the drillpipe, the bottomhole assembly, and any other tools used to
2 make the drill bit turn at the bottom of the wellbore. [Schlumberger. 2014]
3 Drilling fluid: Any of a number of liquid and gaseous fluids and mixtures of fluids and solids used
4 when drilling boreholes. [Adapted from Schlumberger, 2014]
5 Drinking water resource: Any body of ground water or surface water that now serves, or in the
6 future could serve, as a source of drinking water for public or private use [U.S. EPA, 2013d]
7 Dry gas: Refers to natural gas that occurs in the absence of liquid hydrocarbons. [Adapted from
8 Schlumberger. 2014]
9 Effluent: Waste material being discharged into the environment, either treated or untreated. [U.S.
10 EPA. 2013d]
11 Facultative anaerobes: Microorganisms that can use oxygen for energy production if it is present
12 in their environment, but can also use alternatives for energy production if no oxygen is present
13 Fault: A fracture or fracture zone along which there has been displacement of the sides relative to
14 each other. fNYSDEC. 20111
15 Field: Area of oil and gas production with at least one common reservoir for the entire area. [Oil
16 and Gas Mineral Services. 2010]
17 Flowback: The term is defined multiple ways in the literature. In general, it is either fluids
18 predominantly containing hydraulic fracturing fluid that return from a well to the surface or a
19 process used to prepare the well for production.
20 Fluid: A substance that flows when exposed to an external pressure; fluids include both liquids and
21 gases.
22 Fluid formulation: The entire suite of chemicals, proppant, and base fluid injected into a well
23 during hydraulic fracturing. [U.S. EPA. 2013d]
24 Formation: A body of earth material with distinctive and characteristic properties and a degree of
25 homogeneity in its physical properties. [U.S. EPA. 2013d]
2 6 Formation packer: A specialized casing part that has the same inner diameter as the casing but
27 whose outer diameter expands to make contact with the formation and seal the annulus between
28 the casing and formation, preventing migration of fluids.
29 Formation fluid: Fluid that occurs naturally within the pores of rock. These fluids consist primarily
30 of water, with varying concentrations of total dissolved solids, but may also contain oil or gas.
31 Sometimes referred to as native fluids, native brines, or reservoir fluids.
32 FracFocus Registry: A registry for oil and gas well operators to disclose information about
33 hydraulic fracturing well locations, and water and chemical use during hydraulic fracturing
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1 operations developed by the Ground Water Protection Council and the Interstate Oil and Gas
2 Compact Commission.
3 Fracture: A crack or breakage surface within a rock.
4 Fracture geometry: Refers to characteristics of the fracture such as height and aperture (width).
5 Fresh water: Qualitatively refers to water with relatively low IDS that is most readily available for
6 drinking water currently.
7 Gelled fluids: Fracturing fluids that are usually water-based with added gels to increase the fluid
8 viscosity to aid in the transport of proppants. [Spellman. 2012: Gupta and Valko. 2007]
9 Ground water: In the broadest sense, all subsurface water; more commonly that part of the
10 subsurface water in the saturated zone. [Solley etal., 1998]
11 Halite: A soft, soluble evaporate mineral commonly known as salt or rock salt Can be critical in
12 forming hydrocarbon traps and seals because it tends to flow rather than fracture during
13 deformation, thus preventing hydrocarbons from leaking out of a trap even during and after some
14 types of deformation. [Schlumberger. 2014]
15 Hazard evaluation: A component of risk assessment that involves gathering and evaluating data
16 on the types of health injuries or diseases (e.g., cancer] that may be produced by a chemical and on
17 the conditions of exposure under which such health effects are produced.
18 Hazard identification: A process for determining if a chemical or a microbe can cause adverse
19 health effects in humans and what those effects might be. (U.S. EPA. 2013d]
20 Henry's law constant: Ratio of a chemical's vapor pressure in the atmosphere to its solubility in
21 water. The higher the Henry's law constant, the more volatile the compound will be from water.
22 fNYSDEC. 20111
2 3 Horizontal drilling: Drilling a portion of a well horizontally to expose more of the formation
24 surface area to the wellbore. (Oil and Gas Mineral Services. 2010]
25 Horizontal well: A well that is drilled vertically up to a point known as the kickoff point, where the
26 well turns toward the horizontal, extending into and parallel with the approximately horizontal
27 targeted producing formation.
28 Hydraulic fracturing: A stimulation technique used to increase production of oil and gas.
29 Hydraulic fracturing involves the injection of fluids under pressures great enough to fracture the
30 oil- and gas-production formations. (U.S. EPA. 2011a]
31 Hydraulic fracturing fluids: Engineered fluids, typically consisting of a base fluid, additives, and
32 proppant, that are pumped under high pressure into the well to create and hold open fractures in
33 the formation.
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1 Hydraulic fracturing wastewater: Flowback and produced water that is managed using practices
2 that include but are not limited to reuse in subsequent hydraulic fracturing operations, treatment
3 and discharge, and injection into disposal wells.
4 Hydraulic fracturing water cycle: The cycle of water in the hydraulic fracturing process,
5 encompassing the acquisition of water, chemical mixing of the fracturing fluid, injection of the fluid
6 into the formation, the production and management of flowback and produced water, and the
7 ultimate treatment and disposal of hydraulic fracturing waste waters.
8 Hydraulic gradient: Slope of a water table or potentiometric surface. More specifically, change in
9 the hydraulic head per unit of distance in the direction of the maximum rate of decrease. [U.S. EPA.
10 2013dl
11 Hydrocarbon: An organic compound containing only hydrogen and carbon, often occurring in
12 petroleum, natural gas, and coal. [U.S. EPA. 2013d]
13 Hydrostatic pressure: The pressure exerted by a column of fluid at a given depth.
14 Imbibition: The displacement of a non-wet fluid (i.e., gas) by a wet fluid (typically water). [Adapted
15 from Pake. 1978)
16 Immiscible: The chemical property in which two or more liquids or phases are incapable of
17 attaining homogeneity. [U.S. EPA, 2013d]
18 Impact: Any observed change in the quality or quantity of drinking water resources, regardless of
19 severity, that results from a mechanism.
2 0 Impact, potential: Any change in the quality or quantity of drinking water resources that could
21 logically occur, but has not yet been observed, as the result of a mechanism or potential mechanism.
22 Induced fracture: A fracture created during hydraulic fracturing.
23 Injection well: A well into which fluids are being injected (40 CFR 144.3).
24 Integrated risk information system (IRIS): An electronic database that contains the EPA's latest
25 descriptive and quantitative regulatory information about chemical constituents. Files on chemicals
26 maintained in IRIS contain information related to both noncarcinogenic and carcinogenic health
27 effects. (U.S. EPA. 2013d]
28 Intermediate casing: Casing that seals off intermediate depths and geologic formations that may
29 have considerably different reservoir pressures than deeper zones to be drilled. (Devereux. 1998;
30 Baker. 1979]
31 Karst: A type of topography that results from dissolution and collapse of carbonate rocks, such as
3 2 limestone, dolomite, and gypsum, and that is characterized by closed depressions or sinkholes,
33 caves, and underground drainage. (Soiiey etal, 1998]
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1 Kill fluid: A weighted fluid with a density that is sufficient to overcome the formation pressure and
2 prevent fluids from flowing up the wellbore.
3 Large truck: A truck with a gross vehicle weight rating greater than 10,000 pounds.
4
5 Lateral: A horizontal section of a well.
6 Leakoff: The fraction of the injected fluid that infiltrates into the formation (e.g., through an
7 existing natural fissure) and is not recovered during production.
8 Linear gel: a series of chemicals linked together so that they form a chain.
9 Liner: A casing string that does not extend to the top of the wellbore, but instead is anchored or
10 suspended from inside the bottom of the previous casing string. (SchJunibergerI_2fll4)
1 1 Lost cement: Refers to a failure of the cement to be circulated back to the surface, indicating that
1 2 the cement has escaped into the formation.
13 Lowest-observable-adverse effect level (LOAEL): The lowest exposure level at which there are
14 biologically significant increases in frequency or severity of adverse effects between the exposed
15 population and its appropriate control group.
16 Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive
17 toxicant at which the chemical would have no observable adverse reproductive effect, assuming
18 exposure at 1,000 times that level.
19 Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in
20 drinking water. MCLs are enforceable standards. (UJ
21 Mechanical integrity: The absence of significant leakage within the injection tubing, casing, or
22 packer (known as internal mechanical integrity), or outside of the casing (known as external
23 mechanical integrity). (UJJiPAi1013d)
24 Mechanism: A means or series of events by which an activity within the hydraulic fracturing water
25 cycle has been observed to change the quality or quantity of drinking water resources.
26 Mechanism, potential: A means or series of events by which hydraulic fracturing activities could
27 logically or theoretically (for instance, based on modeling) change the quality or quantity of
28 drinking water resources but one that has not yet been observed.
29 Mechanism, suspected: A means or series of events by which hydraulic fracturing activities could
30 logically have resulted in an observed change in the quality or quantity of drinking water resources.
31 Available evidence may or may not be sufficient to determine if it is the only mechanism that caused
32 the observed change.
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1 Metropolitan combined statistical area: A core urban area of 50,000 or more people. [U.S.
2 Census Bureau. 2013]
3 Microaerophiles: Microorganisms that require small amounts of oxygen for energy production.
4 Microannuli: Very small channels that form in the cement and that may serve as pathways for fluid
5 migration to drinking water resources.
6 Micropolitan combined statistical area: An urban core of at least 10,000, but less than 50,000,
7 people. [U.S. Census Bureau. 2013]
8 Microseismic monitoring: A technique to track the propagation of a hydraulic fracture as it
9 advances through a formation. [Schlumberger. 2014]
10 Minimum risk level (MRL): An estimate of daily human exposure to a hazardous substance at or
11 below which the substance is unlikely to pose a measurable risk of harmful (adverse],
12 noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral] over a
13 specified time period (acute, intermediate, or chronic].
14 Mobility: The ratio of effective permeability to phase viscosity. The overall mobility is a sum of the
15 individual phase viscosities. Well productivity is directly proportional to the product of the mobility
16 and the layer thickness product (Schlumberger. 2014]
17 National Pollution Discharge Elimination System (NPDES): A national program under
18 Section 402 of the Clean Water Act for regulation of discharges of pollutants from point sources to
19 waters of the United States. Discharges are illegal unless authorized by an NPDES permit (U.S. EPA,
20 2013dl
21 National Secondary Drinking Water Regulations (NSDWR): Non-enforceable guidelines
22 regulating contaminants that may cause cosmetic effects (such as skin or tooth discoloration] or
23 aesthetic effects (such as taste, odor, or color] in drinking water (also referred to as secondary
24 standards]. (U.S. EPA. 2014b]
2 5 Natural gas: A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases in porous
26 formations beneath the earth's surface, often in association with petroleum. The principal
27 constituent of natural gas is methane. (Schlumberger. 2014]
28 Natural organic matter (NOM): Complex organic compounds that are formed from decomposing
29 plant animal and microbial material in soil and water. (U.S. EPA. 2013d]
3 0 Non-community water systems: Water systems that supply water to at least 2 5 of the same
31 people at least six months per year, but not year-round. (U.S. EPA. 2013c]
32 Octanol-water partition coefficient (Kow): A coefficient representing the ratio of the solubility of a
33 compound in octanol (a nonpolar solvent] to its solubility in water (a polar solvent]. The higher the
34 Kow, the more nonpolar the compound. Log Kow is generally used as a relative indicator of the
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1 tendency of an organic compound to adsorb to soil. Log Kow values are generally inversely related to
2 aqueous solubility and directly proportional to molecular weight. [U.S. EPA. 2013d]
3 Offset well: An existing wellbore close to a proposed well that provides information for planning
4 the proposed well. [Schlumberger. 2014]
5 Open hole completion: A well completion that has no casing or liner set across the reservoir
6 formation, allowing the produced fluids to flow directly into the wellbore. [Schlumberger. 2014]
7 Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased
8 cancer risk from a lifetime oral exposure to an agent. This estimate, usually expressed in units of
9 proportion (of a population] affected per mg/kg day, is generally reserved for use in the low dose
10 region of the dose response relationship, that is, for exposures corresponding to risks less than 1 in
11 100.
12 Organic carbon-water partition coefficient (Koc)'- A coefficient representing the amount of a
13 compound that is adsorbed to soil to the amount of a compound that is dissolved in water,
14 normalized to the total organic carbon content of the soil. The higher the Koc, the more likely a
15 compound is to adsorb to soils and sediments, and the less likely it is to migrate with water. Along
16 with log Kow, log Koc is used as a relative indicator of the tendency of an organic compound to adsorb
17 to soil.
18 Orphaned well: An inactive oil or gas well with no known (or financially solvent] owner.
19 Overburden: Material of any nature, consolidated or unconsolidated, that overlies a deposit of
20 useful minerals or ores. (U.S. EPA. 2013d]
21 Packer: A device that can be run into a wellbore with a smaller initial outside diameter that then
22 expands externally to seal the wellbore. (Schlumberger. 2014]
23 Pad fluid: a mixture of base fluid, typically water and additives designed to create, elongate, and
24 enlarge fractures along the natural channels of the formation when injected under high pressure.
2 5 Partial cementing: Cementing a casing string along only a portion of its length.
2 6 Passby flow: A prescribed, low-streamflow threshold below which withdrawals are not allowed.
27 fU.S. EPA. 2015dl
28 Peer review: A documented critical review of a specific major scientific and/or technical work
29 product Peer review is intended to uncover any technical problems or unresolved issues in a
3 0 preliminary or draft work product through the use of independent experts. This information is then
31 used to revise the draft so that the final work product will reflect sound technical information and
32 analyses. The process of peer review enhances the scientific or technical work product so that the
33 decision or position taken by the EPA, based on that product, has a sound and credible basis. (U.S.
34 EPA. 2013dl
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1 Perforation: The communication tunnel created from the casing or liner into the reservoir
2 formation through which injected fluids and oil or gas flows. Also refers to the process of creating
3 communication channels, e.g., via the use of a jet perforating gun.
4 Permeability: The ability of a material (e.g., rock or soil) to transmit fluid to move through pore
5 spaces.
6 Persistence: The length of time a compound stays in the environment, once introduced. A
7 compound may persist for less than a second or indefinitely.
8 Physicochemical properties: The inherent physical and chemical properties of a molecule such as
9 boiling point, density, physical state, molecular weight, vapor pressure, etc. These properties define
10 how a chemical interacts with its environment. (UiS._EPA1_2()13d)
1 1 Play: A set of oil or gas accumulations sharing similar geologic, geographic properties, such as
12 source rock, hydrocarbon type, and migration pathways.
13 Poisson's ratio: A ratio of transverse-to-axial (or latitudinal- to-longitudinal) strain; characterizes
14 how a material is deformed under pressure.
15 Polar molecule: A molecule with a slightly positive charge at one part of the molecule and a
16 slightly negative charge on another. The water molecule, H20, is an example of a polar molecule,
17 where the molecule is slightly positive around the hydrogen atoms and negative around the oxygen
18 atom.
19 Porosity: A measure of pore space, or the percentage of the material (e.g., rock or soil) volume that
20 can be occupied by oil, gas, or water.
2 1 Produced water: Water that flows from oil and gas wells.
22 Production casing: The deepest casing set and serves primarily as the conduit for producing fluids,
23 although when cemented to the wellbore, this casing can also serve to seal off other subsurface
24 zones including ground water resources. (
25 Production well: A well that is used to bring fluids (such as oil or gas) to the surface.
26 Production zone: Refers to the portion of a subsurface rock zone that contains oil or gas to be
27 extracted (sometimes using hydraulic fracturing). The production zone is sometimes referred to as
2 8 the target zone.
29 Proppant/propping agent: A granular substance (sand grains, aluminum pellets, or other
30 material) that is carried in suspension by the fracturing fluid and that serves to keep the cracks
31 open when fracturing fluid is withdrawn after a fracture treatment (U1S._EPAJ_2013d)
3 2 Protected ground water resource: The deepest aquifer that the state or other regulatory agency
3 3 requires to be protected from fluid migration through or along wellbores.
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1 Public water system source: The source of the surface or ground water used by a public water
2 system, including source wells, intakes, reservoirs, infiltration galleries, and springs.
3 Public water systems: Water systems that provide water for human consumption from surface or
4 ground water through pipes or other infrastructure to at least 15 service connections or serve an
5 average of at least 25 people for at least 60 days a year. [Safe Drinking Water Act, 2002]
6 Publicly owned treatment works (POTW): Any device or system used in the treatment (including
7 recycling and reclamation) of municipal sewage or industrial wastes of a liquid nature that is
8 owned by a state or municipality. This definition includes sewers, pipes, or other conveyances only
9 if they convey wastewater to a POTW providing treatment. fU.S. EPA. 2013dl
10 Quality assurance (QA): An integrated system of management activities involving planning,
11 implementation, documentation, assessment, reporting, and quality improvement to ensure that a
12 process, item, or service is of the type and quality needed and expected by the customer. [U.S. EPA.
13 2013d]
14 Quality assurance project plan (QAPP): A formal document describing in comprehensive detail
15 the necessary quality assurance procedures, quality control activities, and other technical activities
16 that need to be implemented to ensure that the results of the work performed will satisfy the stated
17 performance or acceptance criteria. [U.S. EPA. 2013d]
18 Quality management plan: A document that describes a quality system in terms of the
19 organizational structure, policy and procedures, functional responsibilities of management and
20 staff, lines of authority, and required interfaces for those planning, implementing, documenting, and
21 assessing all activities conducted. [U.S. EPA. 2013d]
2 2 Radioactive tracer log: A record of the presence of tracer material placed in or around the
23 borehole to measure fluid movement in injection wells. [Schiumberger. 2014]
24 Radionuclide: Radioactive particle, man-made or natural, with a distinct atomic weight number.
2 5 Emits radiation in the form of alpha or beta particles, or as gamma rays. Can have a long life as soil
26 or water pollutant Prolonged exposure to radionuclides increases the risk of cancer. [U.S. EPA,
28 Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude] of
29 a daily oral exposure to the human population (including sensitive subgroups] that is likely to be
30 without an appreciable risk of deleterious effects during a lifetime.
31 Reference value (RfV): An estimate of an exposure for a given duration to the human population
32 (including susceptible subgroups] that is likely to be without an appreciable risk of adverse health
33 effects over a lifetime. Reference value is a generic term not specific to a given route of exposure.
34 Relative permeability: A dimensionless property allowing for comparison of the different abilities
35 of fluids to flow in multiphase settings. If a single fluid is present, its relative permeability is equal
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1 to 1, but the presence of multiple fluids generally inhibits flow and decreases the relative
2 permeability.
3 Reservoir: A porous and permeable geologic formation where hydrocarbons collect under
4 pressure over geological time.
5 Residuals: The solids generated or retained during the treatment of waste water. [U.S. EPA. 2013d]
6 Safe Drinking Water Act (SDWA): The act designed to protect the nation's drinking water supply
7 by establishing national drinking water standards (maximum contaminant levels or specific
8 treatment techniques) and by regulating underground injection control wells. [U.S. EPA, 2013d]
9 Sandstone: A clastic sedimentary rock whose grains are predominantly sand sized. The term is
10 commonly used to imply consolidated sand or a rock made of predominantly quartz sand, although
11 sandstones often contain feldspar, rock fragments, mica, and numerous additional mineral grains
12 held together with silica or another type of cement The relatively high porosity and permeability of
13 sandstones make them good reservoir rocks. [Schlumberger. 2014]
14 Science Advisory Board (SAB): A federal advisory committee that provides a balanced, expert
15 assessment of scientific matters relevant to the EPA. An important function of the Science Advisory
16 Board is to review EPA's technical programs and research plans. [U.S. EPA. 2013d]
17 Service company: A company that assists well operators by providing specialty services, including
18 hydraulic fracturing. [U.S. EPA. 2013d]
19 Shale: A fine-grained, fissile, detrital sedimentary rock formed by consolidation of clay- and silt-
20 sized particles into thin, relatively impermeable layers. [Schlumberger. 2014]
21 Shale gas: Natural gas generated and stored in shale.
22 Shale oil: Oil present in unconventional oil reservoirs that are made up of shale.
23 Shut-in: The process of sealing off a well by either closing the valves at the wellhead, adownhole
24 safety valve, or a blowout preventer.
25 Slickwater: A type of fracturing fluid that consists mainly of water with a very low portion of
26 additives like polymers that serve as friction reducers to reduce friction loss when pumping the
27 fracturing fluid downhole. [Barati and Liang. 2014]
28 Solubility: The amount of mass of a compound that will dissolve in a unit volume of solution. [U.S.
29 EPA. 2013d]
3 0 Sorption: The general term used to describe the partitioning of a chemical between soil and water
31 and depends on the nature of the solids and the properties of the chemical.
32 Source water: Surface or ground water, or reused wastewater, acquired for use in hydraulic
33 fracturing. fU.S. EPA. 2013dl
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1 Spacer fluid: A fluid pumped before the cement to clean drilling mud out of the wellbore.
2 Spud (spud a well): To start the well drilling process by removing rock, dirt, and other
3 sedimentary material with the drill bit [U.S. EPA. 2013d]
4 Stages (frac stages): A single reservoir interval that is hydraulically stimulated in succession with
5 other intervals.
6 Stimulation: Refers to (1) injecting fluids to clear the well or pore spaces near the well of drilling
7 mud or other materials that create blockage and inhibit optimal production (i.e., matrix treatment)
8 and (2) injecting fluid to fracture the rock to optimize the production of oil or gas.
9 Stray gas: Refers to the phenomenon of natural gas (primarily methane) migrating into shallow
10 drinking water resources or to the surface.
11 Strings: An assembled length of steel pipe configured to suit a specific wellbore.
12 Subsurface formation: A mappable body of rock of distinctive rock type (s), including the rock's
13 pore volume (i.e., the void space within a formation that fluid flow can occur, as opposed to the bulk
14 volume which includes both pore and solid phase volume), with a unique stratigraphic position.
15 Surface casing: The shallowest cemented casing, with the widest diameter. Cemented surface
16 casing generally serves as an anchor for blowout protection equipment and to seal off drinking
17 water resources. (Baker, 1979]
18 Surface water: All water naturally open to the atmosphere (rivers, lakes, reservoirs, ponds,
19 streams, impoundments, seas, estuaries, etc.). (U.S. EPA. 2013d]
20 Surfactant: Used during the hydraulic fracturing process to decrease liquid surface tension and
21 improve fluid passage through the pipes. (U.S. EPA, 2013d]
22 Sustained casing pressure: Refers to cases when the pressure in any well annulus that is
2 3 measurable at the wellhead rebuilds after it is bled down, not caused solely by temperature
24 fluctuations or imposed by the operator. If the pressure is relieved by venting natural gas from the
25 annulus to the atmosphere, it will build up again once the annulus is closed (i.e., the pressure is
26 sustained). (Skjervenetal. 2011]
27 Technically recoverable resources: The volumes of oil and natural gas that could be produced
28 with current technology, regardless of oil and natural gas prices and production costs. (EIA, 2013]
29 Temperature log: A log of the temperature of the fluids in the borehole; a differential temperature
30 log records the rate of change in temperature with depth and is sensitive to very small changes.
31 (U.S. EPA. 2013d]
32 Tensile strength: The force per unit cross-sectional area required to pull a substance apart.
33 (Schlumberger, 2014]
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1 Thermogenic: Methane that is produced by high temperatures and pressures in deep formations
2 over geologic timescales. Thermogenic methane is formed by the thermal breakdown, or cracking,
3 of organic material that occurs during deep burial of sediment.
4 Tight oil: Oil found in relatively impermeable reservoir rock. (SchlumbergerJ_2fll4)
5 Total dissolved solids (TDS): The quantity of dissolved material in a given volume of water. Total
6 dissolved solids can include salts (e.g., sodium chloride), dissolved metals, radionuclides, and
7 dissolved organics. (li£^
8 Toxicity: The degree to which a substance or mixture of substances can harm humans or animals.
9 Acute toxicity involves harmful effects in an organism through a single or short-term exposure.
1 0 Chronic toxicity is the ability of a substance or mixture of substances to cause harmful effects over
11 an extended period, usually upon repeated or continuous exposure, sometimes lasting for the entire
12 life of the exposed organism. Subchronic toxicity is the ability of the substance to cause effects for
13 more than 1 year but less than the lifetime of the exposed organism. (UiS._EPA1_2()13d)
14 Tubing: The narrowest casing set within a completed well, either hung directly from the wellhead
15 or secured at its bottom using a packer. Tubing is not typically cemented in the well.
1 6 Unconventional reservoir: A reservoir characterized by lower permeability than conventional
17 reservoirs. It can be the same formation where hydrocarbons are formed and also serve as the
18 source for hydrocarbons that migrate and accumulate in conventional reservoirs. Unconventional
19 reservoirs can include methane-rich coalbeds and oil- and/or gas-bearing shales and tight sands.
20 Unconventional resource: An umbrella term for oil and natural gas that is produced by means
2 1 that do not meet the criteria for conventional production. What has qualified as unconventional at
22 any particular time is a complex function of resource characteristics, the available exploration and
23 production technologies, the economic environment, and the scale, frequency, and duration of
24 production from the resource. Perceptions of these factors inevitably change over time and often
25 differ among users of the term. At present, the term is used in reference to oil and gas resources
26 whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from
27 conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas,
28 fractured reservoirs, and tight gas sands are considered unconventional resources. (MiljjmbergiL
29 2014)
30 Underground Injection Control (UIC): The program under the Safe Drinking Water Act that
3 1 regulates the use of wells to pump fluids into the ground. (UJLER
32 Unsaturated zone: The soil zone above the water table that is only partially filled by water; also
33 referred to as the "vadose zone."
34 Vapor pressure: The force per unit area exerted by a vapor in an equilibrium state with its pure
35 solid, liquid, or solution at a given temperature. Vapor pressure is a measure of a substance's
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1 propensity to evaporate. Vapor pressure increases exponentially with an increase in temperature.
2 [U.S. EPA. 2013d]
3 Vertical well: A well in which the wellbore is vertical throughout its entire length, from the
4 wellhead at the surface to the production zone.
5 Viscosity: A measure of the internal friction of a fluid that provides resistance to shear within the
6 fluid, informally referred to as how "thick" a fluid is.
7 Volatile: Readily vaporizable at a relatively low temperature. [U.S. EPA. 2013d]
8 Volatilization: The process in which a chemical leaves the liquid phase and enters the gas phase.
9 Wastewater treatment: Chemical, biological, and mechanical procedures applied to an industrial
10 or municipal discharge or to any other sources of contaminated water in order to remove, reduce,
11 or neutralize contaminants. [U.S. EPA. 2013d]
12 Water availability: There is no standard definition for water availability, and it has not been
13 assessed recently at the national scale [U.S. GAP. 2014]. Instead, a number of water availability
14 indicators have been suggested [e.g.. Roy etal.. 2005]. Here, availability is most often used to
15 qualitatively refer to the amount of a location's water that could, currently or in the future, serve as
16 a source of drinking water [U.S. GAP, 2014], which is a function of water inputs to ahydrologic
17 system (e.g., rain, snowmelt, groundwater recharge] and water outputs from that system occurring
18 either naturally or through competing demands of users.
19 Water consumption: Water that is removed from the local hydrologic cycle following its use (e.g.,
20 via evaporation, transpiration, incorporation into products or crops, consumption by humans or
21 livestock], and is therefore unavailable to other water users (Maupinetal.. 2014].
22 Water intensity: The amount of water used per unit of energy obtained. (Nicotetal., 2014:
23 Laurenzi and Jersey, 2013]
24 Water reuse: Any hydraulic fracturing wastewater that is used to offset total fresh water
2 5 withdrawals for hydraulic fracturing, regardless of the level of treatment required.
26 Water use: Water withdrawn for a specific purpose, part or all of which may be returned to the
27 local hydrologic cycle.
28 Water withdrawal: Water removed from the ground or diverted from a surface-water source for
29 use. (Nicotetal.. 2014: Laurenzi and Jersey. 2013]
3 0 Well blowout: The uncontrolled flow of fluids out of a well.
31 Well communication: Refers to fractures intersecting abandoned or active (producing] offset
32 wells near the well that is being stimulated.
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1 Well logging: A continuous measurement of physical properties in or around the well with
2 electrically powered instruments to infer formation properties. Measurements may include
3 electrical properties (resistivity and conductivity), sonic properties, active and passive nuclear
4 measurements, measurements of the wellbore, pressure measurement, formation fluid sampling,
5 sidewall coring tools, and others. Measurements may be taken via a wireline, which is a wire or
6 cable that is used to deploy tools and instruments downhole and that transmits data to the surface.
7 [Adapted from Schlumberger. 2014]
8 Well operator: A company that controls and operates oil and gas wells. [U.S. EPA, 2013d]
9 Well pad: A temporary drilling site, usually constructed of local materials such as sand and gravel.
10 After the drilling operation is over, most of the pad is usually removed or plowed back into the
11 ground. fNYSDEC. 2011]
12 Wellbore: The drilled hole or borehole, including the open hole or uncased portion of the well.
13 Wet gas: Refers to natural gas that typically contains less than 85% methane along with ethane and
14 more complex hydrocarbons.
15 Wetting/nonwetting: The preferential attraction of a fluid to the surface. In typical reservoirs,
16 water preferentially wets the surface, and gas is nonwetting. [Adapted from Pake. 1978]
17 Workover: Refers to any maintenance activity performed on a well that involves ceasing
18 operations and removing the wellhead.
19 Young's modulus: A ratio of stress to strain that is a measure of the rigidity of a material.
J.2. References for Appendix J
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Maupin. MA: Kenny. IF: Hutson. SS: Lovelace. IK: Barber. NL: Linsey. KS. (2014). Estimated use of water in the
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U.S. EPA (U.S. Environmental Protection Agency). (2013d). Terminology services (TS): Terms and acronyms.
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This document is a draft for review purposes only and does not constitute Agency policy.
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