EPA-600-R-16-236Fa 

December 2016

www.epa.gov/hfstudy 

Hydraulic Fracturing for Oil and Gas: 

Impacts from the Hydraulic Fracturing 

Water Cycle on Drinking Water 

Resources in the United States

Office of Research and Development

Washington, DC

EPA-600-R-16-236Fa

December 2016

www.epa.gov/hfstudy

Hydraulic Fracturing for Oil and Gas: 

Impacts from the Hydraulic 

Fracturing Water Cycle on Drinking 

Water Resources in the United States 

Office of Research and Development

U.S. Environmental Protection Agency

Washington, DC 20460
This page is intentionally left blank.
i 

Disclaimer

This document has been reviewed in accordance with U.S. Environmental Protection Agency policy 

and approved for publication. Mention of trade names or commercial products does not constitute 

endorsement or recommendation for use.

Preferred citation: USEPA (U.S. Environmental Protection Agency). 2016. Hydraulic Fracturing for 

Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in 

the United States. Office of Research and Development, Washington, DC. EPA-600-R-16-236Fa. 
ii

Contents

List of Tables ..........................................................................................................................................................ix

List of Figures........................................................................................................................................................xii

List of Text Boxes.............................................................................................................................................. xvii

List of Acronyms/Abbreviations...................................................................................................................xix

Preface................................................................................................................................................................. xxiv

Authors, Contributors, and Reviewers.......................................................................................................xxv

Acknowledgements..........................................................................................................................................xxxi

Executive Summary ........................................................................................................................................ES-1

Drinking Water Resources in the United States.........................................................................................................ES-4

Hydraulic Fracturing for Oil and Gas in the United States.....................................................................................ES-5

Approach: The Hydraulic Fracturing Water Cycle ....................................................................................................ES-9

Water Acquisition................................................................................................................................................................. ES-12

Water Acquisition Conclusions ................................................................................................................................. ES-18

Chemical Mixing....................................................................................................................................................................ES-18

Chemical Mixing Conclusions.....................................................................................................................................ES-26

Well Injection .........................................................................................................................................................................ES-26

Well Injection Conclusions..........................................................................................................................................ES-32

Produced Water Handling ................................................................................................................................................ES-33

Produced Water Handling Conclusions.................................................................................................................ES-37

Wastewater Disposal and Reuse....................................................................................................................................ES-38

Wastewater Disposal and Reuse Conclusions ....................................................................................................ES-42

Chemicals in the Hydraulic Fracturing Water Cycle..............................................................................................ES-42

Chemicals in the Hydraulic Fracturing Water Cycle Conclusions .............................................................. ES-44

Data Gaps and Uncertainties............................................................................................................................................ES-44

Report Conclusions..............................................................................................................................................................ES-46

Chapter 1. Introduction.............................................................................................................................. 1-1

1.1 Background .......................................................................................................................................................................1-3

1.2 Goals .....................................................................................................................................................................................1-4

1.3 Scope ....................................................................................................................................................................................1-4

1.4 Approach ............................................................................................................................................................................1-9

1.4.1 EPA Hydraulic Fracturing Study Publications......................................................................................1-9

1.4.2 Literature and Data Search Strategy...................................................................................................... 1-10

1.4.3 Literature and Data Evaluation Strategy ............................................................................................. 1-11

1.4.4 Quality Assurance and Peer Review...................................................................................................... 1-11

1.5 Organization................................................................................................................................................................... 1-12

1.6 Intended Use.................................................................................................................................................................. 1-13
iii

Chapter 2. Drinking Water Resources in the United States........................................................... 2-1

Abstract.......................................................................................................................................................................................... 2-1

2.1 Introduction..................................................................................................................................................................... 2-3

2.2 Ground and Surface Water Resources .................................................................................................................. 2-3

2.2.1 Groundwater Resources ............................................................................................................................... 2-5

2.2.2 Surface Water Resources.............................................................................................................................. 2-7

2.3 Current Drinking Water Sources............................................................................................................................. 2-9

2.3.1 Factors Affecting How Water Becomes a Drinking Water Source ............................................ 2-11

2.4 Future Drinking Water Sources.............................................................................................................................2-13

2.5 Proximity of Drinking Water Resources to Hydraulic Fracturing Operations ..................................2-14

2.5.1 Lateral Distance between Public Water System Sources and Hydraulic Fracturing ........ 2-14

2.5.2 Vertical Distance between Drinking Water Resources and Hydraulic Fracturing ............ 2-16

2.6 Conclusions.....................................................................................................................................................................2-18

Chapter 3. Hydraulic Fracturing for Oil and Gas in the United States........................................ 3-1

Abstract...........................................................................................................................................................................................3-1

3.1 Introduction..................................................................................................................................................................... 3-3

3.2 What is Hydraulic Fracturing? ................................................................................................................................. 3-3

3.3 Hydraulic Fracturing and the Life of a Well...................................................................................................... 3-11

3.3.1 Site Preparation and Well Construction............................................................................................... 3-12

3.3.2 Hydraulic Fracturing ....................................................................................................................................3-18

3.3.3 Fluid Recovery, Handling, and Disposal or Reuse............................................................................3-23

3.3.4 Oil and Gas Production................................................................................................................................3-24

3.3.5 Site and Well Closure....................................................................................................................................3-25

3.4 How Widespread is Hydraulic Fracturing?....................................................................................................... 3-25

3.4.1 Number of Wells Fractured per Year .................................................................................................... 3-29

3.4.2 Hydraulic Fracturing Rates........................................................................................................................ 3-31

3.5 Trends and Outlook for the Future ...................................................................................................................... 3-32

3.5.1 Natural Gas ....................................................................................................................................................... 3-33

3.5.2 Oil.......................................................................................................................................................................... 3-36

3.6 Conclusions..................................................................................................................................................................... 3-38

Chapter 4. Water Acquisition ................................................................................................................... 4-1

Abstract...........................................................................................................................................................................................4-1

4.1 Introduction......................................................................................................................................................................4-3

4.2 Types of Water Used......................................................................................................................................................4-5

4.2.1 Source ....................................................................................................................................................................4-5

4.2.2 Quality....................................................................................................................................................................4-8

4.2.3 Provisioning ..................................................................................................................................................... 4-10

4.3 Water Use Per Well ..................................................................................................................................................... 4-10

4.3.1 Hydraulic Fracturing Water Use in the Life Cycle of Oil and Gas .............................................. 4-10

4.3.2 National Estimates and Variability in Water Use Per Well for Hydraulic Fracturing....... 4-11
iv

4.4 Hydraulic Fracturing Water Use and Consumption at the National, State, and County 

Scale.................................................................................................................................................................................................. 4-13

4.4.1 National and State Scale.............................................................................................................................. 4-13

4.4.2 County Scale ..................................................................................................................................................... 4-15

4.5 Potential for Impacts by Location......................................................................................................................... 4-21

4.5.1 Texas.................................................................................................................................................................... 4-21

4.5.2 Colorado and Wyoming............................................................................................................................... 4-31

4.5.3 Pennsylvania, West Virginia, and Ohio................................................................................................. 4-35

4.5.4 North Dakota and Montana ....................................................................................................................... 4-40

4.5.5 Arkansas and Louisiana .............................................................................................................................. 4-42

4.6 Chapter Synthesis ........................................................................................................................................................ 4-45

4.6.1 Major Findings ................................................................................................................................................ 4-45

4.6.2 Factors Affecting Frequency or Severity of Impacts....................................................................... 4-47

4.6.3 Uncertainties.................................................................................................................................................... 4-49

4.6.4 Conclusions....................................................................................................................................................... 4-50

Chapter 5. Chemical Mixing....................................................................................................................... 5-1

Abstract.......................................................................................................................................................................................... 5-1

5.1 Introduction..................................................................................................................................................................... 5-3

5.2 Chemical Mixing Process ............................................................................................................................................ 5-4

5.3 Overview of Hydraulic Fracturing Fluids ............................................................................................................ 5-8

5.3.1 Water-Based Fracturing Fluids................................................................................................................5-12

5.3.2 Alternative Fracturing Fluids....................................................................................................................5-13

5.3.3 Tracers................................................................................................................................................................5-14

5.3.4 Proppants ..........................................................................................................................................................5-16

5.3.5 Example Hydraulic Fracturing Fluids ...................................................................................................5-16

5.4 Frequency and Volume of Hydraulic Fracturing Chemical Use ...............................................................5-17

5.4.1 National Frequency of Use of Hydraulic Fracturing Chemicals .................................................5-20

5.4.2 Nationwide Oil versus Gas .........................................................................................................................5-24

5.4.3 State-by-State Frequency of Use of Hydraulic Fracturing Chemicals......................................5-25

5.4.4 Volume of Chemical Use..............................................................................................................................5-26

5.4.5 Chemical Composition of Hydraulic Fracturing Fluids and Additives ....................................5-28

5.5 Chemical Management and Spill Potential........................................................................................................5-31

5.5.1 Storage................................................................................................................................................................5-33

5.5.2 Hoses and Lines ..............................................................................................................................................5-37

5.5.3 Blender ...............................................................................................................................................................5-38

5.5.4 Manifold.............................................................................................................................................................5-39

5.5.5 High-Pressure Fracturing Pumps............................................................................................................5-39

5.5.6 Surface Wellhead for Fracture Stimulation ........................................................................................5-39

5.6 Overview of Chemical Spills Data .........................................................................................................................5-41

5.6.1 EPA Analysis of Spills Associated with Hydraulic Fracturing.....................................................5-41

5.6.2 Estimated Spill Rate and Other Spill Reports and Data.................................................................5-45

5.7 Spill Prevention, Containment, and Mitigation...............................................................................................5-46
v 

5.8 Fate and Transport of Spilled Chemicals...........................................................................................................5-47

5.8.1 Potential Paths ................................................................................................................................................5-49

5.8.2 Physicochemical Properties of Organic Hydraulic Fracturing Chemicals .............................5-50

5.8.3 Mobility of Organic Hydraulic Fracturing Chemicals .....................................................................5-52

5.8.4 Transformation Processes .........................................................................................................................5-56

5.8.5 Fate and Transport of Chemical Mixtures...........................................................................................5-57

5.8.6 Site and Environmental Conditions .......................................................................................................5-58

5.8.7

Fluid Spills

Peer-Reviewed Literature on the Fate and Transport of Hydraulic Fracturing

............................................................................................................................................................................ 5-58

5.8.8 Potential and Documented Fate and Transport of Documented Spills...................................5-59

5.8.9 Challenges with Unmonitored and Undetected Chemicals..........................................................5-62

5.9 Trends in the Use of Hydraulic Fracturing Chemicals .................................................................................5-63

5.10 Synthesis..........................................................................................................................................................................5-64

5.10.1 Summary of Findings ...................................................................................................................................5-64

5.10.2 Factors Affecting the Frequency or Severity of Impacts ...............................................................5-66

5.10.3 Uncertainties....................................................................................................................................................5-67

5.10.4 Conclusions.......................................................................................................................................................5-69

Chapter 6. Well Injection............................................................................................................................ 6-1

Abstract.......................................................................................................................................................................................... 6-1

6.1 Introduction..................................................................................................................................................................... 6-3

6.2 Fluid Migration Pathways Within and Along the Production Well .......................................................... 6-5

6.2.1 Overview of Well Construction.................................................................................................................. 6-5

6.2.2 Factors that can Affect Fluid Movement to Drinking Water Resources ................................. 6-16

6.3 Fluid Migration Associated with Induced Fractures within Subsurface Formations..................... 6-38

6.3.1 Overview of Subsurface Fracture Growth...........................................................................................6-40

6.3.2 Migration of Fluids through Pathways Related to Fractures/Formations............................6-44

6.4 Synthesis..........................................................................................................................................................................6-69

6.4.1 Summary of Findings ...................................................................................................................................6-70

6.4.3 Uncertainties....................................................................................................................................................6-75

6.4.4 Conclusions.......................................................................................................................................................6-77

Chapter 7. Produced Water Handling.................................................................................................... 7-1

Abstract.......................................................................................................................................................................................... 7-1

7.1 Introduction..................................................................................................................................................................... 7-3

7.1.1 Definitions........................................................................................................................................................... 7-4

7.2 Volume of Hydraulic Fracturing Flowback and Produced Water ............................................................. 7-5

7.2.1 Flowback of Injected Hydraulic Fracturing Fluid .............................................................................. 7-6

7.2.2 Produced Water Volumes............................................................................................................................. 7-8

7.3 Chemical Composition of Produced Water....................................................................................................... 7-11

7.3.1 Determination of Produced Water Composition.............................................................................. 7-11

7.3.2 Factors Influencing Produced Water Composition ......................................................................... 7-12

7.3.3 Produced Water Composition During the Flowback Period....................................................... 7-12

6.4.2 Factors Affecting Frequency or Severity of Impacts .......................................................................6-73
vi

7.3.4 Produced Water Composition ..................................................................................................................7-16

7.3.5 Spatial Trends in Produced Water Composition..............................................................................7-24

7.4 Spill and Release Impacts on Drinking Water Resources...........................................................................7-25

7.4.1 Produced Water Handling and Spill Potential...................................................................................7-25

7.4.2 Spills of Produced Water ............................................................................................................................7-26

7.5 Roadway Transport of Produced Water ............................................................................................................7-40

7.6 Synthesis..........................................................................................................................................................................7-41

7.6.1 Summary of Findings ...................................................................................................................................7-41

7.6.2 Factors Affecting the Frequency or Severity of Impacts ...............................................................7-43

7.6.3 Uncertainties....................................................................................................................................................7-43

7.6.4 Conclusions.......................................................................................................................................................7-44

Chapter 8. Wastewater Disposal and Reuse........................................................................................ 8-1

Abstract.......................................................................................................................................................................................... 8-1

8.1 Introduction..................................................................................................................................................................... 8-3

8.2 Volumes of Hydraulic Fracturing Wastewater.................................................................................................. 8-4

8.2.1 National Level Estimate ................................................................................................................................ 8-6

8.2.2 Regional/State Level Estimates................................................................................................................. 8-6

8.2.3 Estimation Methodologies and Challenges ........................................................................................... 8-8

8.3 Wastewater Characteristics ....................................................................................................................................8-11

8.3.1 Wastewater.......................................................................................................................................................8-11

8.3.2 Constituents in Residuals ...........................................................................................................................8-13

8.4 Wastewater Management Practices and Their Potential Impacts on Drinking Water 

Resources....................................................................................................................................................................................8-14

8.4.1 Underground Injection................................................................................................................................8-23

8.4.2 Publicly Owned Treatment Works .........................................................................................................8-27

8.4.3 Centralized Waste Treatment Facilities...............................................................................................8-28

8.4.4 Wastewater Reuse for Hydraulic Fracturing .....................................................................................8-35

8.4.5 Storage and Disposal Pits and Impoundments .................................................................................8-39

8.4.6 Other Management Practices and Issues.............................................................................................8-46

8.4.7 Management of Solid and Liquid Residuals........................................................................................8-51

8.5 Potential Impacts of Hydraulic Fracturing Wastewater Constituents on Drinking Water 

Resources....................................................................................................................................................................................8-54

8.5.1 Bromide, Iodide, and Chloride ..................................................................................................................8-54

8.5.2 Radionuclides ..................................................................................................................................................8-58

8.5.3 Metals..................................................................................................................................................................8-64

8.5.4 Volatile Organic Compounds.....................................................................................................................8-65

8.5.5 Semi-Volatile Organic Compounds.........................................................................................................8-65

8.5.6 Oil and Grease..................................................................................................................................................8-66

8.6 Synthesis..........................................................................................................................................................................8-66

8.6.1 Summary of Findings ...................................................................................................................................8-66

8.6.2 Factors Affecting the Frequency or Severity of Impacts ...............................................................8-70

8.6.3 Uncertainties....................................................................................................................................................8-73
vii

8.6.4 Conclusions.......................................................................................................................................................8-75

Chapter 9. Identification and Hazard Evaluation of Chemicals across the Hydraulic 

Fracturing Water Cycle.................................................................................................................................... 9-1

Abstract.......................................................................................................................................................................................... 9-1

9.1 Introduction..................................................................................................................................................................... 9-3

9.2 Overview: Hydraulic Fracturing and Potential Impacts on Human Health.......................................... 9-5

9.3 Identification of Chemicals Associated with the Hydraulic Fracturing Water Cycle........................ 9-8

9.3.1 Chemicals Used in Hydraulic Fracturing Fluids.................................................................................. 9-9

9.3.2 Chemicals Detected in Produced Water...............................................................................................9-11

9.4 Toxicological and Physicochemical Properties of Hydraulic Fracturing Chemicals ....................... 9-11

9.4.1 Reference Values (RfVs), Oral Slope Factors (OSFs), and Qualitative Cancer 

Classifications ...................................................................................................................................................................... 9-13

9.4.2 Estimating Toxicity Using Quantitative Structure Activity Relationship (QSAR) 

Modeling............................................................................................................................................................................... 9-17

9.4.3 Chemical Data Available from EPA’s Aggregated Computations Toxicology Resource 

(ACToR) Database.............................................................................................................................................................. 9-19

9.4.4 Additional Tools for Hazard Evaluation............................................................................................... 9-20

9.4.5 Physicochemical Properties ......................................................................................................................9-21

9.4.6 Summary of Available Toxicological and Physicochemical Information for Hydraulic 

Fracturing Chemicals........................................................................................................................................................9-21

9.5 Hazard Identification of Hydraulic Fracturing Chemicals..........................................................................9-22

9.5.1 Chemicals Used in Hydraulic Fracturing Fluids................................................................................9-23

9.5.2 Organic Chemicals in Produced Water .................................................................................................9-30

9.5.3 Inorganic Chemicals and TENORM in Produced Water ................................................................9-38

9.5.4 Organochlorine Pesticides and Polychlorinated Biphenyls (PCBs) in Produced Water . 9-44

9.5.5 Methane in Stray Gas....................................................................................................................................9-46

9.5.6 Disinfection Byproducts (DBPs) Formed from Wastewater Constituents............................9-47

9.5.7 Chemicals Detected in Multiple Stages of the Hydraulic Fracturing Water Cycle..............9-48

9.6 Hazard Evaluation of Selected Subsets of Hydraulic Fracturing Chemicals Using Multi-Criteria 

Decision Analysis (MCDA): Integrating Toxicity, Occurrence, and Physicochemical 

Data.................................................................................................................................................................................................. 9-51

9.6.1 Overview of the MCDA Framework for Hazard Evaluation......................................................... 9-53

9.6.2 Selection of Chemicals for Hazard Evaluation in the MCDA Framework............................... 9-53

9.6.3 Calculation of MCDA Scores....................................................................................................................... 9-57

9.6.4 Total Hazard Potential Score ....................................................................................................................9-58

9.6.5 MCDA Results ................................................................................................................................................. 9-59

9.6.6 Limitations and Uncertainty of the MCDA Framework.................................................................9-77

9.6.7 Application of the MCDA Framework for Preliminary Hazard Evaluation...........................9-78

9.7 Synthesis..........................................................................................................................................................................9-79

9.7.1 Summary of Findings ...................................................................................................................................9-79

9.7.2 Factors Affecting the Frequency or Severity of Impacts ...............................................................9-81

9.7.3 Uncertainties....................................................................................................................................................9-82

9.7.4 Conclusions.......................................................................................................................................................9-83
viii

9.8 Annex ................................................................................................................................................................................9-84

9.8.1 Calculation of Physicochemical Property Scores (MCDA Hazard Evaluation)....................9-84

9.8.2 Example of MCDA Score Calculation......................................................................................................9-85

Chapter 10. Synthesis ..............................................................................................................................10-1

Introduction...............................................................................................................................................................................10-3

10.1 Factors Affecting the Frequency or Severity of Impacts.............................................................................10-4

10.1.1 Water Acquisition..........................................................................................................................................10-4

10.1.2 Chemical Mixing and Produced Water Handling..............................................................................10-8

10.1.3 Well Injection................................................................................................................................................10-13

10.1.4 Wastewater Disposal and Reuse ..........................................................................................................10-21

10.1.5 Summary.........................................................................................................................................................10-23

10.2 Uncertainties and Data Gaps................................................................................................................................10-24

10.3 Use of this Assessment ...........................................................................................................................................10-28

Chapter 11. References ...........................................................................................................................11-1
ix

List of Tables

Table ES-1. Water use per hydraulically fractured well between January 2011 and February 2013.........ES-13

Table ES-2. Chemicals reported in 10% or more of disclosures in FracFocus 1.0. .......................................ES-20

Table ES-3. Available chronic oral reference values for hydraulic fracturing chemicals reported 

in 10% or more of disclosures in FracFocus 1.0. .........................................................................................................ES-43

Table 1-1. The five factors and accompanying criteria used to evaluate literature and data cited 

in this assessment. ....................................................................................................................................................................... 1-11

Table 2-1. Summary of drinking water sources in the United States in 2010.................................................... 2-10

Table 3-1. Estimated number of new wells hydraulically fractured nationally by year from 

various sources.............................................................................................................................................................................. 3-29

Table 4-1. Estimated proportions of hydraulic fracturing source water from surface water and 

groundwater..................................................................................................................................................................................... 4-6

Table 4-2. Percentage of injected water volume that comes from reused hydraulic fracturing 

wastewater in various states, basins, and plays................................................................................................................ 4-7

Table 4-3. Average annual hydraulic fracturing water use and consumption in 2011 and 2012 

compared to total annual water use and consumption in 2010, by county. ....................................................... 4-16

Table 4-4. Estimated brackish water use as a percentage of total hydraulic fracturing water use 

in the main hydraulic fracturing areas of Texas, 2011.................................................................................................4-23

Table 5-1. Examples of common additives, their function, and the most frequently used 

chemicals reported to FracFocus for these additives. .................................................................................................. 5-11

Table 5-2. Classes and specifically identified examples of tracers used in hydraulic fracturing 

fluids. .................................................................................................................................................................................................. 5-14

Table 5-3. Chemicals identified in the EPA FracFocus 1.0 project database in 10% or more 

disclosures, with the percent of disclosures for which each chemical is reported as an ingredient 

in an additive and the top four reported additives for which the chemical is used. ....................................... 5-21

Table 5-4. Example list of chemicals and chemical volumes used in hydraulic fracturing........................... 5-26

Table 5-5. Fluid and additive composition by maximum mass percent. .............................................................. 5-29

Table 5-6. Examples of typical hydraulic fracturing equipment and its function............................................. 5-32

Table 5-7. The 20 chemicals reported most frequently nationwide for hydraulic fracturing based 

on the EPA FracFocus 1.0 project database, with EPI SuiteTM physicochemical parameters where 

available, and estimated mean and median volumes of those chemicals where density was 

available............................................................................................................................................................................................ 5-54

Table 6-1. Failure rates of vertical wells in the Wattenberg field, Colorado....................................................... 6-20

Table 6-2. Results of studies of PA DEP violation data that examined mechanical integrity failure 

rates.................................................................................................................................................................................................... 6-30

Table 6-3. Comparing the approximate depth and thickness of selected U.S. shale gas plays and 

coalbed methane basins. ........................................................................................................................................................... 6-46

Table 6-4. Modeling parameters and scenarios investigated by Reagan et al. (2015)................................... 6-57

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............................................. 7-6
x 

Table 7-2. Additional short-, medium-, and long-term produced water estimates. .......................................... 7-7

Table 7-3. Flowback water characteristics for wells in unconventional reservoirs.......................................... 7-8

Table 7-4. Long-term produced water generation rates (gal/day per well) for wells in 

unconventional reservoirs. ........................................................................................................................................................ 7-9

Table 7-5. Compiled minimum and maximum concentrations for various geochemical 

constituents in produced water from shale gas, tight gas, and CBM produced water.................................... 7-17

Table 7-6. Examples of compounds identified in produced water that can be components of 

hydraulic fracturing fluid.......................................................................................................................................................... 7-22

Table 7-7. Summary of produced water release volumes........................................................................................... 7-37

Table 8-1. Estimated volumes (millions of gal) of wastewater based on state data for selected 

years and numbers of wells producing fluid. ..................................................................................................................... 8-9

Table 8-2. Estimated percentages of wastewater managed by practice and by state. ................................... 8-16

Table 8-3. Management practices for wastewater from unconventional oil and gas resources................ 8-17

Table 8-4. Distribution of active Class IID wells across the United States........................................................... 8-24

Table 8-5. Number, by state, of CWT facilities that have accepted or plan to accept wastewater 

from unconventional oil and gas activities........................................................................................................................ 8-30

Table 8-6. Estimated percentages of reuse of hydraulic fracturing wastewater. ............................................. 8-36

Table 9-1. Sources of selected RfVs, OSFs, and qualitative cancer classifications............................................ 9-15

Table 9-2. 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. 

Chronic oral RfVs, TOPKAT LOAEL estimates, and availability of ACToR data are shown when 

available............................................................................................................................................................................................ 9-25

Table 9-3. List of OSFs and qualitative cancer classifications available for all carcinogenic 

chemicals reported to FracFocus 1.0 from January 1, 2011 to February 28, 2013 in 10% or more 

disclosures....................................................................................................................................................................................... 9-28

Table 9-4. List of a subset of organic chemicals that have been detected in produced water, with 

respective chronic oral RfVs, TOPKAT LOAEL estimates, and availability of ACToR data shown 

when available............................................................................................................................................................................... 9-32

Table 9-5. List of OSFs and qualitative cancer classifications available for a subset of organic 

chemicals that have been reported in produced water. .............................................................................................. 9-36

Table 9-6. List of inorganics and TENORM reported in produced water, and respective chronic 

oral RfVs and OSFs when available....................................................................................................................................... 9-39

Table 9-7. List of qualitative cancer classifications available for inorganics and NORM that were 

reported in produced water. ................................................................................................................................................... 9-42

Table 9-8. List of organochlorine pesticides and PCBs that were reported in produced water, and 

their respective chronic oral RfVs, TOPKAT LOAEL estimates, and availability of data in EPA’s 

ACToR database. ........................................................................................................................................................................... 9-44

Table 9-9. List of OSFs and qualitative cancer classifications available for organochlorine 

pesticides reported in produced water............................................................................................................................... 9-46

Table 9-10. List of 45 chemicals on EPA’s list that were used in hydraulic fracturing fluids and 

detected in produced water and have an RfV or OSF available................................................................................ 9-48
xi

Table 9-11. Thresholds used for developing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score in this MCDA framework.................................................................................... 9-59

Table 9-12. Data on the selected subset of chemicals in hydraulic fracturing fluids used for input 

into a noncancer MCDA.............................................................................................................................................................. 9-62

Table 9-13. Data on the selected subset of chemicals in hydraulic fracturing fluids used for input 

into a cancer MCDA...................................................................................................................................................................... 9-70

Table 9-14. Data on the selected subset of chemicals detected in produced water used for input 

into a noncancer MCDA.............................................................................................................................................................. 9-72

Table 9-15. Data on the selected subset of chemicals detected in produced water used for input 

into a cancer MCDA...................................................................................................................................................................... 9-76

Table 10-1. Literature estimates of mechanical integrity failure rates resulting in contamination 

of groundwater or failure of all well barriers, potentially exposing the groundwater. ..............................10-15
xii

List of Figures

Figure ES-1. General timeline and summary of activities at a hydraulically fractured oil or gas 

production well. ............................................................................................................................................................................ES-6

Figure ES-2. Locations of approximately 275,000 wells that were drilled and likely hydraulically 

fractured between 2000 and 2013. ......................................................................................................................................ES-8

Figure ES-3. The five stages of the hydraulic fracturing water cycle. ................................................................. ES-10

Figure ES-4. Water budgets illustrative of hydraulic fracturing water management practices in 

the Marcellus Shale in the Susquehanna River Basin between approximately 2008 and 2013 and 

the Barnett Shale in Texas between approximately 2011 and 2013. ................................................................. ES-14

Figure ES-5. Generalized depiction of factors that influence whether spilled hydraulic fracturing 

fluids or additives reach drinking water resources, including spill characteristics, environmental 

fate and transport, and spill response activities. .........................................................................................................ES-25

Figure ES-6. Potential pathways for fluid movement in a cemented well. .......................................................ES-29

Figure ES-7. Examples of different subsurface environments in which hydraulic fracturing takes 

place. ...............................................................................................................................................................................................ES-31

Figure ES-8. Changes in wastewater management practices over time in the Marcellus Shale area 

of Pennsylvania. .........................................................................................................................................................................ES-41

Figure 1-1. Conceptualized view of the stages of the hydraulic fracturing water cycle. ................................. 1-5

Figure 2-1. Geographic variability in drinking water sources for public water systems. ............................. 2-10

Figure 2-2. The location of public water system sources having hydraulically fractured wells 

within 1 mile................................................................................................................................................................................... 2-15

Figure 2-3. Separation distance between drinking water resources and hydraulically fractured 

intervals in wells........................................................................................................................................................................... 2-17

Figure 3-1. Conceptual illustration of the types of oil and gas reservoirs and production wells 

used in hydraulic fracturing....................................................................................................................................................... 3-6

Figure 3-2. Major shale gas and oil plays in the contiguous United States............................................................ 3-8

Figure 3-3. Major tight gas plays in the contiguous United States. ........................................................................... 3-9

Figure 3-4. Coalbed methane fields and coal basins in the contiguous United States. ................................... 3-10

Figure 3-5. General timeline and summary of activities that take place during the preparation 

and through the operations of an oil or gas well site at which hydraulic fracturing is used....................... 3-12

Figure 3-6. Surface water being pumped for oil and gas development. ............................................................... 3-14

Figure 3-7. Illustration of well construction showing different types of casing and cement. ..................... 3-15

Figure 3-8. Sections of well casing ready for installation at a well site in Colorado........................................ 3-16

Figure 3-9. Aerial photograph of two hydraulic fracturing well sites and a service road in 

Springville Township, Pennsylvania. ................................................................................................................................... 3-17

Figure 3-10. Aerial photograph of hydraulic fracturing well sites near Williston, North Dakota. ............ 3-18

Figure 3-11. Well site with equipment (and pits in the background) in preparation for hydraulic 

fracturing in Troy, Pennsylvania............................................................................................................................................ 3-19

Figure 3-12. Three wellheads on a multi-well pad connected to the piping used for hydraulic 

fracturing injection. ..................................................................................................................................................................... 3-20
xiii

Figure 3-13. Water tanks (blue, foreground) lined up for hydraulic fracturing at a well site in 

central Arkansas. .......................................................................................................................................................................... 3-22

Figure 3-14. A pit on the site of a hydraulic fracturing operation in central Arkansas.................................. 3-23

Figure 3-15. Locations of the approximately 275,000 wells drilled and hydraulically fractured 

between 2000 and 2013............................................................................................................................................................ 3-26

Figure 3-16. Landsat photo showing hydraulic fracturing well sites near Frierson, Louisiana................. 3-27

Figure 3-17. Landsat photo showing hydraulic fracturing well sites near Pinedale, Wyoming................. 3-28

Figure 3-18. Primary U.S. energy production by source, 1950 to 2015................................................................ 3-32

Figure 3-19. U.S. production of oil (left) and gas (right) from hydraulically fractured wells from 

2000 to 2015. ................................................................................................................................................................................. 3-33

Figure 3-20. Location of horizontal wells that began producing oil or natural gas in 2000, 2005, 

and 2012........................................................................................................................................................................................... 3-34

Figure 3-21. Natural gas prices and drilling activity, United States, 1988 to 2015. ........................................ 3-35

Figure 3-22. Historic and projected natural gas production by source (trillion cubic feet). ....................... 3-35

Figure 3-23. Production from U.S. shale gas plays, 2000-2014................................................................................ 3-36

Figure 3-24. Crude oil prices and drilling activity, United States, 1988 to 2015. ............................................. 3-37

Figure 3-25. Historic and projected oil production by source (million barrels per day).............................. 3-37

Figure 3-26. Production from U.S. tight oil plays, 2000-2014................................................................................... 3-38

Figure 4-1. Median water volume per hydraulically fractured well nationally, expressed by well 

type and completion year. ........................................................................................................................................................ 4-12

Figure 4-2. Average annual hydraulic fracturing water use in 2011 and 2012 by county. .......................... 4-18

Figure 4-3. (a) Average annual hydraulic fracturing water use in 2011 and 2012 compared to 

total annual water use in 2010, by county, expressed as a percentage; (b) Average annual 

hydraulic fracturing water consumption in 2011 and 2012 compared to total annual water 

consumption in 2010, by county, expressed as a percentage. .................................................................................. 4-19

Figure 4-4. Locations of wells in the EPA FracFocus 1.0 project database, with respect to U.S. EIA 

shale plays and basins. ............................................................................................................................................................... 4-22

Figure 4-5. Major U.S. EIA shale plays and basins for Texas...................................................................................... 4-22

Figure 4-6. Average annual 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........................................................................................................................................................ 4-26

Figure 4-7. (a) Estimated annual surface water runoff from the USGS; (b) Reliance on 

groundwater as indicated by the ratio of groundwater pumping to stream flow and pumping. .............. 4-27

Figure 4-8. Percentage of weeks in drought between 2000 and 2013 by county. ........................................... 4-29

Figure 4-9. Major U.S. EIA shale plays and basins for Colorado and Wyoming. ................................................ 4-31

Figure 4-10. Major U.S. EIA shale plays and basins for Pennsylvania, West Virginia, and Ohio................. 4-35

Figure 4-11. Major U.S. EIA shale plays and basins for North Dakota and Montana....................................... 4-40

Figure 4-12. Major U.S. EIA shale plays and basins for Arkansas and Louisiana. ............................................. 4-43
xiv

Figure 5-1. Representative hydraulic fracturing site showing equipment used on-site during the 

chemical mixing process. ............................................................................................................................................................ 5-5

Figure 5-2. Overview of a chemical mixing process of the hydraulic fracturing water cycle........................ 5-6

Figure 5-3. Example hydraulic fracturing fluid decision tree for gas and oil wells. .......................................... 5-9

Figure 5-4. Example hydraulic fracturing fluids. ............................................................................................................ 5-17

Figure 5-5. Estimated median volumes for 74 chemicals reported in at least 100 disclosures in 

the FracFocus 1.0 project database for use in hydraulic fracturing from January 1, 2011 to 

February 28, 2013........................................................................................................................................................................ 5-28

Figure 5-6. Typical hydraulic fracturing equipment layout. ...................................................................................... 5-33

Figure 5-7. Metal and high-density polyethylene (HDPE) additive units. ........................................................... 5-35

Figure 5-8. Hoses and lines at a site in Arkansas............................................................................................................ 5-37

Figure 5-9. Multiple fracture heads. ..................................................................................................................................... 5-40

Figure 5-10. Percent distribution of the causes of spills. ............................................................................................ 5-42

Figure 5-11. Percent distribution of the sources of spills. .......................................................................................... 5-43

Figure 5-12. Distribution of the number of spills for different ranges of spill volumes. ............................... 5-43

Figure 5-13. Total volume of fluids spilled from different sources......................................................................... 5-44

Figure 5-14. Number of spills by environmental receptor......................................................................................... 5-45

Figure 5-15. Fate and transport schematic for a spilled hydraulic fracturing fluid......................................... 5-48

Figure 5-16. Histograms of physicochemical properties of organic chemicals used in the 

hydraulic fracturing process.................................................................................................................................................... 5-52

Figure 5-17. Fate and Transport Spill Example: Case 1. .............................................................................................. 5-60

Figure 5-18. Fate and Transport Spill Example: Case 2. .............................................................................................. 5-61

Figure 5-19 Fate and Transport Spill Example: Case 3. ............................................................................................... 5-62

Figure 6-1. Schematic cross-section of general types of oil and gas resources and the 

orientations of production wells used in hydraulic fracturing................................................................................... 6-6

Figure 6-2. Overview of well construction. ......................................................................................................................... 6-8

Figure 6-3. The various stresses to which the casing will be exposed. ................................................................. 6-10

Figure 6-4. Potential pathways for fluid movement in a cemented wellbore. ................................................... 6-17

Figure 6-5. Hydraulic fracture planes (represented as ovals), with respect to the principal 

subsurface compressive stresses: SV (the vertical stress), SH (the maximum horizontal stress), 

and Sh (the minimum horizontal stress). ........................................................................................................................... 6-41

Figure 6-6. Vertical distances in the subsurface separating drinking water resources and 

hydraulic fracturing depths. .................................................................................................................................................... 6-45

Figure 6-7. 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 

permeable fault. ............................................................................................................................................................................ 6-53

Figure 6-8. Induced fractures intersecting an offset well (in a production zone, as shown, or in 

overlying formations into which fracture growth may have occurred). .............................................................. 6-59
xv

Figure 6-9. Well communication (a frac hit)..................................................................................................................... 6-60

Figure 7-1. Generalized examples of produced water flow from five formations............................................ 7-10

Figure 7-2. Typical produced water volume for a coal bed methane well in the western United 

States. ................................................................................................................................................................................................. 7-11

Figure 7-3. TDS concentrations measured through time for injected fluid (at 0 days), and 

produced water samples from four Marcellus Shale gas wells in three southwest Pennsylvania 

counties............................................................................................................................................................................................. 7-13

Figure 7-4. Total radium and TDS concentrations measured through time for injected (day 0), 

and produced water samples Greene County, PA, Marcellus Shale gas wells. ................................................... 7-14

Figure 7-5. (a) Increasing chloride (Cl) and (b) decreasing DOC concentrations measured 

through time for samples from three Marcellus Shale gas wells on a single well pad in Greene 

County, PA........................................................................................................................................................................................ 7-15

Figure 7-6. Data on radium 226 (open symbols) and total radium (filled symbols) for Marcellus 

Shale wells (leftmost three columns) and other formations (rightmost three columns). ............................ 7-21

Figure 7-7. Produced water spill rates (spills per active wells) for North Dakota from 2001 to 

2015 (Appendix Section E.5)................................................................................................................................................... 7-31

Figure 7-8. Number of produced water releases in North Dakota by cause for 2014 and 2015 

(Appendix Section E.5)............................................................................................................................................................... 7-32

Figure 7-9. Distribution of spill causes in Oklahoma, pre-high volume hydraulic fracturing years 

of 1993-2003 (left) and in the EPA study of spills on production pads (right)................................................. 7-33

Figure 7-10. Distribution of spill sources in Oklahoma, pre-high volume hydraulic fracturing 

years of 1993-2003 (left) and in the EPA study of spills on production pads (right)..................................... 7-33

Figure 7-11. Volumes of 2015 North Dakota salt water releases by cause (leftmost 13 boxes in 

red), and all causes (last box in blue). ................................................................................................................................. 7-34

Figure 7-12. Volumes of produced water spills reported by the EPA for 2006 to 2012 by cause 

(the five left most boxes in red), source (the second five boxes in yellow), and all spills (blue)............... 7-35

Figure 7-13. Median, mean, and maximum produced water spill volumes for North Dakota from 

2001 to 2015. ................................................................................................................................................................................. 7-36

Figure 7-14. Schematic view of transport processes occurring during releases of produced 

water. ................................................................................................................................................................................................. 7-40

Figure 8-1. Wastewater (i.e., produced water and fracturing fluid waste) and produced gas 

volumes from unconventional (as defined by PA DEP) wells in Pennsylvania from January 2010 

through June 2016. ........................................................................................................................................................................ 8-5

Figure 8-2. Wastewater quantities in the western United States (billions of gal per year). .......................... 8-7

Figure 8-3. Schematic of wastewater management strategies. ................................................................................ 8-14

Figure 8-4. Percentages of total unconventional wastewater (as defined by PA DEP) managed via 

various practices for the second half of 2009 through the first half of 2014. .................................................... 8-21

Figure 8-5. Management of wastewater in Colorado in regions where hydraulic fracturing is 

being performed. .......................................................................................................................................................................... 8-22

Figure 8-6. Oil and gas wastewater volumes discharged to POTWs from 2001-2011 in the 

Marcellus Shale. (“Conventional” is indicated by the authors as non-Marcellus wells and 

described as vertically drilled to shallower depths in more porous formations.)........................................... 8-27
xvi

Figure 8-7. Map showing Pennsylvania surface water designated as potable water supplies and 

upstream CWTs. ............................................................................................................................................................................ 8-32

Figure 8-8. Lined evaporation pit in the Battle Creek Field (Montana)................................................................ 8-42

Figure 9-1. Fate and transport schematic for a hydraulic fracturing-related spill or release....................... 9-6

Figure 9-2. Percentage of hydraulic fracturing-related chemicals (out of 1,606 total) with at least 

one data point in each ACToR data class............................................................................................................................ 9-20

Figure 9-3. Overall representation of the selected toxicological, physicochemical, and occurrence 

data available for the 1,606 hydraulic fracturing-related chemicals identified by the EPA. ....................... 9-22

Figure 9-4. Availability of toxicity data (chronic oral RfVs/OSFs, TOPKAT LOAEL estimates, and 

relevant data on ACToR) for subsets of chemicals used at various frequencies in hydraulic 

fracturing fluids, as determined based on the number of disclosures in the EPA FracFocus 1.0 

project database............................................................................................................................................................................ 9-29

Figure 9-5. Overview of the MCDA framework for hazard evaluation. ................................................................. 9-53

Figure 9-6. The subsets of chemicals selected for hazard evaluation using the noncancer MCDA 

framework included 42 chemicals used in hydraulic fracturing fluids and 29 chemicals detected 

in produced water........................................................................................................................................................................ 9-55

Figure 9-7. The subsets of chemicals selected for hazard evaluation using the cancer MCDA 

framework included 10 chemicals used in hydraulic fracturing fluids, and 7 chemicals detected 

in produced water........................................................................................................................................................................ 9-56

Figure 9-8. Noncancer MCDA results for 42 chemicals used in hydraulic fracturing fluids 

(national analysis), showing the Toxicity Score, Occurrence Score, and Physicochemical 

Properties Score for each chemical. ..................................................................................................................................... 9-65

Figure 9-9. Noncancer MCDA results for 36 chemicals used in hydraulic fracturing fluids in 

Texas (state-specific analysis), showing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score for each chemical................................................................................................... 9-66

Figure 9-10. Noncancer MCDA results for 20 chemicals used in hydraulic fracturing fluids in 

Pennsylvania (state-specific analysis), showing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score for each chemical................................................................................................... 9-67

Figure 9-11. Noncancer MCDA results for 21 chemicals used in hydraulic fracturing fluids in 

North Dakota (state-specific analysis), showing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score for each chemical................................................................................................... 9-68

Figure 9-12. Cancer MCDA results for 10 chemicals used in hydraulic fracturing fluids, showing 

the Toxicity Score, Occurrence Score, and Physicochemical Properties Score for each chemical. ........... 9-71

Figure 9-13. Noncancer MCDA results for a subset of 29 chemicals detected in produced water, 

showing the Toxicity Score, Occurrence Score, and Physicochemical Properties Score for each 

chemical............................................................................................................................................................................................ 9-74

Figure 9-14. Cancer MCDA results for 7 chemicals detected in produced water, showing the 

Toxicity Score, Occurrence Score, and Physicochemical Properties Score for each chemical. ................... 9-77

Figure 10-1. Water budgets representative of practices in (top) the Marcellus Shale in the 

Susquehanna River Basin in Pennsylvania and (bottom) the Barnett Shale in Texas....................................10-7

Figure 10-2. Fate and transport schematic for a spill of chemicals, hydraulic fracturing fluid, or 

produced water. .........................................................................................................................................................................10-11

Figure 10-3. Separation in measured depth between drinking water resources and hydraulically 

fractured intervals in wells. ..................................................................................................................................................10-20
xvii

List of Text Boxes

Text Box ES-1. Drinking Water Resources.........................................................................................................................ES-5

Text Box ES-2. Hydraulically Fractured Oil and Gas Production Wells.................................................................ES-7

Text Box ES-3. The EPA’s Study of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on 

Drinking Water Resources. .....................................................................................................................................................ES-11

Text Box ES-4. FracFocus Chemical Disclosure Registry..........................................................................................ES-13

Text Box ES-5. County-Level Water Use for Hydraulic Fracturing.......................................................................ES-16

Text Box ES-6. Examples of Hydraulic Fracturing Fluids.........................................................................................ES-19

Text Box ES-7. Chemical Mixing Equipment. .................................................................................................................ES-23

Text Box ES-8. Fracture Growth..........................................................................................................................................ES-28

Text Box ES-9. Produced Water from Hydraulically Fractured Oil and Gas Production Wells................ES-34

Text Box ES-10. On-Site Storage of Produced Water. ................................................................................................ES-36

Text Box ES-11. Hydraulic Fracturing Wastewater Management. .......................................................................ES-39

Text Box 1-1. Regulatory Protection for Drinking Water Resources. ...................................................................... 1-7

Text Box 2-1. The Hydrologic Cycle........................................................................................................................................ 2-4

Text Box 2-2. El Paso’s Use of Higher Salinity Water for Drinking Water............................................................ 2-11

Text Box 3-1. Hydraulic Fracturing: Not New, but Different and Still Changing................................................. 3-4

Text Box 3-2. “Conventional” Versus “Unconventional.”............................................................................................... 3-7

Text Box 4-1. Using the EPA’s FracFocus 1.0 Project Database to Estimate Water Use for 

Hydraulic Fracturing................................................................................................................................................................... 4-20

Text Box 4-2. Hydraulic Fracturing Water Use as a Percentage of Water Availability Estimates. ............ 4-25

Text Box 4-3. Case Study: Water Profile of the Eagle Ford Play, Texas................................................................. 4-30

Text Box 4-4. Case Study: Impact of Water Acquisition for Hydraulic Fracturing on Local Water 

Availability in the Upper Colorado River Basin............................................................................................................... 4-34

Text Box 4-5. Case Study: Impact of Water Acquisition for Hydraulic Fracturing on Local Water 

Availability in the Susquehanna River Basin.................................................................................................................... 4-38

Text Box 5-1. The FracFocus Registry and EPA FracFocus Report......................................................................... 5-18

Text Box 5-2. Confidential Business Information (CBI)............................................................................................... 5-20

Text Box 5-3. Spills from Storage Units............................................................................................................................... 5-34

Text Box 5-4. Spill from Additive (Crosslinker) Storage Tote................................................................................... 5-34

Text Box 5-5. Spill of Acid from Storage Container........................................................................................................ 5-36

Text Box 5-6. Spill of Gel Slurry during Mixing................................................................................................................ 5-36

Text Box 5-7. Spill of Hydraulic Fracturing Fluid from Blender............................................................................... 5-38

Text Box 5-8. Spill of Fluid from Fracture Pump............................................................................................................. 5-39

Text Box 5-9. Spill from Frac Head Failure........................................................................................................................ 5-40
xviii

Text Box 5-10. EPA Review of State and Industry Spill Data: Characterization of Hydraulic 

Fracturing-Related Spills........................................................................................................................................................... 5-41

Text Box 6-1. The Well File Review. ....................................................................................................................................... 6-9

Text Box 6-2. Dimock, Pennsylvania. ................................................................................................................................... 6-11

Text Box 6-3. Stray Gas Migration......................................................................................................................................... 6-23

Text Box 6-4. Parker County, Texas...................................................................................................................................... 6-26

Text Box 6-5. Pavillion, Wyoming.......................................................................................................................................... 6-47

Text Box 6-6. Monitoring at the Greene County, Pennsylvania, Hydraulic Fracturing Test Site................ 6-54

Text Box 6-7. Well Communication at a Horizontal Well near Innisfail, Alberta, Canada............................. 6-63

Text Box 8-1. Temporal Trends in Wastewater Management – Experience of Pennsylvania..................... 8-19

Text Box 8-2. Regulations Affecting Wastewater Management. .............................................................................. 8-21

Text Box 8-3. Wastewater Treatment Processes. ........................................................................................................... 8-28

Text Box 9-1. Applying Toxicological Data for Human Health Risk Assessment. ............................................... 9-5

Text Box 9-2. The EPA’s List of Chemicals Identified in Hydraulic Fracturing Fluids and/or 

Produced Water. ............................................................................................................................................................................. 9-9

Text Box 9-3. Toxicity Values for Hydraulic Fracturing-Related Chemicals. ...................................................... 9-12

Text Box 10-1. Hydraulic Fracturing and Groundwater Quality Monitoring in California. .......................10-25

Text Box 10-2. Causal Assessment and Hydraulic Fracturing Water Cycle Activities. ................................10-27
xix

List of Acronyms/Abbreviations

Acronym Definition

2BE 2-butoxyethanol

ACToR Aggregated Computational Toxicology Resource database

AME Acton Mickelson Environmental, Inc.

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

CDC Centers for Disease Control and Prevention 

CDWR Colorado Division of Water Resources

CFR Code of Federal Regulations

CICAD Concise International Chemical Assessment Document

CM chemical mixing

CMV commercial motor vehicle

COGCC Colorado Oil and Gas Conservation Commission

COWDF Commercial Oil Field Waste Disposal Facilities

CWA Clean Water Act

CWCB Colorado Water Conservation Board

CWT centralized waste treatment

CWTF centralized water treatment facility

DBNM dibromochloronitromethane

DBP disinfection byproduct 

DecaBDE decabromodipheyl ether 

DfE Design for the Environment

DI Drilling Info, Inc.

DMA dimethylamine

DMR Discharge Monitoring Report

DNR Department of Natural Resources

DO dissolved oxygen

DOC dissolved organic carbon
xx

DOE U.S. Department of Energy

DOGGR California Department of Conservation’s Division of Oil, Gas & Geothermal Resources

DOI U.S. Department of the Interior

DOJ U.S. Department of Justice

DOT U.S. Department of Transportation

DRB Delaware River Basin

DRO diesel range organics

DWSHA Drinking Water Standards and Health Advisories

ECHA European Chemicals Agency

EERC Energy and Environmental Research Center, University of North Dakota

EIA U.S. Energy Information Administration

EPA U.S. Environmental Protection Agency

EPA OW U.S. Environmental Protection Agency, Office of Water

EPI estimation programs interface

EPWU El Paso Water Utility

ERCB Energy Resource Conservation Board

ERG Eastern Research Group

ESN Environmental Services Network

ESOD erythrocyte Cu, Zn-superoxide dismutase

EWI Energy Water Initiative

FDA U.S. Food and Drug Administration

FOIA Freedom of Information Act

FRS fluids recovery services

GES Groundwater & Environmental Services, Inc.

GHGRP Greenhouse Gas Reporting Program

GNB Government of New Brunswick

GRAS generally recognized as safe

GRO gasoline range organics

GTI Gas Technology Institute

GWPC Ground Water Protection Council

HBCD hexabromocyclododecane

HDPE high-density polyethylene

HF hydraulic fracturing

HHBP Human Health Benchmarks for Pesticides

HISA Highly Influential Scientific Assessment

HPG hydroxypropylguar

HTS high throughput screening

HUC hydrological unit code

IAEA International Atomic Energy Agency

IARC International Agency for Research on Cancer

IHS Information Handling Services

IOGCC Interstate Oil and Gas Compact Commission
xxi

IPCC

IPCS

IRIS

IUPAC

KWO

LDEQ

LOAEL

MCDA

MCL

MCLG

MCOR

MGD

MIT

MMCF 

MRL 

MSC

MT GWIC

MTBE 

MVR

NAS

NDDMR

NDDOH

NDMA

NDPES

NDSWC

NETL

NGO

NIH

NM OCD

NM OSE

NOAEL

NORM

NPC

NPDES

NPDWR

NRC

NTP

NYSDEC

O&G

ODNR

DMRM

OECD

Intergovernmental Panel on Climate Change

International Programme on Chemical Safety

Integrated Risk Information System

International Union of Pure and Applied Chemistry

Kansas Water Office

Louisiana Department of Environmental Quality

lowest observed adverse effect level

multicriteria decision analysis

maximum contaminant level

maximum containment level goal

Marcellus Center for Outreach and Research

million gallons per day

mechanical integrity test

million cubic feet

minimum risk level 

Marcellus Shale Coalition 

Montana Ground Water Information Center

methyl tert-butyl ether

mechanical vapor recompression

National Academy of Sciences

North Dakota Department of Mineral Resources

North Dakota Department of Health

N-nitrosodimethylamine

National Pollution Discharge Elimination System

North Dakota State Water Commission

National Energy Technology Laboratory

non-governmental organization

National Institutes of Health

New Mexico Oil Conservation Division

New Mexico Office of the State Engineer

no observed adverse effect level

naturally occurring radioactive material

National Petroleum Council

National Pollution Discharge Elimination System

National Primary Drinking Water Regulations

National Resource Council

U.S. National Toxicology Program

New York State Department of Environmental Conservation

oil and gas

Ohio Department of Natural Resources

Division of Mineral Resources Management

The Organisation for Economic Co-operation and Development
xxii

OEPA Ohio Environmental Protection Agency

OMB Office of Management and Budget

ORB Ohio River Basin

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

PAH polycyclic aromatic hydrocarbon

PCB polychlorinated biphenyl

PFBC Pennsylvania Fish and Boat Commission

PDL positive determination letter

PMF Positive Matrix Factorization

PMN pre-manufacturing notices

POD point-of-departure

POTW publicly owned treatment work

PPRTV provisional peer-reviewed toxicity value

PVC polyvinyl chloride

PWS public water system

PWSA Pittsburgh Water and Sewer Authority

QA quality assurance

QAPP quality assurance project plan

QC quality control

QSAR Quantitative Structure Activity Relationship

RAHC reasonably anticipated to be a human carcinogen

RBC red blood cells

RfD reference dose

RfV reference value

RO reverse osmosis

SAB Science Advisory Board

SAIC Science Applications International Corporation

SAR sodium adsorption ratio

SCN thiocyanates

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

SPE Society of Petroleum Engineers
xxiii

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

TBA tert-butyl alcohol

TDI tolerable daily intake

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

TOPKAT Toxicity Prediction by Komputer Assisted Technology

TPH total petroleum hydrocarbons

TPHWG Total Petroleum Hydrocarbon Criteria Working Group

TSS total suspended solids

TTC Threshold of Toxicological Concern

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

USGAO U.S. Government Accountability Office

USGS U.S. Geological Survey

UWS Universal Well Services

VES viscoelastic surfactant

VOC volatile organic compounds

WAWSA Western Area Water Supply Authority

WFR Well File Review

WHO World Health Organization

WOE weight of evidence

WRF Water Research Foundation

WVDEP West Virginia Department of Environmental Protection

WWTP wastewater treatment plant

WYOGCC Wyoming Oil and Gas Conservation Commission
xxiv

Preface 

Hydraulic fracturing is a technique used to increase oil and gas production from underground oilor gas-bearing rock formations. Since the mid-2000s, the combination of hydraulic fracturing and 

directional drilling has become widespread, raising concerns about the potential impacts of 

hydraulic fracturing on drinking water resources. This concern is the focus of this report. 

In 2010, the U.S. Environmental Protection Agency (EPA) initiated a study of the potential impacts 

of hydraulic fracturing activities on drinking water resources. The EPA defined the scope of its 

study to focus on the acquisition, use, disposal, and reuse of water used for hydraulic fracturing—

what we call the hydraulic fracturing water cycle. This was done in recognition that concerns raised 

about potential impacts were not limited to the relatively short-term act of fracturing rock, but can 

include impacts related to other activities associated with hydraulic fracturing.

The EPA’s study included the development of multiple research projects using the following 

research approaches: the analysis of existing data, scenario and modeling evaluations, laboratory 

studies, toxicological assessments, and five case studies. Throughout the study, the EPA engaged 

with stakeholders, including industry, the states, tribal nations, academia, and others, for input on 

the scope, approach, and initial results. To date, the study has resulted in the publication of multiple 

peer-reviewed scientific products, including 13 EPA technical reports and 14 journal articles.

This report represents the capstone product of the EPA’s hydraulic fracturing drinking water study.

It captures the state-of-the-science concerning drinking water impacts from activities in the 

hydraulic fracturing activities water cycle and integrates the results of the EPA’s study of the 

subject with approximately 1,200 other publications and sources of information. The goals of this 

report were to assess the potential for activities in the hydraulic fracturing water cycle to impact 

the quality or quantity of drinking water resources and to identify factors that affect the frequency 

or severity of those impacts. 

This report is a science document and does not present or evaluate policy options or make policy 

recommendations. A draft of this report was reviewed by the EPA’s independent Science Advisory 

Board (SAB). Reflecting the complexity of the subject, the expert ad hoc panel formed by the SAB 

was the largest ever convened for the review of a scientific product. Combined with over 100,000 

comments submitted by members of the public, SAB comments helped the EPA to refine, clarify, 

and better support the final conclusions presented in this report.

The release of this final assessment report marks the completion of the EPA’s hydraulic fracturing 

drinking water study. The study has already prompted increased dialogue among industry, the 

states, tribal nations, the public, and others concerning how drinking water resources can be better 

protected in areas where hydraulic fracturing is occurring or being considered. However, there are 

data gaps and uncertainties limiting our understanding of the impacts of hydraulic fracturing 

activities on drinking water resources. As additional data become available, and with continued 

dialogue among stakeholders, our understanding of the potential impacts of hydraulic fracturing on 

drinking water resources will improve.
xxv

Authors, Contributors, and Reviewers 

Authors of the Final Assessment (EPA 600-R-16-236Fa and EPA 600-R-16-236Fb) 

Susan Burden, USEPA-Office of Research and Development, Washington, DC

Megan M. Fleming, USEPA-Office of Research and Development, Washington, DC

Jeffrey Frithsen, USEPA-Office of Research and Development, Washington, DC

Linda Hills, The Cadmus Group, Inc., Helena, MT

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

Caroline E. Ridley, USEPA-Office of Research and Development, Washington, DC

Shari Ring, The Cadmus Group, Inc., Arlington, VA

Sarah Solomon, Student Services Contractor, USEPA-Office of Research and Development, Washington, DC

John Stanek, USEPA-Office of Research and Development, Research Triangle Park, NC

Mary Ellen Tuccillo, The Cadmus Group, Inc., Waltham, MA

Jim Weaver, USEPA-Office of Research and Development, Ada, OK

Anna Weber, The Cadmus Group, Inc., Arlington, VA

Nathan Wiser, USEPA-Office of Research and Development, Denver, CO

Erin Yost, USEPA-Office of Research and Development, Research Triangle Park, NC 

Authors of the June 2015 External Review Draft (EPA-600-R-15-047a) 

William Bates, USEPA-Office of Water, Washington, DC

Glen Boyd, The Cadmus Group, Inc., Seattle, WA

Jeanne Briskin, USEPA-Office of Research and Development, Washington, DC

Lyle Burgoon, USEPA-Office of Research and Development, Research Triangle Park, NC; currently with

US-ACOE, Research Triangle Park, NC

Susan Burden, USEPA-Office of Research and Development, Washington, DC

Christopher M. Clark, USEPA-Office of Research and Development, Washington, DC

Maryam Cluff, Student Services Contractor, USEPA-Office of Research and Development, Washington, DC

Rebecca Daiss, USEPA-Office of Research and Development, Washington, DC

Jill Dean, USEPA-Office of Water, Washington, DC

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

Linda Hills, The Cadmus Group, Inc., Helena, MT

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
xxvi

Claudia Meza-Cuadra, Student Services Contractor, USEPA-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, USEPA-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

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; currently with the US

State Department, Washington, DC

Liabeth Yohannes, Student Services Contractor, USEPA-Office of Research and Development, 

Washington, DC

Erin Yost, USEPA-Office of Research and Development, Research Triangle Park, NC

Contributors

Maryam Akhavan, The Cadmus Group, Inc., Arlington, VA

Natalie Auer, The Cadmus Group, Inc., Arlington, VA

Kevin Blackwood, Student Services Contractor, USEPA-Office of Research and Development, Ada, OK

Alison Cullity, The Cadmus Group, Rollinsford, NH

Rob Dewoskin, USEPA-Office of Research and Development, Research Triangle Park, NC 

Krissy Downing, The Cadmus Group, Inc., Seattle, WA

Christopher Impellitteri, USEPA-Office of Research and Development, Cincinnati, OH 

Will Jobs, The Cadmus Group, Inc., Waltham, MA

Richard Judson, USEPA-Office of Research and Development, Research Triangle Park, NC 

Erina Keefe, The Cadmus Group, Waltham, MA

Ava Lazor, The Cadmus Group, Inc., Arlington, VA

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, USEPA-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, USEPA-Office of Research and Development, 

Ada, OK

Jesse Pritts, USEPA-Office of Water, Washington, DC

Ann Richard, USEPA-Office of Research and Development, Research Triangle Park, NC

Ana Rosner, The Cadmus Group, Inc., Waltham, MA

Susan Sharkey, USEPA-Office of Research and Development, Washington, DC

Jessica Wilhelm, Student Services Contractor, USEPA-Office of Research and Development, Ada, OK

Holly Wooten, The Cadmus Group, Inc., Arlington, VA

Jie Xu, Student Services Contractor, USEPA-Office of Research and Development, Ada, OK
xxvii

U.S. Environmental Protection Agency Science Advisory Board

Joseph Arvai, University of Michigan, Ann Arbor, MI

Kiros T. Berhane, University of Southern California, Los Angeles, CA

Sylvie M. Brouder, Purdue University, West Lafayette, IN

Ingrid Burke, University of Wyoming, Laramie, WY

Thomas Carpenter, Designated Federal Officer, U.S. Environmental Protection Agency, Science Advisory 

Board, Washington, DC 

Ana V. Diez Roux, Drexel University, Philadelphia, PA

Michael Dourson, University of Cincinnati, Cincinnati, OH

Joel J. Ducoste, North Carolina State University, Raleigh, NC

David A. Dzombak, Carnegie Mellon Unviersity, Pittsburgh, PA

Elaine M. Faustman, University of Washington, Seattle, WA

Susan P. Felter, Proctor & Gamble, Mason, OH 

R. William Field, University of Iowa, Iowa City, IA

H. Christopher Frey, North Carolina State University, Raleigh, NC

Steven Hamburg, Environmental Defense Fund, Boston, MA

Cynthia M. Harris, Florida A&M University, Tallahassee, FL

Robert J. Johnston, Clark University, Worcester, MA

Kimberly L. Jones, Howard University, Washington, DC

Catherine J. Karr, University of Washington, Seattle, WA

Madhu Khanna, University of Illinois at Urbana-Champaign, Urbana, IL

Francine Laden, Brigham and Women’s Hospital and Harvard Medical School, Boston, MA

Lois Lehman-McKeeman, Bristol-Myers Squibb, Princeton, NJ

Robert E. Mace, Texas Water Development Board, Austin, TX

Mary Sue Marty, The Dow Chemical Company, Midland, MI

Denise Mauzerall, Princeton University, Princeton, NJ

Kristina D. Mena, University of Texas Health Science Center at Houston, El Paso, TX

Surabi Menon, ClimateWorks Foundation, San Francisco, CA

James R. Mihelcic, University of South Florida, Tampa, FL

Keith H. Moo-Young, Washington State University, Tri-Cities, Richland, WA

Kari Nadeau, Stanford University School of Medicine, Stanford, CA

James Opaluch, University of Rhode Island, Kingston, RI

Thomas F. Parkerton, ExxonMobil Biomedical Science, Houston, TX

Richard L. Poirot, Independent Consultant, Burlington, VT

Kenneth M. Portier, American Cancer Society, Atlanta, GA

Kenneth Ramos, University of Arizona, Tucson, AZ

David B. Richardson, University of North Carolina, Chapel Hill, NC

Tara L. Sabo-Attwood, University of Florida, Gainesville, FL

William Schlesinger, Cry Institute of Ecosystem Studies, Millbrook, NY

Gina Solomon, California Environmental Protection Agency, Sacramento, CA

Daniel O. Stram, University of Southern California, Los Angeles, CA

Peter S. Thorne (Chair), University of Iowa, Iowa City, IA
xxviii

Jay Turner, Washington University, St. Louis, MO

Edwin van Wijngaarden, University of Rochester, Rochester, NY

Jeanne M. VanBriesen, Carnegie Mellon University, Pittsburgh, PA

John Vena, Medical University of South Carolina, Charleston, SC

Elke Weber, Columbia Business School, New York, NY

Charles Werth, University of Texas at Austin, Austin, TX

Peter J. Wilcoxen, Syracuse University, Syracuse, NY

Robyn S. Wilson, The Ohio State University, Columbus, OH

U.S. Environmental Protection Agency Science Advisory Board Hydraulic Fracturing 

Research Advisory Panel

Stephen W. Almond, Fritz Industries, Inc., Houston, TX

E. Scott Bair, The Ohio State University, Columbus, OH

Peter Bloomfield, North Carolina State University, Raleigh, NC

Steven R. Bohlen, State of California Department of Conservation, Sacramento, CA

Elizabeth W. Boyer, Pennsylvania State University, University Park, PA

Susan L. Brantley, Pennsylvania State University, University Park, PA

James V. Bruckner, University of Georgia, Athens, GA

Thomas L. Davis, Colorado School of Mines, Golden, CO

Joseph J. DeGeorge, Merck Research Laboratories, Lansdale, PA

Joel Ducoste, North Carolina State University, Raleigh, NC

Shari Dunn-Norman, Missouri University of Science and Technology, Rolla, MO

David A. Dzombak (Chair), Carnegie Mellon University, Pittsburgh, PA

Katherine Bennett Ensor, Rice University, Houston, TX

Elaine M. Faustman, University of Washington, Seattle, WA

John V. Fontana, Vista GeoScience LLC, Golden, CO

Daniel J. Goode, U.S. Geological Survey, Exton, PA

Edward Hanlon, Designated Federal Officer, U.S. Environmental Protection Agency, Science Advisory

Board Staff, Washington, DC

Bruce D. Honeyman, Colorado School of Mines, Golden, CO

Walter R. Hufford, Talisman Energy USA Inc. – REPSOL, Warrendale, PA

Richard F. Jack, Thermo Fisher Scientific Inc., San Jose, CA

Dawn S. Kaback, Amec Foster Wheeler, Denver, CO

Abby A. Li, Exponent Inc., San Francisco, CA

Dean N. Malouta, White Mountain Energy Consulting, LLC, Houston, TX

Cass T. Miller, University of North Carolina, Chapel Hill, NC

Laura J. Pyrak-Nolte, Purdue University, West Lafayette, IN

Stephen Randtke, University of Kansas, Lawrence, KS

Joseph N. Ryan, University of Colorado-Boulder, Boulder, CO

James E. Saiers, Yale University, New Haven, CT

Azra N. Tutuncu, Colorado School of Mines, Golden, CO

Paul K. Westerhoff, Arizona State University, Tempe, AZ

Thomas M. Young, University of California-Davis, Davis, CA
xxix

U.S. Environmental Protection Agency Internal Technical Reviewers

Lisa Biddle, Office of Water, Washington, DC 

Britta Bierwagen, Office of Research and Development, Washington, DC

Frank Brock, Region 2, New York, NY

Thomas Burke, Office of Research and Development, Washington, DC

Kyle Carey, Office of Water, Washington, DC 

Mark Corrales, Office of Policy, Washington, DC

Brian D’Amico, Office of Water, Washington, DC

Kathleen Deener, Office of Research and Development, Washington, DC

Tim Elkins, Region 5, Chicago, IL

Malcolm Field, Office of Research and Development, Washington, DC

Erin Floto, Region 2, New York, NY

Robert Ford, Office of Research and Development, Cincinnati, OH

Greg Fritz, Office of Chemical Safety and Pollution Prevention, Washington, DC 

Andrew Gillespie, Office of Research and Development, Research Triangle Park, NC

Janet Goodwin, Office of Water, Washington, DC

Bradley Grams, Region 5, Chicago, IL

Holly Green, Office of Water, Washington, DC

Richard Hall, Region 4, Atlanta, GA

Mary Hanley, Administrator’s Office, Washington, DC

Mohamed Hantush, Office of Research and Development, Cincinnati, OH

Jana Harvill, Region 6, Dallas, TX

Fred Hauchman, Office of Science Policy, Washington, DC

Kurt Hildebrandt, Region 7, Lenexa, KS

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

Stephen Jann, Region 5, Chicago, IL

Thomas Johnson, Office of Research and Development, Washington, DC 

Jeff Jollie, Office of Water, Washington, DC

Robert Kavlock, Office of Research and Development, 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 

Mike Mattheisen, Office of Chemical Safety and Pollution Prevention, Washington, DC

Damon McElroy, Region 6, Dallas, TX

Karen Milam, Office of Water, Washington, DC

Keara Moore, Office of Water, Washington, DC
xxx

Nathan Mottl, Office of Chemical Safety and Pollution Prevention, Washington, DC 

Greg Oberley, Region 8, Denver, CO

Mike Overbay, Region 6, Dallas, TX

Pooja Parikh, Office of General Council, Washington, DC

Dale Perry, Administrator’s Office, Washington, DC

Tricia Pfeiffer, Region 8, Denver, CO

Steve Platt, Region 3, Philadelphia, PA

Dave Rectenwald, Region 3, Philadelphia, PA 

Meredith Russell, Office of Water, Washington, DC

Daniel Ryan, Region 3, Philadelphia, PA

Greg Schweer, Office of Chemical Safety and Pollution Prevention, Washington, DC 

Brian Smith, Region 4, Atlanta, GA

Kelly Smith, Office of Research and Development, Cincinnati, OH

Steve Souders, Office of Solid Waste and Emergency Response, Washington, DC 

Kate Sullivan, Office of Research and Development, Athens, GA

Kevin Teichman, Office of Research and Development, Washington, DC 

Chuck Tinsley, Region 8, Denver, CO

Scott Wilson, Office of Water, Washington, DC

Jose Zambrana, Office of Research and Development, Washington, DC
xxxi

Acknowledgements

The development of this assessment involved individuals from across the Agency, many of which 

have been listed as authors, contributors or reviewers, or acknowledged below. We want to 

specifically highlight and acknowledge Jeanne Briskin for her role with making the EPA’s Hydraulic 

Fracturing Drinking Water Study a success. Jeanne was responsible for the development of the 

2011 Study Plan and for coordinating the implementation of the projects outlined in that Study 

Plan. Jeanne also played a large role with reaching out to stakeholders for input that informed the 

development of the reports and publications resulting from Study Plan projects, and the 

development of this assessment. 

Other individuals who have made this assessment report possible and have not been previously 

mentioned include: Jessica Agatstein, Adam Banasiak, Tom Beneke, Amy Bergdale, Ann Calamai, 

Amy Clark, Brian Devir, Dayna Gibbons, Chris Grulke, Seth Haines, H. Jason Harmon, Cheryl Itkin, 

Maureen Johnson, Randy Lamdin, Audrey Levine, Jordan Macknick, Kelsey Maloney, Lisa Matthews, 

Angela McFadden, Connie Meacham, Marc Morandi, Jean-Philippe Nicot, Jennifer Orme-Zavaleta, 

Nancy Parrotta, Robert Puls, Bridget R. Scanlon, Ayn Schmit, Cynthia Sonich-Mullen, Vicki Soto, 

Inthirany Thillainadarajah, Vincent Tidwell, Martha Walters, and Steve Watkins.

Contract support was provided by The Cadmus Group, Inc. under contracts EP-C-08-015 and EP-C15-022 and by Neptune & Co., Inc. under contract EP-C-13-022. Authors and contributors included

student service contractors to USEPA: Kevin Blackwood (Contract EP-13-C-000133); Maryam Cluff

(Contract EP-13-H-000438); Ashley McElmury (Contract EP-12-C-000025); Claudia Meza-Cuadra

(Contract EP-13-H-000054); Alison Singer (Contract EP-13-H-000474); Sarah Solomon (Contract

EP-D-15-003); Jessica Wilhelm (Contract EP-D-15-003); Jie Xu (Contract EP-13-C-00120); Liabeth

Yohannes (Contract EP-14-H-000455). Kay Pinley was supported under the Senior Environmental

Employment Program under agreement CQ-835363 with NCCBA.
xxxii

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Executive Summary

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Executive Summary

ES-2 

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Executive Summary

ES-3 

Executive Summary

People rely on clean and plentiful water resources to meet their basic needs, including drinking, 

bathing, and cooking. In the early 2000s, members of the public began to raise concerns about 

potential impacts on their drinking water from hydraulic fracturing at nearby oil and gas 

production wells. In response to these concerns, Congress urged the U.S. Environmental Protection 

Agency (EPA) to study the relationship between hydraulic fracturing for oil and gas and drinking 

water in the United States. 

The goals of the study were to assess the potential for activities in the hydraulic fracturing water 

cycle to impact the quality or quantity of drinking water resources and to identify factors that affect 

the frequency or severity of those impacts. To achieve these goals, the EPA conducted independent 

research, engaged stakeholders through technical workshops and roundtables, and reviewed 

approximately 1,200 cited sources of data and information. The data and information gathered 

through these efforts served as the basis for this report, which represents the culmination of the 

EPA’s study of the potential impacts of hydraulic fracturing for oil and gas on drinking water 

resources. 

The hydraulic fracturing water cycle describes the use of water in hydraulic fracturing, from water 

withdrawals to make hydraulic fracturing fluids, through the mixing and injection of hydraulic 

fracturing fluids in oil and gas production wells, to the collection and disposal or reuse of produced 

water. These activities can impact drinking water resources under some circumstances. Impacts 

can range in frequency and severity, depending on the combination of hydraulic fracturing water 

cycle activities and local- or regional-scale factors. The following combinations of activities and 

factors are more likely than others to result in more frequent or more severe impacts: 

• Water withdrawals for hydraulic fracturing in times or areas of low water availability, 

particularly in areas with limited or declining groundwater resources; 

• Spills during the management of hydraulic fracturing fluids and chemicals or produced 

water that result in large volumes or high concentrations of chemicals reaching 

groundwater resources; 

• Injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, 

allowing gases or liquids to move to groundwater resources;

• Injection of hydraulic fracturing fluids directly into groundwater resources; 

• Discharge of inadequately treated hydraulic fracturing wastewater to surface water

resources; and

• Disposal or storage of hydraulic fracturing wastewater in unlined pits, resulting in 

contamination of groundwater resources.

The above conclusions are based on cases of identified impacts and other data, information, and 

analyses presented in this report. Cases of impacts were identified for all stages of the hydraulic 

fracturing water cycle. Identified impacts generally occurred near hydraulically fractured oil and 
Executive Summary

ES-4 

gas production wells and ranged in severity, from temporary changes in water quality to 

contamination that made private drinking water wells unusable. 

The available data and information allowed us to qualitatively describe factors that affect the 

frequency or severity of impacts at the local level. However, significant data gaps and uncertainties 

in the available data prevented us from calculating or estimating the national frequency of impacts 

on drinking water resources from activities in the hydraulic fracturing water cycle. The data gaps 

and uncertainties described in this report also precluded a full characterization of the severity of 

impacts. 

The scientific information in this report can help inform decisions by federal, state, tribal, and local 

officials; industry; and communities. In the short-term, attention could be focused on the 

combinations of activities and factors outlined above. In the longer-term, attention could be focused 

on reducing the data gaps and uncertainties identified in this report. Through these efforts, current 

and future drinking water resources can be better protected in areas where hydraulic fracturing is 

occurring or being considered. 

Drinking Water Resources in the United States

In this report, drinking water resources are defined as any water that now serves, or in the future 

could serve, as a source of drinking water for public or private use. This includes both surface water 

resources and groundwater resources (Text Box ES-1). In 2010, approximately 58% of the total 

volume of water withdrawn for public and non-public water supplies came from surface water 

resources and approximately 42% came from groundwater resources (Maupin et al., 2014).1 Most 

people (86% of the population) in the United States relied on public water supplies for their 

drinking water in 2010, and approximately 14% of the population obtained drinking water from 

non-public water supplies. Non-public water supplies are often private water wells that supply 

drinking water to a residence. 

Future access to high-quality drinking water in the United States will likely be affected by changes 

in climate and water use. Since 2000, about 30% of the total area of the contiguous United States 

has experienced moderate drought conditions and about 20% has experienced severe drought 

conditions. Declines in surface water resources have led to increased withdrawals and net 

depletions of groundwater in some areas. As a result, non-fresh water resources (e.g., wastewater 

from sewage treatment plants, brackish groundwater and surface water, and seawater) are 

increasingly treated and used to meet drinking water demand.

Natural processes and human activities can affect the quality and quantity of current and future 

drinking water resources. This report focuses on the potential for activities in the hydraulic 

fracturing water cycle to impact drinking water resources; other processes or activities are not 

discussed.

 

1 Public water systems provide water for human consumption from surface or groundwater 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. Nonpublic water systems have fewer than 15 service connections and serve fewer than 25 individuals. 
Executive Summary

ES-5 

Text Box ES-1. Drinking Water Resources. 

In this report, drinking water resources are considered to be any water that now serves, or in the future could 

serve, as a source of drinking water for public or private use. This includes both surface water bodies and 

underground rock formations that contain water. 

Surface water resources include water bodies located on the surface of the Earth. Rivers, springs, lakes, and 

reservoirs are examples of surface water resources. Water quality and quantity are often considered when 

determining whether a surface water resource could be used as a drinking water resource.

Groundwater resources are underground rock formations that contain water. Groundwater resources are found at 

different depths nearly everywhere in the United States. Resource depth, water quality, and water yield are often 

considered when determining whether a groundwater resource could be used as a drinking water resource.

Hydraulic Fracturing for Oil and Gas in the United States

Hydraulic fracturing is frequently used to enhance oil and gas production from underground rock 

formations and is one of many activities that occur during the life of an oil and gas production well 

(Figure ES-1). During hydraulic fracturing, hydraulic fracturing fluid is injected down an oil or gas 

production well and into the targeted rock formation under pressures great enough to fracture the 

oil- and gas-bearing rock.1 The hydraulic fracturing fluid usually carries proppant (typically sand) 

into the newly-created fractures to keep the fractures “propped” open. After hydraulic fracturing, 

oil, gas, and other fluids flow through the fractures and up the production well to the surface, where 

they are collected and managed.

 

1 The targeted rock formation (sometimes called the “target zone” or “production zone”) is the portion of a subsurface 

rock formation that contains the oil or gas to be extracted. 
Executive Summary

ES-6 

Figure ES-1. General timeline and summary of activities at a hydraulically fractured oil or gas 

production well. 

Hydraulically fractured oil and gas production wells have significantly contributed to the surge in 

domestic oil and gas production, accounting for slightly more than 50% of oil production and nearly 

70% of gas production in 2015 (EIA, 2016c, d). The surge occurred when hydraulic fracturing was 

combined with directional drilling technologies around 2000. Directional drilling allows oil and gas 

production wells to be drilled horizontally or directionally along the targeted rock formation, 

exposing more of the oil- or gas-bearing rock formation to the production well. When combined 

with directional drilling technologies, hydraulic fracturing expanded oil and gas production to oiland gas-bearing rock formations previously considered uneconomical. Although hydraulic 

fracturing is commonly associated with oil and gas production from deep, horizontal wells drilled

into shale (e.g., the Marcellus Shale in Pennsylvania or the Bakken Shale in North Dakota), it has 

been used in a variety of oil and gas production wells (Text Box ES-2) and other types of oil- or gasbearing rock (e.g., sandstone, carbonate, and coal).

Approximately 1 million wells have been hydraulically fractured since the technique was first 

developed in the late 1940s (Gallegos and Varela, 2015; IOGCC, 2002). Roughly one third of those 

wells were hydraulically fractured between 2000 and approximately 2014. Wells hydraulically 

fractured between 2000 and 2013 were located in pockets of activity across the United States 

(Figure ES-2). Based on several different data compilations, we estimate that 25,000 to 30,000 new 

wells were drilled and hydraulically fractured in the United States each year between 2011 and 

2014, in addition to existing wells that were hydraulically fractured to increase production.1

Following the decline in oil and gas prices, the number of new wells drilled and hydraulically 

fractured appears to have decreased, with about 20,000 new wells drilled and hydraulically 

fractured in 2015.

 

1 See Table 3-1 in Chapter 3. 
Executive Summary

ES-7 

Text Box ES-2. Hydraulically Fractured Oil and Gas Production Wells.

Hydraulically fractured oil and gas production wells come in different shapes and sizes. They can have different 

depths, orientations, and construction characteristics. They can include new wells (i.e., wells that are hydraulically 

fractured soon after construction) and old wells (i.e., wells that are hydraulically fractured after producing oil and 

gas for some time).
Executive Summary

ES-8 

Figure ES-2. Locations of approximately 275,000 wells that were drilled and likely 

hydraulically fractured between 2000 and 2013.

Data from DrillingInfo (2014a). 

Hydraulically fractured oil and gas production wells can be located near or within sources of

drinking water. Between 2000 and 2013, approximately 3,900 public water systems were 

estimated to have had at least one hydraulically fractured well within 1 mile of their water source; 

these public water systems served more than 8.6 million people year-round in 2013. An additional 

3.6 million people were estimated to have obtained drinking water from non-public water supplies

in counties with at least one hydraulically fractured well.1 Underground, hydraulic fracturing can 

occur in close vertical proximity to drinking water resources. In some parts of the United States

(e.g., the Powder River Basin in Montana and Wyoming), there is no vertical distance between the 

top of the hydraulically fractured oil- or gas-bearing rock formation and the bottom of treatable 

water, as determined by data from state oil and gas agencies and state geological survey data.2 In 

other parts of the country (e.g., the Eagle Ford Shale in Texas), there can be thousands of feet of 

 

1 This estimate only includes counties in which 30% or more of the population (i.e., two or more times the national 

average) relied on non-public water supplies in 2010. See Section 2.5 in Chapter 2. 

2 In these cases, water that is naturally found in the oil- and gas-bearing rock formation meets the definition of drinking 

water in some parts of the basin. See Section 6.3.2 in Chapter 6.
Executive Summary

ES-9

rock that separate treatable water from the hydraulically fractured oil- or gas-bearing rock 

formation. When hydraulically fractured oil and gas production wells are located near or within 

drinking water resources, there is a greater potential for activities in the hydraulic fracturing water 

cycle to impact those resources. 

Approach: The Hydraulic Fracturing Water Cycle

The EPA studied the relationship between hydraulic fracturing for oil and gas and drinking water 

resources using the hydraulic fracturing water cycle (Figure ES-3). The hydraulic fracturing water 

cycle has five stages; each stage is defined by an activity involving water that supports hydraulic 

fracturing. The stages and activities of the hydraulic fracturing water cycle include: 

• Water Acquisition: the withdrawal of groundwater or surface water to make hydraulic

fracturing fluids;

• Chemical Mixing: the mixing of a base fluid (typically water), proppant, and additives at

the well site to create hydraulic fracturing fluids;1

• Well Injection: the injection and movement of hydraulic fracturing fluids through the oil

and gas production well and in the targeted rock formation;

• Produced Water Handling: the on-site collection and handling of water that returns to

the surface after hydraulic fracturing and the transportation of that water for disposal or

reuse;2 and

• Wastewater Disposal and Reuse: the disposal and reuse of hydraulic fracturing

wastewater.

3 

Potential impacts on drinking water resources from the above activities are considered in this 

report. We do not address other concerns that have been raised by stakeholders about hydraulic 

fracturing (e.g., potential air quality impacts or induced seismicity) or other oil and gas exploration 

and production activities (e.g., environmental impacts from site selection and development), as 

these were not included in the scope of the study. Additionally, this report is not a human health 

risk assessment; it does not identify populations exposed to hydraulic fracturing-related chemicals, 

and it does not estimate the extent of exposure or estimate the incidence of human health impacts.

1 A base fluid is the fluid into which proppants and additives are mixed to make a hydraulic fracturing fluid; water is an 

example of a base fluid. Additives are chemicals or mixtures of chemicals that are added to the base fluid to change its 

properties. 

2 “Produced water” is defined in this report as water that flows from and through oil and gas wells to the surface as a byproduct of oil and gas production.

3 “Hydraulic fracturing wastewater” is defined in this report as produced water from hydraulically fractured oil and gas 

wells that is being managed using practices that include, but are not limited to, injection in Class II wells, reuse in other

hydraulic fracturing operations, and various aboveground disposal practices. The term “wastewater” is being used as a 

general description of certain waters and is not intended to constitute a term of art for legal or regulatory purposes. Class 

II wells are used to inject wastewater associated with oil and gas production underground and are regulated under the 

Underground Injection Control Program of the Safe Drinking Water Act. 
Executive Summary

ES-10 

Figure ES-3. The five stages of the hydraulic fracturing water cycle. 

The stages (shown in the insets) identify activities involving water that support hydraulic fracturing for oil and gas. 

Activities may take place in the same watershed or different watersheds and close to or far from drinking water 

resources. Thin arrows in the insets depict the movement of water and chemicals. Specific activities in the 

“Wastewater Disposal and Reuse” inset include (a) disposal of wastewater through underground injection, (b) 

wastewater treatment followed by reuse in other hydraulic fracturing operations or discharge to surface waters, 

and (c) disposal through evaporation or percolation pits.

Each stage of the hydraulic fracturing water cycle was assessed to identify (1) the potential for 

impacts on drinking water resources and (2) factors that affect the frequency or severity of impacts. 

Specific definitions used in this report are provided below:

• An impact is any change in the quality or quantity of drinking water resources, regardless 

of severity, that results from an activity in the hydraulic fracturing water cycle. 

• A factor is a feature of hydraulic fracturing operations or an environmental condition that 

affects the frequency or severity of impacts.

• Frequency is the number of impacts per a given unit (e.g., geographic area, unit of time, 

number of hydraulically fractured wells, or number of water bodies). 

• Severity is the magnitude of change in the quality or quantity of a drinking water resource 

as measured by a given metric (e.g., duration, spatial extent, or contaminant 

concentration).
Executive Summary

ES-11 

Factors affecting the frequency or severity of impacts were identified because they describe 

conditions under which impacts are more or less likely to occur and because they could inform the 

development of future strategies and actions to prevent or reduce impacts. Although no attempt 

was made to identify or evaluate best practices, ways to reduce the frequency or severity of impacts 

from activities in the hydraulic fracturing water cycle are described in this report when they were 

reported in the scientific literature. Laws, regulations, and policies also exist to protect drinking 

water resources, but a comprehensive summary and broad evaluation of current or proposed 

regulations and policies was beyond the scope of this report. 

Relevant scientific literature and data were evaluated for each stage of the hydraulic fracturing 

water cycle. Literature included articles published in science and engineering journals, federal and 

state government reports, non-governmental organization reports, and industry publications. Data 

sources included federal- and state-collected data sets, databases maintained by federal and state 

government agencies, other publicly available data, and industry data provided to the EPA.1 The 

relevant literature and data complement research conducted by the EPA under its Plan to Study the 

Potential Impacts of Hydraulic Fracturing on Drinking Water Resources (Text Box ES-3).

Text Box ES-3. The EPA’s Study of the Potential Impacts of Hydraulic Fracturing for Oil and 

Gas on Drinking Water Resources. 

The EPA’s study is the first national study of the potential impacts of hydraulic fracturing for oil and gas on drinking 

water resources. It included independent research projects conducted by EPA scientists and contractors and a 

state-of-the-science assessment of available data and information on the relationship between hydraulic fracturing 

and drinking water resources (i.e., this report). 

Throughout the study, the EPA consulted with the Agency’s independent Science Advisory Board (SAB) on the

scope of the study and the progress made on the research projects. The SAB also conducted a peer review of both

the Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources (U.S. EPA, 2011d;

referred to as the Study Plan in this report) and a draft of this report. 

Stakeholder engagement also played an important role in the development and implementation of the study.

While developing the scope of the study, the EPA held public meetings to get input from stakeholders on the study

scope and design. While conducting the study, the EPA requested information from the public and engaged with 

technical, subject-matter experts on topics relevant to the study in a series of technical workshops and 

roundtables. For more information on the EPA’s study, including the role of the SAB and stakeholders, visit

www.epa.gov/hfstudy. 

1 Industry data was provided to the EPA in response to two separate information requests to oil and gas service 

companies and oil and gas production well operators. Some of these data were claimed as confidential business 

information under the Toxic Substances Control Act and were treated as such in this report. 
Executive Summary

ES-12 

A draft of this report underwent peer review by the EPA’s Science Advisory Board (SAB). The SAB is 

an independent federal advisory committee that often conducts peer reviews of high-profile 

scientific matters relevant to the EPA. Members of the SAB and ad hoc panels formed under the 

auspices of the SAB are nominated by the public and selected based on factors such as technical 

expertise, knowledge, experience, and absence of any real or perceived conflicts of interest. Peer 

review comments provided by the SAB and public comments submitted to the SAB during their 

peer review, including comments on major conclusions and technical content, were carefully 

considered in the development of this final document.

A summary of the activities in the hydraulic fracturing water cycle and their potential to impact 

drinking water resources is provided below, including what is known about human health hazards 

associated with chemicals identified across all stages of the hydraulic fracturing water cycle. 

Additional details are available in the full report.

Water Acquisition 

Activity: The withdrawal of groundwater or surface water to make hydraulic fracturing fluids. 

Relationship to Drinking Water Resources: Groundwater and surface water resources that 

provide water for hydraulic fracturing fluids can also provide drinking water for public or nonpublic water supplies.

Water is the major component of nearly all hydraulic fracturing fluids, typically making up 90–97% 

of the total fluid volume injected into a well. The median volume of water used, per well, for 

hydraulic fracturing was approximately 1.5 million gallons (5.7 million liters) between January 

2011 and February 2013, as reported in FracFocus 1.0 (Text Box ES-4). There was wide variation in 

the water volumes reported per well, with 10th and 90th percentiles of 74,000 gallons (280,000 

liters) and 6 million gallons (23 million liters) per well, respectively. There was also variation in 

water use per well within and among states (Table ES-1). This variation likely results from several 

factors, including the type of well, the fracture design, and the type of hydraulic fracturing fluid 

used. An analysis of hydraulic fracturing fluid data from Gallegos et al. (2015) indicates that water 

volumes used per well have increased over time as more horizontal wells have been drilled. 

Water used for hydraulic fracturing is typically fresh water taken from available groundwater 

and/or surface water resources located near hydraulically fractured oil and gas production wells. 

Water sources can vary across the United States, depending on regional or local water availability; 

laws, regulations, and policies; and water management practices. Hydraulic fracturing operations in 

the humid eastern United States generally rely on surface water resources, whereas operations in 

the arid and semi-arid western United States generally rely on groundwater or surface water. 

Geographic differences in water use for hydraulic fracturing are illustrated in Figure ES-4, which 

shows that most of the water used for hydraulic fracturing in the Marcellus Shale region of the 

Susquehanna River Basin came from surface water resources between approximately 2008 and 

2013. In comparison, less than half of the water used for hydraulic fracturing in the Barnett Shale 

region of Texas came from surface water resources between approximately 2011 and 2013. 
Executive Summary

ES-13 

Text Box ES-4. FracFocus Chemical Disclosure Registry.

The FracFocus Chemical Disclosure Registry is a publicly-accessible website (www.fracfocus.org) managed by the

Ground Water Protection Council (GWPC) and the Interstate Oil and Gas Compact Commission (IOGCC). Oil and gas 

production well operators can disclose information at this website about water and chemicals used in hydraulic

fracturing fluids at individual wells. In many states where oil and gas production occurs, well operators are

required to disclose to FracFocus well-specific information on water and chemical use during hydraulic fracturing.

The GWPC and the IOGCC provided the EPA with over 39,000 PDF disclosures submitted by well operators to

FracFocus (version 1.0) before March 1, 2013. Data in the disclosures were extracted and compiled in a project 

database, which was used to conduct analyses on water and chemical use for hydraulic fracturing. Analyses were

conducted on over 38,000 unique disclosures for wells located in 20 states that were hydraulically fractured 

between January 1, 2011, and February 28, 2013.

Despite the challenge of adapting a dataset originally created for local use and single-PDF viewing to answer 

broader questions, the project database created by the EPA provided substantial insight into water and chemical

use for hydraulic fracturing. The project database represents the data reported to FracFocus 1.0 rather than all 

hydraulic fracturing that occurred in the United States during the study time period. The project database is an

incomplete picture of all hydraulic fracturing due to voluntary reporting in some states for certain time periods (in 

the absence of state reporting requirements), the omission of information on confidential chemicals from

disclosures, and invalid or erroneous information in the original disclosures or created during the development of

the database. The development of FracFocus 2.0, which became the exclusive reporting mechanism in June 2013,

was intended to increase the quality, completeness, and consistency of the data submitted by providing 

dropdown menus, warning and error messages during submission, and automatic formatting of certain fields. The 

GWPC has announced additional changes and upgrades for FracFocus 3.0 to enhance data searchability, increase 

system security, provide greater data accuracy, and further increase data transparency. 

Table ES-1. Water use per hydraulically fractured well between January 2011 and February 2013. 

Medians and percentiles were calculated from data submitted to FracFocus 1.0 (Appendix B).

State Number of FracFocus 

1.0 disclosures

Median volume per 

well (gallons)

10th percentile 

(gallons)

90th percentile 

(gallons)

Arkansas 1,423 5,259,965 3,234,963 7,121,249

California 711 76,818 21,462 285,306

Colorado 4,898 463,462 147,353 3,092,024

Kansas 121 1,453,788 10,836 2,227,926

Louisiana 966 5,077,863 1,812,099 7,945,630

Montana 207 1,455,757 367,326 2,997,552

New Mexico 1,145 175,241 35,638 1,871,666

North Dakota 2,109 2,022,380 969,380 3,313,482

Ohio 146 3,887,499 2,885,568 5,571,027

Oklahoma 1,783 2,591,778 1,260,906 7,402,230

Pennsylvania 2,445 4,184,936 2,313,649 6,615,981

Texas 16,882 1,420,613 58,709 6,115,195

Utah 1,406 302,075 76,286 769,360

West Virginia 273 5,012,238 3,170,210 7,297,080

Wyoming 1,405 322,793 5,727 1,837,602
Executive Summary

ES-14 

Hydraulic fracturing wastewater and other lower-quality water can also be used in hydraulic 

fracturing fluids to offset the need for fresh water, although the proportion of injected fluid that is 

reused hydraulic fracturing wastewater varies by location (Figure ES-4).1 Overall, the proportion of 

Figure ES-4. Water budgets illustrative of hydraulic fracturing water management practices in 

the Marcellus Shale in the Susquehanna River Basin between approximately 2008 and 2013 

and the Barnett Shale in Texas between approximately 2011 and 2013. 

Class II wells are used to inject wastewater associated with oil and gas production underground and are regulated 

under the Underground Injection Control Program of the Safe Drinking Water Act. Data sources are described in 

Figure 10-1 in Chapter 10.

 

1 Reused hydraulic fracturing wastewater as a percentage of injected fluid differs from the percentage of produced water

that is managed through reuse in other hydraulic fracturing operations. For example, in the Marcellus Shale region of the 

Susquehanna River Basin, approximately 14% of injected fluid was reused hydraulic fracturing wastewater, while 

approximately 90% of produced water was managed through reuse in other hydraulic fracturing operations (Figure ES4a).
Executive Summary

ES-15 

water used in hydraulic fracturing that comes from reused hydraulic fracturing wastewater 

appears to be low. In a survey of literature values from 10 states, basins, or plays, the median 

percentage of the injected fluid volume that came from reused hydraulic fracturing wastewater was 

5% between approximately 2008 and 2014.1There was an increase in the reuse of hydraulic 

fracturing wastewater as a percentage of the injected hydraulic fracturing fluid in both 

Pennsylvania and West Virginia between approximately 2008 and 2014. This increase is likely due 

to the limited availability of Class II wells, which are commonly used to dispose of oil and gas 

wastewater, and the costs of trucking wastewater to Ohio, where Class II wells are more prevalent.2

Class II wells are also prevalent in Texas, and the reuse of wastewater in hydraulic fracturing fluids 

in the Barnett Shale appears to be lower than in the Marcellus Shale (Figure ES-4). 

Because the same water resource can be used to support hydraulic fracturing and to provide 

drinking water, withdrawals for hydraulic fracturing can directly impact drinking water resources 

by changing the quantity or quality of the remaining water. Although every water withdrawal 

affects water quantity, we focused on water withdrawals that have the potential to significantly 

impact drinking water resources by limiting the availability of drinking water or altering its quality.

Water withdrawals for a single hydraulically fractured oil and gas production well are not expected 

to significantly impact drinking water resources, because the volume of water needed to 

hydraulically fracture a single well is unlikely to limit the availability of drinking water or alter its 

quality. If, however, multiple oil and gas production wells are located within an area, the total 

volume of water needed to hydraulically fracture all of the wells has the potential to be a significant 

portion of the water available and impacts on drinking water resources can occur. 

To assess whether hydraulic fracturing operations are a relatively large or small user of water, we 

compared water use for hydraulic fracturing to total water use at the county level (Text Box ES-5). 

In most counties studied, the average annual water volumes reported in FracFocus 1.0 were 

generally less than 1% of total water use. This suggests that hydraulic fracturing operations 

represented a relatively small user of water in most counties. There were exceptions, however. 

Average annual water volumes reported in FracFocus 1.0 were 10% or more of total water use in 

26 of the 401 counties studied, 30% or more in nine counties, and 50% or more in four counties.3 In 

these counties, hydraulic fracturing operations represented a relatively large user of water.

The above results suggest that hydraulic fracturing operations can significantly increase the volume 

of water withdrawn in particular areas. Increased water withdrawals can result in significant 

impacts on drinking water resources if there is insufficient water available in the area to 

accommodate all users. To assess the potential for these impacts, we compared hydraulic fracturing

water use to estimates of water availability at the county level.4 In most counties studied, average

 

1 See Section 4.2 in Chapter 4.

2 See Chapter 8 for additional information on Class II wells. 

3 Hydraulic fracturing water consumption estimates followed the same general pattern as the water use estimates 

presented here, but with slightly larger percentages in each category (Section 4.4 in Chapter 4).

4 County-level water availability estimates were derived from the Tidwell et al. (2013) estimates of water availability for 

siting new thermoelectric power plants (see Text Box 4-2 in Chapter 4 for details). The county-level water availability 

estimates used in this report represent the portion of water available to new users within a county. 
Executive Summary

ES-16 

Text Box ES-5. County-Level Water Use for Hydraulic Fracturing.

To assess whether hydraulic fracturing operations are a relatively large or small user of water, the average annual 

water use for hydraulic fracturing in 2011 and 2012 was compared, at the county-level, to total water use in 2010. 

For most counties studied, average annual water volumes reported for individual counties in FracFocus 1.0 were 

less than 1% of total water use in those counties. But in some counties, hydraulic fracturing operations reported in 

FracFocus 1.0 represented a relatively large user of water.

annual water volumes reported for hydraulic fracturing were less than 1% of the estimated annual 

volume of readily-available fresh water. However, average annual water volumes reported for 

hydraulic fracturing were greater than the estimated annual volume of readily-available fresh

water in 17 counties in Texas. This analysis suggests that there was enough water available 

annually to support the level of hydraulic fracturing reported to FracFocus 1.0 in most, but not all, 
Executive Summary

ES-17 

areas of the country. This observation does not preclude the possibility of local impacts in other 

areas of the country, nor does it indicate that local impacts have occurred or will occur in the 17 

counties in Texas. To better understand whether local impacts have occurred, and the factors that 

affect those impacts, local-level studies, such as the ones described below, are needed. 

Local impacts on drinking water quantity have occurred in areas with increased hydraulic 

fracturing activity. In 2011, for example, drinking water wells in an area overlying the Haynesville 

Shale ran out of water due to higher than normal groundwater withdrawals and drought (LA 

Ground Water Resources Commission, 2012). Water withdrawals for hydraulic fracturing 

contributed to these conditions, along with other water users and the lack of precipitation. 

Groundwater impacts have also been reported in Texas. In a detailed case study, Scanlon et al. 

(2014b) estimated that groundwater levels in approximately 6% of the area studied dropped by 

100 feet (31 meters) to 200 feet (61 meters) or more after hydraulic fracturing activity increased in 

2009. 

In contrast, studies in the Upper Colorado and Susquehanna River basins found minimal impacts on

drinking water resources from hydraulic fracturing. In the Upper Colorado River Basin, the EPA 

found that high-quality water produced from oil and gas wells in the Piceance tight sands provided 

nearly all of the water for hydraulic fracturing in the study area (U.S. EPA, 2015e). Due to this high 

reuse rate, the EPA did not identify any locations in the study area where hydraulic fracturing 

contributed to locally high water use. In the Susquehanna River Basin, multiple studies and state 

reports have identified the potential for hydraulic fracturing water withdrawals in the Marcellus 

Shale to impact surface water resources. Evidence suggests, however, that current water 

management strategies, including passby flows and reuse of hydraulic fracturing wastewater, help 

protect streams from depletion by hydraulic fracturing water withdrawals. A passby flow is a 

prescribed, low-streamflow threshold below which water withdrawals are not allowed.

The above examples highlight factors that can affect the frequency or severity of impacts on

drinking water resources from hydraulic fracturing water withdrawals. In particular, areas of the 

United States that rely on declining groundwater resources are vulnerable to more frequent and 

more severe impacts from all water withdrawals, including withdrawals for hydraulic fracturing. 

Extensive groundwater withdrawals can limit the availability of belowground drinking water 

resources and can also change the quality of the water remaining in the resource. Because 

groundwater recharge rates can be low, impacts can last for many years. Seasonal or long-term 

drought can also make impacts more frequent and more severe for groundwater and surface water 

resources. Hot, dry weather reduces or prevents groundwater recharge and depletes surface water 

bodies, while water demand often increases simultaneously (e.g., for irrigation). This combination 

of factors—high hydraulic fracturing water use and relatively low water availability due to 

declining groundwater resources and/or frequent drought—was found to be present in southern 

and western Texas. 

Water management strategies can also affect the frequency and severity of impacts on drinking 

water resources from hydraulic fracturing water withdrawals. These strategies include using 

hydraulic fracturing wastewater or brackish groundwater for hydraulic fracturing, transitioning 

from limited groundwater resources to more abundant surface water resources, and using passby 
Executive Summary

ES-18 

flows to control water withdrawals from surface water resources. Examples of these water 

management strategies can be found throughout the United States. In western and southern Texas, 

for example, the use of brackish water is currently reducing impacts on fresh water sources, and 

could, if increased, reduce future impacts. Louisiana and North Dakota have encouraged well 

operators to withdraw water from surface water resources instead of high-quality groundwater 

resources. And, as described above, the Susquehanna River Basin Commission limits surface water 

withdrawals during periods of low stream flow.

Water Acquisition Conclusions

With notable exceptions, hydraulic fracturing uses a relatively small percentage of water when 

compared to total water use and availability at large geographic scales. Despite this, hydraulic 

fracturing water withdrawals can affect the quantity and quality of drinking water resources by 

changing the balance between the demand on local water resources and the availability of those 

resources. Changes that have the potential to limit the availability of drinking water or alter its 

quality are more likely to occur in areas with relatively high hydraulic fracturing water withdrawals 

and low water availability, particularly due to limited or declining groundwater resources. Water 

management strategies (e.g., encouragement of alternative water sources or water withdrawal 

restrictions) can reduce the frequency or severity of impacts on drinking water resources from 

hydraulic fracturing water withdrawals.

Chemical Mixing

Activity: The mixing of a base fluid, proppant, and additives at the well site to create hydraulic 

fracturing fluids. 

Relationship to Drinking Water Resources: Spills of additives and hydraulic fracturing fluids can 

reach groundwater and surface water resources. 

Hydraulic fracturing fluids are engineered to create and grow fractures in the targeted rock

formation and to carry proppant through the oil and gas production well into the newly-created

fractures. Hydraulic fracturing fluids are typically made up of base fluids, proppant, and additives.

Base fluids make up the largest proportion of hydraulic fracturing fluids by volume. As illustrated in

Text Box ES-6, base fluids can be a single substance (e.g., water in the slickwater example) or can be

a mixture of substances (e.g., water and nitrogen in the energized fluid example). The EPA’s analysis

of hydraulic fracturing fluid data reported to FracFocus 1.0 suggests that water was the most 

commonly used base fluid between January 2011 and February 2013 (U.S. EPA, 2015a). Non-water 

substances, such as gases and hydrocarbon liquids, were reported to be used alone or blended with

water to form a base fluid in fewer than 3% of wells in FracFocus 1.0.

Proppant makes up the second largest proportion of hydraulic fracturing fluids (Text Box ES-6).

Sand (i.e., quartz) was the most commonly reported proppant between January 2011 and February 

2013, with 98% of wells in FracFocus 1.0 reporting sand as the proppant (U.S. EPA, 2015a). Other 
Executive Summary

ES-19 

Text Box ES-6. Examples of Hydraulic Fracturing Fluids.

Hydraulic fracturing fluids are engineered to create and extend fractures in the targeted rock formation and to 

carry proppant through the production well into the newly-created fractures. While there is no universal hydraulic 

fracturing fluid, there are general types of hydraulic fracturing fluids. Two types of hydraulic fracturing fluids are 

described below. 

Slickwater 

Slickwater hydraulic fracturing fluids are water-based fluids that generally contain a friction reducer. The friction 

reducer makes it easier for the fluid to be pumped down the oil and gas production well at high rates. Slickwater is 

commonly used to hydraulically fracture shale formations.

Energized Fluid

Energized fluids are mixtures of liquids and gases. They can be used for hydraulic fracturing in under-pressured gas 

formations. 
Executive Summary

ES-20 

proppants can include man-made or specially engineered particles, such as high-strength ceramic 

materials or sintered bauxite.1

Additives generally make up the smallest proportion of the overall composition of hydraulic 

fracturing fluids (Text Box ES-6), yet have the greatest potential to impact the quality of drinking 

water resources compared to proppant and base fluids. Additives, which can be a single chemical or 

a mixture of chemicals, are added to the base fluid to change its properties (e.g., adjust pH, increase 

fluid thickness, or limit bacterial growth). The choice of which additives to use depends on the 

characteristics of the targeted rock formation (e.g., rock type, temperature, and pressure), the 

economics and availability of desired additives, and well operator or service company preferences 

and experience. 

The variability of additives, both in their purpose and chemical composition, suggests that a large 

number of different chemicals may be used in hydraulic fracturing fluids across the United States. 

The EPA identified 1,084 chemicals that were reported to have been used in hydraulic fracturing 

fluids between 2005 and 2013.2,3 The EPA’s analysis of FracFocus 1.0 data indicates that between 4 

and 28 chemicals were used per well between January 2011 and February 2013 and that no single 

chemical was used in all wells (U.S. EPA, 2015a). Three chemicals—methanol, hydrotreated light 

petroleum distillates, and hydrochloric acid—were reported in 65% or more of the wells in 

FracFocus 1.0; 35 chemicals were reported in at least 10% of the wells (Table ES-2). 

Table ES-2. Chemicals reported in 10% or more of disclosures in FracFocus 1.0. 

Disclosures provided information on chemicals used at individual well sites between January 1, 2011, and February 

28, 2013.

Chemical Name (CASRN)a Percent of FracFocus 1.0 disclosuresb

Methanol (67-56-1) 72

Hydrotreated light petroleum distillates (64742-47-8) 65

Hydrochloric acid (7647-01-0) 65

Water (7732-18-5)c 48

Isopropanol (67-63-0) 47

Ethylene glycol (107-21-1) 46

Peroxydisulfuric acid, diammonium salt (7727-54-0) 44

Sodium hydroxide (1310-73-2) 39

Guar gum (9000-30-0) 37

 

1 Sintered bauxite is crushed and powdered bauxite that is fused into spherical beads at high temperatures. 

2 This list includes 1,084 unique Chemical Abstracts Service Registration Numbers (CASRNs), which can be assigned to a 

single chemical (e.g., hydrochloric acid) or a mixture of chemicals (e.g., hydrotreated light petroleum distillates). 

Throughout this report, we refer to the substances identified by unique CASRNs as “chemicals.” 

3 Dayalu and Konschnik (2016) identified 995 unique CASRNs from data submitted to FracFocus between March 9, 2011, 

and April 13, 2015. Two hundred sixty-three of these CASRNs are not on the list of unique CASRNs identified by the EPA 

(Appendix H). Only one of the 263 chemicals was reported at greater than 1% of wells, which suggests that these 

chemicals were used at only a few sites. 
Executive Summary

ES-21 

Chemical Name (CASRN)a Percent of FracFocus 1.0 disclosuresb

Quartz (14808-60-7)c 36

Glutaraldehyde (111-30-8) 34

Propargyl alcohol (107-19-7) 33

Potassium hydroxide (1310-58-3) 29

Ethanol (64-17-5) 29

Acetic acid (64-19-7) 24

Citric acid (77-92-9) 24

2-Butoxyethanol (111-76-2) 21

Sodium chloride (7647-14-5) 21

Solvent naphtha, petroleum, heavy aromatic (64742-94-5) 21

Naphthalene (91-20-3) 19

2,2-Dibromo-3-nitrilopropionamide (10222-01-2) 16

Phenolic resin (9003-35-4) 14

Choline chloride (67-48-1) 14

Methenamine (100-97-0) 14

Carbonic acid, dipotassium salt (584-08-7) 13

1,2,4-Trimethylbenzene (95-63-6) 13

Quaternary ammonium compounds, benzyl-C12-16-alkyldimethyl, 

chlorides (68424-85-1) 12

Poly(oxy-1,2-ethanediyl)-nonylphenyl- hydroxy (mixture) 

(127087-87-0) 12

Formic acid (64-18-6) 12

Sodium chlorite (7758-19-2) 11

Nonyl phenol ethoxylate (9016-45-9) 11

Tetrakis(hydroxymethyl)phosphonium sulfate (55566-30-8) 11

Polyethylene glycol (25322-68-3) 11

Ammonium chloride (12125-02-9) 10

Sodium persulfate (7775-27-1) 10

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 that met selected quality assurance criteria. See Table 5-2 in Chapter 5.

c Quartz and water were reported as ingredients in additives, in addition to proppants and base fluids.
Executive Summary

ES-22 

Concentrated additives are delivered to the well site and stored until they are mixed with the base 

fluid and proppant and pumped down the oil and gas production well (Text Box ES-7). While the 

overall concentration of additives in hydraulic fracturing fluids is generally small (typically 2% or 

less of the total volume of the injected fluid), the total volume of additives delivered to the well site 

can be large. Because over 1 million gallons (3.8 million liters) of hydraulic fracturing fluid are 

generally injected per well, thousands of gallons of additives can be stored on site and used during 

hydraulic fracturing. 

As illustrated in Text Box ES-7, additives are often stored in multiple, closed containers [typically

200 gallons (760 liters) to 375 gallons (1,420 liters) per container] and moved around the site in 

hoses and tubing. This equipment is designed to contain additives and blended hydraulic fracturing 

fluid, but spills can occur. Changes in drinking water quality can occur if spilled fluids reach 

groundwater or surface water resources. 

Several studies have documented spills of hydraulic fracturing fluids or additives. Nearly all of these 

studies identified spills from state-managed spill databases. Data gathered for these studies suggest 

that spills of hydraulic fracturing fluids or additives were primarily caused by equipment failure or 

human error. For example, an EPA analysis of spill reports from nine state agencies, nine oil and gas 

well operators, and nine hydraulic fracturing service companies characterized 151 spills of 

hydraulic fracturing fluids or additives on or near well sites in 11 states between January 2006 and 

April 2012 (U.S. EPA, 2015m). These spills were primarily caused by equipment failure (34% of the 

spills) or human error (25%), and more than 30% of the spills were from fluid storage units (e.g., 

tanks, totes, and trailers). Similarly, a study of spills reported to the Colorado Oil and Gas 

Conservation Commission identified 125 spills during well stimulation (i.e., a part of the life of an 

oil and gas well that often, but not always, includes hydraulic fracturing) between January 2010 and 

August 2013 (COGCC, 2014). Of these spills, 51% were caused by human error and 46% were due 

to equipment failure.

Studies of spills of hydraulic fracturing fluids or additives provide insights on spill volumes, but 

little information on chemical-specific spill composition. Among the 151 spills characterized by the 

EPA, the median volume of fluid spilled was 420 gallons (1,600 liters), although the volumes spilled 

ranged from 5 gallons (19 liters) to 19,320 gallons (73,130 liters). Spilled fluids were often 

described as acids, biocides, friction reducers, crosslinkers, gels, and blended hydraulic fracturing 

fluid, but few specific chemicals were mentioned.1 Considine et al. (2012) identified spills related to 

oil and gas development in the Marcellus Shale that occurred between January 2008 and August 

2011 from Notices of Violations issued by the Pennsylvania Department of Environmental 

Protection. The authors identified spills greater than 400 gallons (1,500 liters) and spills less than 

400 gallons (1,500 liters). 

 

1 A crosslinker is an additive that increases the thickness of gelled fluids by connecting polymer molecules in the gelled 

fluid. 
Executive Summary

ES-23 

Text Box ES-7. Chemical Mixing Equipment. 

Spills of hydraulic fracturing fluids or additives have reached, and therefore impacted, surface 

water resources. Thirteen of the 151 spills characterized by the EPA were reported to have reached 

a surface water body (often creeks or streams). Among the 13 spills, reported spill volumes ranged 

from 28 gallons (105 liters) to 7,350 gallons (27,800 liters). Additionally, Brantley et al. (2014) and 

Considine et al. (2012) identified fewer than 10 total instances of spills of additives and/or 

hydraulic fracturing fluids greater than 400 gallons (1,500 liters) that reached surface waters in 
Executive Summary

ES-24 

Pennsylvania between January 2008 and June 2013. Reported spill volumes for these spills ranged 

from 3,400 gallons (13,000 liters) to 227,000 gallons (859,000 liters).

Although impacts on surface water resources have been documented, site-specific studies that 

could be used to describe factors that affect the frequency or severity of impacts were not available. 

In the absence of such studies, we relied on fundamental scientific principles to identify factors that 

affect how hydraulic fracturing fluids and chemicals can move through the environment to drinking 

water resources. Because these factors influence whether spilled fluids reach groundwater and 

surface water resources, they affect the frequency and severity of impacts on drinking water 

resources from spills during the chemical mixing stage of the hydraulic fracturing water cycle. 

The potential for spilled fluids to impact groundwater or surface water resources depends on the 

characteristics of the spill, the environmental fate and transport of the spilled fluid, and spill 

response activities (Figure ES-5). Site-specific characteristics affect how spilled liquids move 

through soil into the subsurface or over the land surface. Generally, highly permeable soils or 

fractured rock can allow spilled liquids to move quickly into and through the subsurface, limiting 

the opportunity for spilled liquids to move over land to surface water resources. In low 

permeability soils, spilled liquids are less able to move into the subsurface and are more likely to 

move over the land surface. In either case, the volume spilled and the distance between the location 

of the spill and nearby water resources affects whether spilled liquids reach drinking water 

resources. Large-volume spills are generally more likely to reach drinking water resources because 

they are more likely to be able to travel the distance between the location of the spill and nearby 

water resources. 

In general, chemical and physical properties, which depend on the identity and structure of a 

chemical, control whether spilled chemicals evaporate, stick to soil particles, or move with water. 

The EPA identified measured or estimated chemical and physical properties for 455 of the 1,084

chemicals used in hydraulic fracturing fluids between 2005 and 2013.1 The properties of these 

chemicals varied widely, from chemicals that are more likely to move quickly through the 

environment with a spilled liquid to chemicals that are more likely to move slowly through the 

environment because they stick to soil particles.2 Chemicals that move slowly through the 

environment may act as longer-term sources of contamination if spilled.

 

1 Chemical and physical properties were identified using EPI SuiteTM. EPI SuiteTM is a collection of chemical and physical

property and environmental fate estimation programs developed by the EPA and Syracuse Research Corporation. It can 

be used to estimate chemical and physical properties of individual organic compounds. Of the 1,084 hydraulic fracturing 

fluid chemicals identified by the EPA, 629 were not individual organic compounds, and thus EPI SuiteTM could not be used 

to estimate their chemical and physical properties.

2 These results describe how some hydraulic fracturing chemicals behave in infinitely dilute aqueous solutions, which is a 

simplified approximation of the real-world mixtures found in hydraulic fracturing fluids. The presence of other chemicals 

in a mixture can affect the fate and transport of a chemical.
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Figure ES-5. Generalized depiction of factors that influence whether spilled hydraulic 

fracturing fluids or additives reach drinking water resources, including spill characteristics, 

environmental fate and transport, and spill response activities.

Spill prevention practices and spill response activities are designed to prevent spilled fluids from 

reaching groundwater or surface water resources and minimize impacts from spilled fluids. Spill 

prevention and response activities are influenced by federal, state, and local regulations and 

company practices. Spill prevention practices include secondary containment systems (e.g., liners 

and berms), which are designed to contain spilled fluids and prevent them from reaching soil, 

groundwater, or surface water. Spill response activities include activities taken to stop the spill, 

contain spilled fluids (e.g., the deployment of emergency containment systems), and clean up 

spilled fluids (e.g., removal of contaminated soil). It was beyond the scope of this report to evaluate 

the implementation and efficacy of spill prevention practices and spill response activities.

The severity of impacts on water quality from spills of hydraulic fracturing fluids or additives 

depends on the identity and amount of chemicals that reach groundwater or surface water 

resources, the toxicity of the chemicals, and the characteristics of the receiving water resource.1

Characteristics of the receiving groundwater or surface water resource (e.g., water resource size 

and flow rate) can affect the magnitude and duration of impacts by reducing the concentration of 

spilled chemicals in a drinking water resource. Impacts on groundwater resources have the 

 

1 Human health hazards associated with hydraulic fracturing fluid chemicals are discussed in Chapter 9 and summarized 

in the “Chemicals in the Hydraulic Fracturing Water Cycle” section below. 
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potential to be more severe than impacts on surface water resources because it takes longer to 

naturally reduce the concentration of chemicals in groundwater and because it is generally difficult

to remove chemicals from groundwater resources. Due to a lack of data, particularly in terms of 

groundwater monitoring after spill events, little is publicly known about the severity of drinking 

water impacts from spills of hydraulic fracturing fluids or additives. 

Chemical Mixing Conclusions

Spills of hydraulic fracturing fluids and additives during the chemical mixing stage of the hydraulic 

fracturing water cycle have reached surface water resources in some cases and have the potential 

to reach groundwater resources. Although the available data indicate that spills of various volumes 

can reach surface water resources, large volume spills are more likely to travel longer distances to 

nearby groundwater or surface water resources. Consequently, large volume spills likely increase 

the frequency of impacts on drinking water resources. Large volume spills, particularly of 

concentrated additives, are also likely to result in more severe impacts on drinking water resources 

than small volume spills because they can deliver a large quantity of potentially hazardous 

chemicals to groundwater or surface water resources. Impacts on groundwater resources are likely 

to be more severe than impacts on surface water resources because of the inherent characteristics 

of groundwater. Spill prevention and response activities are designed to prevent spilled fluids from 

reaching groundwater or surface water resources and minimize impacts from spilled fluids.

Well Injection

Activity: The injection and movement of hydraulic fracturing fluids through the oil and gas 

production well and in the targeted rock formation. 

Relationship to Drinking Water Resources: Belowground pathways, including the production 

well itself and newly-created fractures, can allow hydraulic fracturing fluids or other fluids to reach 

underground drinking water resources.

Hydraulic fracturing fluids primarily move along two pathways during the well injection stage: the 

oil and gas production well and the newly-created fracture network. Oil and gas production wells 

are designed and constructed to move fluids to and from the targeted rock formation without 

leaking and to prevent fluid movement along the outside of the well. This is generally accomplished 

by installing multiple layers of casing and cement within the drilled hole (Text Box ES-2), 

particularly where the well intersects oil-, gas-, and/or water-bearing rock formations. Casing and 

cement, in addition to other well components (e.g., packers), can control hydraulic fracturing fluid 

movement by creating a preferred flow pathway (i.e., inside the casing) and preventing 

unintentional fluid movement (e.g., from the inside of the casing to the surrounding environment or 

vertically along the well from the targeted rock formation to shallower formations).1 An EPA survey 

of oil and gas production wells hydraulically fractured between approximately September 2009 and 

September 2010 suggests that hydraulically fractured wells are often, but not always, constructed 

 

1 Packers are mechanical devices installed with casing. Once the casing is set in the drilled hole, packers swell to fill the 

space between the outside of the casing and the surrounding rock or casing. 
Executive Summary

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with multiple casings that have varying amounts of cement surrounding each casing (U.S. EPA, 

2015n). Among the wells surveyed, the most common number of casings per well was two: surface 

casing and production casing (Text Box ES-2). The presence of multiple cemented casings that 

extend from the ground surface to below the designated drinking water resource is one of the 

primary well construction features that protects underground drinking water resources.

During hydraulic fracturing, a well is subjected to greater pressure and temperature changes than 

during any other activity in the life of the well. As hydraulic fracturing fluid is injected into the well, 

the pressure applied to the well increases until the targeted rock formation fractures; then pressure 

decreases. Maximum pressures applied to wells during hydraulic fracturing have been reported to 

range from less than 2,000 pounds per square inch (psi) [14 megapascals (MPa)] to approximately 

12,000 psi (83 MPa).1 A well can also experience temperature changes as cooler hydraulic 

fracturing fluid enters the warmer well. In some cases, casing temperatures have been observed to 

drop from 212°F (100°C) to 64°F (18°C). A well can experience multiple pressure and temperature 

cycles if hydraulic fracturing is done in multiple stages or if a well is re-fractured.2 Casing, cement, 

and other well components need to be able to withstand these changes in pressure and 

temperature, so that hydraulic fracturing fluids can flow to the targeted rock formation without 

leaking. 

The fracture network created during hydraulic fracturing is the other primary pathway along which 

hydraulic fracturing fluids move. Fracture growth during hydraulic fracturing is complex and 

depends on the characteristics of the targeted rock formation and the characteristics of the 

hydraulic fracturing operation. In general, rock characteristics, particularly the natural stresses 

placed on the targeted rock formation due to the weight of the rock above, affect how the rock 

fractures, including whether newly-created fractures grow vertically (i.e., perpendicular to the 

ground surface) or horizontally (i.e., parallel to the ground surface) (Text Box ES-8). Because 

hydraulic fracturing fluids are used to create and grow fractures, fracture growth during hydraulic 

fracturing can be controlled by limiting the rate and volume of hydraulic fracturing fluid injected 

into the well. 

Publicly available data on fracture growth are currently limited to microseismic and tiltmeter data 

collected during hydraulic fracturing operations in five shale plays in the United States. Analyses of 

these data by Fisher and Warpinski (2012) and Davies et al. (2012) indicate that the direction of 

fracture growth generally varied with depth and that upward vertical fracture growth was often on 

the order of tens to hundreds of feet in the shale formations studied (Text Box ES-8). One percent of 

the fractures had a fracture height greater than 1,148 feet (350 meters), and the maximum fracture 

height among all of the data reported was 1,929 feet (588 meters). These reported fracture heights 

suggest that some fractures can grow out of the targeted rock formation and into an overlying 

formation. It is unknown whether these observations apply to other hydraulically fractured rock 

formations because similar data from hydraulic fracturing operations in other rock formations are 

not currently available to the public. 

 

1 For comparison, average atmospheric pressure is approximately 15 psi.

2 In a multi-stage hydraulic fracturing operation, specific parts of the well are isolated and hydraulically fractured until 

the total desired length of the well has been hydraulically fractured.
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Text Box ES-8. Fracture Growth.

Fracture growth during hydraulic fracturing is complex and depends on the characteristics of the targeted rock 

formation and the characteristics of the hydraulic fracturing operation. 

 

The potential for hydraulic fracturing fluids to reach, and therefore impact, underground drinking 

water resources is related to the pathways along which hydraulic fracturing fluids primarily move 

during hydraulic fracturing: the oil and gas production well itself and the fracture network created 

during hydraulic fracturing. Because the well can be a pathway for fluid movement, the mechanical 

integrity of the well is an important factor that affects the frequency and severity of impacts from 
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the well injection stage of the hydraulic fracturing water cycle.1 A well with insufficient mechanical 

integrity can allow unintended fluid movement, either from the inside to the outside of the well 

(pathway 1 in Figure ES-6) or vertically along the outside of the well (pathways 2-5). The existence 

of one or more of these pathways can result in impacts on drinking water resources if hydraulic 

fracturing fluids reach groundwater resources. Impacts on drinking water resources can also occur

if gases or liquids released from the targeted rock formation or other formations during hydraulic 

fracturing travel along these pathways to groundwater resources.

Figure ES-6. Potential pathways for fluid movement in a cemented well. 

These pathways (represented by the white arrows) include: (1) a casing and tubing leak into the surrounding rock, 

(2) an uncemented annulus (i.e., the space behind the casing), (3) microannuli between the casing and cement, 

(4) gaps in cement due to poor cement quality, and (5) microannuli between the cement and the surrounding rock. 

This figure is intended to provide a conceptual illustration of pathways that can be present in a well and is not to 

scale.

 

1 Mechanical integrity is the absence of significant leakage within or outside of the well components.
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The pathways shown in Figure ES-6 can exist because of inadequate well design or construction 

(e.g., incomplete cement around the casing where the well intersects with water-, oil-, or gasbearing formations) or can develop over the well’s lifetime, including during hydraulic fracturing. 

In particular, casing and cement can degrade over the life of the well because of exposure to 

corrosive chemicals, formation stresses, and operational stresses (e.g., pressure and temperature 

changes during hydraulic fracturing). As a result, some hydraulically fractured oil and gas 

production wells may develop one or more of the pathways shown in Figure ES-6. Changes in 

mechanical integrity over time have implications for older wells that are hydraulically fractured 

because these wells may not be able to withstand the stresses applied during hydraulic fracturing. 

Older wells may also be hydraulically fractured at shallower depths, where cement around the 

casing may be inadequate or missing.

Examples of mechanical integrity problems have been documented in hydraulically fractured oil 

and gas production wells. In one case, hydraulic fracturing of an inadequately cemented gas well in 

Bainbridge Township, Ohio, contributed to the movement of methane into local drinking water 

resources.1 In another case, an inner string of casing burst during hydraulic fracturing of an oil well 

near Killdeer, North Dakota, resulting in a release of hydraulic fracturing fluids and formation fluids 

that impacted a groundwater resource. 

The potential for hydraulic fracturing fluids or other fluids to reach underground drinking water 

resources is also related to the fracture network created during hydraulic fracturing. Because fluids 

travel through the newly-created fractures, the location of these fractures relative to underground 

drinking water resources is an important factor affecting the frequency and severity of potential 

impacts on drinking water resources. Data on the relative location of induced fractures to 

underground drinking water resources are generally not available, because fracture networks are 

infrequently mapped and because there can be uncertainty in the depth of the bottom of the 

underground drinking water resource at a specific location. 

Without these data, we were often unable to determine with certainty whether fractures created 

during hydraulic fracturing have reached underground drinking water resources. Instead, we 

considered the vertical separation distance between hydraulically fractured rock formations and 

the bottom of underground drinking water resources. Based on computer modeling studies,

Birdsell et al. (2015a) concluded that it is less likely that hydraulic fracturing fluids would reach an 

overlying drinking water resource if (1) the vertical separation distance between the targeted rock 

formation and the drinking water resource is large and (2) there are no open pathways (e.g., 

natural faults or fractures, or leaky wells). As the vertical separation distance between the targeted 

rock formation and the underground drinking water resource decreases, the likelihood of upward 

migration of hydraulic fracturing fluids to the drinking water resource increases (Birdsell et al., 

2015a). 

Figure ES-7 illustrates how the vertical separation distance between the targeted rock formation 

and underground drinking water resources can vary across the United States. The two example 

 

1 Although ingestion of methane is not considered to be toxic, methane can pose a physical hazard. Methane can 

accumulate to explosive levels when allowed to exsolve (degas) from groundwater in closed environments.
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environments depicted in panels a and b represent the range of separation distances shown in 

panel c. In Figure ES-7a, there are thousands of feet between the bottom of the underground 

drinking water resource and the hydraulically fractured rock formation. These conditions are 

generally reflective of deep shale formations (e.g., Haynesville Shale), where oil and gas production 

wells are first drilled vertically and then horizontally along the targeted rock formation. 

Microseismic data and modeling studies suggest that, under these conditions, fractures created 

during hydraulic fracturing are unlikely to grow through thousands of feet of rock into 

underground drinking water resources. 

Figure ES-7. Examples of different subsurface environments in which hydraulic fracturing 

takes place. 

In panel a, there are thousands of feet between the base of the underground drinking water resource and the part 

of the well that is hydraulically fractured. Panel b illustrates the co-location of groundwater and oil and gas 

resources. In these types of situations, there is no separation between the shallowest point of hydraulic fracturing 

within the well and the bottom of the underground drinking water resource. Panel c shows the estimated 

distribution of separation distances for approximately 23,000 oil and gas production wells hydraulically fractured 

by nine service companies between 2009 and 2019 (U.S. EPA, 2015n). The separation distance is the distance along 

the well between the point of shallowest hydraulic fracturing in the well and the base of the protected 

groundwater resource (illustrated in panel a). The error bars in panel c display 95% confidence intervals.

When drinking water resources are co-located with oil and gas resources and there is no vertical 

separation between the hydraulically fractured rock formation and the bottom of the underground 

drinking water resource (Figure ES-7b), the injection of hydraulic fracturing fluids impacts the 

quality of the drinking water resource. According to the information examined in this report, the 

overall occurrence of hydraulic fracturing within a drinking water resource appears to be low, with 
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the activity generally concentrated in some areas in the western United States (e.g., the Wind River 

Basin near Pavillion, Wyoming, and the Powder River Basin of Montana and Wyoming).1 Hydraulic 

fracturing within drinking water resources introduces hydraulic fracturing fluid into formations 

that may currently serve, or in the future could serve, as a drinking water source for public or 

private use. This is of concern in the short-term if people are currently using these formations as a 

drinking water supply. It is also of concern in the long-term, because drought or other conditions 

may necessitate the future use of these formations for drinking water.

Regardless of the vertical separation between the targeted rock formation and the underground 

drinking water resource, the presence of other wells near hydraulic fracturing operations can 

increase the potential for hydraulic fracturing fluids or other subsurface fluids to move to drinking 

water resources. There have been cases in which hydraulic fracturing at one well has affected a 

nearby oil and gas well or its fracture network, resulting in unexpected pressure increases at the 

nearby well, damage to the nearby well, or spills at the surface of the nearby well. These well 

communication events, or “frac hits,” have been reported in New Mexico, Oklahoma, and other 

locations. Based on the available information, frac hits most commonly occur when multiple wells 

are drilled from the same surface location and when wells are spaced less than 1,100 feet (335 

meters) apart. Frac hits have also been observed at wells up to 8,422 feet (2,567 meters) away from 

a well undergoing hydraulic fracturing. 

Abandoned wells near a well undergoing hydraulic fracturing can provide a pathway for vertical 

fluid movement to drinking water resources if those wells were not properly plugged or if the plugs 

and cement have degraded over time. For example, an abandoned well in Pennsylvania produced a 

30-foot (9-meter) geyser of brine and gas for more than a week after hydraulic fracturing of a 

nearby gas well. The potential for fluid movement along abandoned wells may be a significant issue 

in areas with historic oil and gas exploration and production. Various studies estimate the number 

of abandoned wells in the United States to be significant. For instance, the Interstate Oil and Gas 

Compact Commission estimates that over 1 million wells were drilled in the United States prior to

the enactment of state oil and gas regulations (IOGCC, 2008). The location and condition of many of 

these wells are unknown, and some states have programs to find and plug abandoned wells. 

Well Injection Conclusions

Impacts on drinking water resources associated with the well injection stage of the hydraulic 

fracturing water cycle have occurred in some instances. In particular, mechanical integrity failures 

have allowed gases or liquids to move to underground drinking water resources. Additionally, 

hydraulic fracturing has occurred within underground drinking water resources in parts of the 

United States. This practice introduces hydraulic fracturing fluids into underground drinking water 

resources. Consequently, the mechanical integrity of the well and the vertical separation distance 

between the targeted rock formation and underground drinking water resources are important 

factors that affect the frequency and severity of impacts on drinking water resources. The presence 

of multiple layers of cemented casing and thousands of feet of rock between hydraulically fractured 

 

1 Section 6.3.2 in Chapter 6.
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rock formations and underground drinking water resources can reduce the frequency of impacts on

drinking water resources during the well injection stage of the hydraulic fracturing water cycle.

Produced Water Handling 

Activity: The on-site collection and handling of water that returns to the surface after hydraulic 

fracturing and the transportation of that water for disposal or reuse. 

Relationship to Drinking Water Resources: Spills of produced water can reach groundwater and 

surface water resources.

After hydraulic fracturing, the injection pressure applied to the oil or gas production well is 

released, and the direction of fluid flow reverses, causing fluid to flow out of the well. The fluid that 

initially returns to the surface after hydraulic fracturing is mostly hydraulic fracturing fluid and is 

sometimes called “flowback” (Text Box ES-9). As time goes on, the fluid that returns to the surface 

contains water and economic quantities of oil and/or gas that are separated and collected. Water 

that returns to the surface during oil and gas production is similar in composition to the fluid 

naturally found in the targeted rock formation and is typically called “produced water.” The term 

“produced water” is also used to refer to any water, including flowback, that returns to the surface 

through the production well as a by-product of oil and gas production. This latter definition of 

“produced water” is used in this report. 

Produced water can contain many constituents, depending on the composition of the injected 

hydraulic fracturing fluid and the type of rock hydraulically fractured. Knowledge of the chemical 

composition of produced water comes from the collection and analysis of produced water samples, 

which often requires advanced laboratory equipment and techniques that can detect and quantify 

chemicals in produced water. In general, produced water has been found to contain: 

• Salts, including those composed from chloride, bromide, sulfate, sodium, magnesium, and 

calcium;

• Metals, including barium, manganese, iron, and strontium; 

• Naturally-occurring organic compounds, including benzene, toluene, ethylbenzene, 

xylenes (BTEX), and oil and grease; 

• Radioactive materials, including radium; and

• Hydraulic fracturing chemicals and their chemical transformation products. 

The amount of these constituents in produced water varies across the United States, both within 

and among different rock formations. Produced water from shale and tight gas formations is 

typically very salty compared to produced water from coalbed methane formations. For example, 

the salinity of produced water from the Marcellus Shale has been reported to range from less than 

1,500 milligrams per liter (mg/L) of total dissolved solids to over 300,000 mg/L, while produced 

water from coalbed methane formations has been reported to range from 170 mg/L of total 
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Text Box ES-9. Produced Water from Hydraulically Fractured Oil and Gas Production Wells. 

Water of varying quality is a byproduct of oil and gas production. The composition and volume of produced water 

varies by well, rock formation, and time after hydraulic fracturing. Produced water can contain hydraulic fracturing 

fluid, formation water, and chemical transformation products.

dissolved solids to nearly 43,000 mg/L.1 Shale and sandstone formations also commonly contain 

radioactive materials, including uranium, thorium, and radium. As a result, radioactive materials 

have been detected in produced water from these formations.

Produced water volumes can vary by well, rock formation, and time after hydraulic fracturing. 

Volumes are often described in terms of the volume of hydraulic fracturing fluid used to fracture 

the well. For example, Figure ES-4 shows that wells in the Marcellus Shale typically produce 10-

30% of the volume injected in the first 10 years after hydraulic fracturing. In comparison, some 

wells in the Barnett Shale have produced 100% of the volume injected in the first three years. 

 

1 For comparison, the average salinity of seawater is approximately 35,000 mg/L of total dissolved solids.
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Because of the large volumes used for hydraulic fracturing [about 4 million gallons (15 million 

liters) per well in the Marcellus Shale and the Barnett Shale], hundreds of thousands to millions of 

gallons of produced water need to be collected and handled at the well site. The volume of water 

produced per day generally decreases with time, so the volumes handled on site immediately after 

hydraulic fracturing can be much larger than the volumes handled when the well is producing oil 

and/or gas (Text Box ES-9). 

Produced water flows from the well to on-site tanks or pits through a series of pipes or flowlines 

(Text Box ES-10) before being transported offsite via trucks or pipelines for disposal or reuse. 

While produced water collection, storage, and transportation systems are designed to contain 

produced water, spills can occur. Changes in drinking water quality can occur if produced water 

spills reach groundwater or surface water resources.

Produced water spills have been reported across the United States. Median spill volumes among the 

datasets reviewed for this report ranged from approximately 340 gallons (1,300 liters) to 1,000 

gallons (3,800 liters) per spill.1 There were, however, a small number of large volume spills. In 

North Dakota, for example, there were 12 spills greater than 21,000 gallons (79,500 liters), five 

spills greater than 42,000 gallons (160,000 liters), and one spill of 2.9 million gallons (11 million

liters) in 2015. Common causes of produced water spills included human error and equipment 

leaks or failures. Common sources of produced water spills included hoses or lines and storage 

equipment.

Spills of produced water have reached groundwater and surface water resources. In U.S. EPA 

(2015m), 30 of the 225 (13%) produced water spills characterized were reported to have reached 

surface water (e.g., creeks, ponds, or wetlands), and one was reported to have reached 

groundwater. Of the spills that were reported to have reached surface water, reported spill volumes 

ranged from less than 170 gallons (640 liters) to almost 74,000 gallons (280,000 liters). A separate 

assessment of produced water spills reported to the California Office of Emergency Services 

between January 2009 and December 2014 reported that 18% of the spills impacted waterways 

(CCST, 2015a). 

Documented cases of water resource impacts from produced water spills provide insights into the 

types of impacts that can occur. In most of the cases reviewed for this report, documented impacts 

included elevated levels of salinity in groundwater and/or surface water resources.2 For example, 

the largest produced water spill reported in this report occurred in North Dakota in 2015, when 

approximately 2.9 million gallons (11 million liters) of produced water spilled from a broken 

pipeline. The spilled fluid flowed into Blacktail Creek and increased the concentration of chloride 

and the electrical conductivity of the creek; these observations are consistent with an increase in 

water salinity. Elevated levels of electrical conductivity and chloride were also found downstream 

in the Little Muddy River and the Missouri River. In another example, pits holding flowback fluids 

overflowed in Kentucky in 2007. The spilled fluid reached the Acorn Fork Creek, decreasing the pH 

of the creek and increasing the electrical conductivity. 

 

1 See Section 7.4 in Chapter 7.

2 Groundwater impacts from produced water management practices are described in Chapter 8 and summarized in the 

“Wastewater Disposal and Reuse” section below.
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Text Box ES-10. On-Site Storage of Produced Water.

Water that returns to the surface after hydraulic fracturing is collected and stored on site in pits or tanks.

 
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Site-specific studies of historical produced water releases highlight the role of local geology in the 

movement of produced water through the environment. Whittemore (2007) described a site in 

Kansas where low permeability soils and rock caused produced water to primarily flow over the 

land surface to nearby surface water resources, reducing the amount of produced water that 

infiltrated soil. In contrast, Otton et al. (2007) explored the release of produced water and oil from 

two pits in Oklahoma. In this case, produced water from the pits flowed through thin soil and into 

the underlying, permeable rock. Produced water was also identified in deeper, less permeable rock. 

The authors suggest that produced water moved into the deeper, less permeable rock through 

natural fractures. Together, these studies highlight the role of preferential flow paths (i.e., paths of 

least resistance) in the movement of produced water through the environment. 

Spill response activities likely reduce the severity of impacts on groundwater and surface water 

resources from produced water spills. For example, in the North Dakota example noted above, 

absorbent booms were placed in the affected creek and contaminated soil and oil-coated ice were 

removed from the site. In another example, a pipeline leak in Pennsylvania spilled approximately 

11,000 gallons (42,000 liters) of produced water, which flowed into a nearby stream. In response, 

the pipeline was shut off, a dam was constructed to contain the spilled produced water, water was 

removed from the stream, and the stream was flushed with fresh water. In both examples, it was 

not possible to quantify how spill response activities reduced the severity of impacts on

groundwater or surface water resources. However, actions taken after the spills were designed to 

stop produced water from entering the environment (e.g., shutting off a pipeline), remove produced 

water from the environment (e.g., using absorbent booms), and reduce the concentration of 

produced water constituents introduced into water resources (e.g., flushing a stream with fresh 

water). 

The severity of impacts on water quality from spills of produced water depends on the identity and 

amount of produced water constituents that reach groundwater or surface water resources, the 

toxicity of those constituents, and the characteristics of the receiving water resource.1 In particular, 

spills of produced water can have high levels of total dissolved solids, which affects how the spilled 

fluid moves through the environment. When a spilled fluid has greater levels of total dissolved 

solids than groundwater, the higher-density fluid can move downward through groundwater 

resources. Depending on the flow rate and other properties of the groundwater resource, impacts 

from produced water spills can last for years. 

Produced Water Handling Conclusions

Spills of produced water during the produced water handling stage of the hydraulic fracturing 

water cycle have reached groundwater and surface water resources in some cases. Several cases of 

water resource impacts from produced water spills suggest that impacts are characterized by 

increases in the salinity of the affected groundwater or surface water resource. In the absence of 

direct pathways to groundwater resources (e.g., fractured rock), large volume spills are more likely 

to travel further from the site of the spill, potentially to groundwater or surface water resources. 

 

1 Human health hazards associated with chemicals detected in produced water are discussed in Chapter 9 and 

summarized in the “Chemicals in the Hydraulic Fracturing Water Cycle” section below. 
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Additionally, saline produced water can migrate downward through soil and into groundwater 

resources, leading to longer-term groundwater contamination. Spill prevention and response 

activities can prevent spilled fluids from reaching groundwater or surface water resources and 

minimize impacts from spilled fluids.

Wastewater Disposal and Reuse

Activity: The disposal and reuse of hydraulic fracturing wastewater.

Relationship to Drinking Water Resources: Disposal practices can release inadequately treated 

or untreated hydraulic fracturing wastewater to groundwater and surface water resources.

In general, produced water from hydraulically fractured oil and gas production wells is managed 

through injection in Class II wells, reuse in other hydraulic fracturing operations, or various

aboveground disposal practices (Text Box ES-11). In this report, produced water from hydraulically 

fractured oil and gas wells that is being managed through one of the above management strategies 

is referred to as “hydraulic fracturing wastewater.” Wastewater management choices are affected 

by cost and other factors, including: the local availability of disposal methods; the quality of 

produced water; the volume, duration, and flow rate of produced water; federal, state, and local 

regulations; and well operator preferences.

Available information suggests that hydraulic fracturing wastewater is mostly managed through 

injection in Class II wells. Veil (2015) estimated that 93% of produced water from the oil and gas 

industry was injected in Class II wells in 2012. Although this estimate included produced water 

from oil and gas wells in general, it is likely indicative of nationwide management practices for 

hydraulic fracturing wastewater. Disposal of hydraulic fracturing wastewater in Class II wells is 

often cost-effective, especially when a Class II disposal well is located within a reasonable distance 

from a hydraulically fractured oil or gas production well. In particular, large numbers of active Class 

II disposal wells are found in Texas (7,876), Kansas (5,516), Oklahoma (3,837), Louisiana (2,448), 

and Illinois (1,054) (U.S. EPA, 2016d). Disposal of hydraulic fracturing wastewater in Class II wells 

has been associated with earthquakes in several states, which may reduce the availability of 

injection in Class II wells as a wastewater disposal option in these states. 

Nationwide, aboveground disposal and reuse of hydraulic fracturing wastewater are currently 

practiced to a much lesser extent compared to injection in Class II wells, and these management 

strategies appear to be concentrated in certain parts of the United States. For example, 

approximately 90% of hydraulic fracturing wastewater from Marcellus Shale gas wells in 

Pennsylvania was reused in other hydraulic fracturing operations in 2013 (Figure ES-4a). Reuse in 

hydraulic fracturing operations is practiced in some other areas of the United States as well, but at 

lower rates (approximately 5-20%). Evaporation ponds and percolation pits have historically been 

used in the western United States to manage produced water from the oil and gas industry and have 

likely been used to manage hydraulic fracturing wastewater. Percolation pits, in particular, were

commonly reported to have been used to manage produced water from stimulated wells in Kern
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Text Box ES-11. Hydraulic Fracturing Wastewater Management.

Produced water from hydraulically fractured oil and gas production wells is often, but not always, considered a 

waste product to be managed. Hydraulic fracturing wastewater (i.e., produced water from hydraulically fractured 

wells) is generally managed through injection in Class II wells, reuse in other hydraulic fracturing operations, and 

various aboveground disposal practices.

Federal and state regulations affect aboveground disposal management options. For example, existing federal 

regulations generally prevent the direct release of wastewater pollutants to waters of the United States from 

onshore oil and gas extraction facilities east of the 98th meridian. However, in the arid western portion of the 

continental United States (west of the 98th meridian), direct discharges of wastewater from onshore oil and gas 

extraction facilities to waters of the United States may be permitted if the produced water has a use in agriculture 

or wildlife propagation and meets established water quality criteria when discharged.
Executive Summary

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County, California, between 2011 and 2014.1 Beneficial uses (e.g., livestock watering and irrigation) 

are also practiced in the western United States if the water quality is considered acceptable, 

although available data on the use of these practices are incomplete.

Aboveground disposal practices generally release treated or, under certain conditions, untreated

wastewater directly to surface water or the land surface (e.g., wastewater treatment facilities, 

evaporation pits, or irrigation). If released to the land surface, treated or untreated wastewater can 

move through soil to groundwater resources. Because the ultimate fate of the wastewater can be 

groundwater or surface water resources, the aboveground disposal of hydraulic fracturing 

wastewater, in particular, can impact drinking water resources. 

Impacts on drinking water resources from the aboveground disposal of hydraulic fracturing 

wastewater have been documented. For example, early wastewater management practices in the 

Marcellus Shale region in Pennsylvania included the use of wastewater treatment facilities that 

released (i.e., discharged) treated wastewater to surface waters (Figure ES-8). The wastewater 

treatment facilities were unable to adequately remove the high levels of total dissolved solids found 

in produced water from Marcellus Shale gas wells, and the discharges contributed to elevated levels 

of total dissolved solids (particularly bromide) in the Monongahela River Basin. In the Allegheny 

River Basin, elevated bromide levels were linked to increases in the concentration of hazardous 

disinfection byproducts in at least one downstream drinking water facility and a shift to more toxic 

brominated disinfection byproducts.2 In response, the Pennsylvania Department of Environmental 

Protection revised existing regulations to prevent these discharges and also requested that oil and 

gas operators voluntarily stop bringing certain kinds of hydraulic fracturing wastewater to facilities 

that discharge inadequately treated wastewater to surface waters.3 

The scientific literature and recent data from the Pennsylvania Department of Environmental 

Protection suggest that other produced water constituents (e.g., barium, strontium, and radium) 

may have been introduced to surface waters through the release of inadequately treated hydraulic 

fracturing wastewater. In particular, radium has been detected in stream sediments at or near 

wastewater treatment facilities that discharged inadequately treated hydraulic fracturing 

wastewater. Such sediments can migrate if they are disturbed during dredging or flood events. 

Additionally, residuals from the treatment of hydraulic fracturing wastewater (i.e., the solids or 

liquids that remain after treatment) are concentrated in the constituents removed during 

treatment, and these residuals can impact groundwater or surface water resources if they are not 

managed properly. 

 

1 Hydraulic fracturing was the predominant stimulation practice. Other stimulation practices included acid fracturing and 

matrix acidizing. California updated its regulations in 2015 to prohibit the use of percolation pits for the disposal of fluids 

produced from stimulated wells.

2 Disinfection byproducts form through chemical reactions between organic material and disinfectants, which are used in 

drinking water treatment. Human health hazards associated with disinfection byproducts are described in Section 9.5.6 in 

Chapter 9. 

3 See Text Box 8-1 in Chapter 8.
Executive Summary

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Figure ES-8. Changes in wastewater management practices over time in the Marcellus Shale 

area of Pennsylvania.

Data from PA DEP (2015a). 

Impacts on groundwater and surface water resources from current and historic uses of lined and 

unlined pits, including percolation pits, in the oil and gas industry have been documented. For 

example, Kell (2011) reported 63 incidents of non-public water supply contamination from unlined 

or inadequately constructed pits in Ohio between 1983 and 2007, and 57 incidents of groundwater 

contamination from unlined produced water disposal pits in Texas prior to 1984. Other cases of 

impacts have been identified in several states, including New Mexico, Oklahoma, Pennsylvania, and

Wyoming.1 Impacts among these cases included the detection of volatile organic compounds in 

groundwater resources, wastewater reaching surface water resources from pit overflows, and 

wastewater reaching groundwater resources through liner failures. Based on documented impacts 

on groundwater resources from unlined pits, many states have implemented regulations that 

prohibit percolation pits or unlined storage pits for either hydraulic fracturing wastewater or oil 

and gas wastewater in general. 

The severity of impacts on drinking water resources from the aboveground disposal of hydraulic 

fracturing wastewater depends on the volume and quality of the discharged wastewater and the 

characteristics of the receiving water resource. In general, large surface water resources with high 

flow rates can reduce the severity of impacts through dilution, although impacts may not be 

eliminated. In contrast, groundwater is generally slow moving, which can lead to an accumulation 

of hydraulic fracturing wastewater contaminants in groundwater from continuous or repeated 

discharges to the land surface; the resulting contamination can be long-lasting. The severity of 

1 See Section 8.4.5 in Chapter 8.
Executive Summary

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impacts on groundwater resources will also be influenced by soil and sediment properties and 

other factors that control the movement or degradation of wastewater constituents. 

Wastewater Disposal and Reuse Conclusions

The aboveground disposal of hydraulic fracturing wastewater has impacted the quality of 

groundwater and surface water resources in some instances. In particular, discharges of 

inadequately treated hydraulic fracturing wastewater to surface water resources have contributed 

to elevated levels of hazardous disinfection byproducts in at least one downstream drinking water 

system. Additionally, the use of lined and unlined pits for the storage or disposal of oil and gas 

wastewater has impacted surface and groundwater resources. Unlined pits, in particular, provide a 

direct pathway for contaminants to reach groundwater. Wastewater management is dynamic, and 

recent changes in state regulations and practices have been made to limit impacts on groundwater 

and surface water resources from the aboveground disposal of hydraulic fracturing wastewater. 

Chemicals in the Hydraulic Fracturing Water Cycle

Chemicals are present in the hydraulic fracturing water cycle. During the chemical mixing stage of 

the hydraulic fracturing water cycle, chemicals are intentionally added to water to alter its 

properties for hydraulic fracturing (Text Box ES-6). Produced water, which is collected, handled,

and managed in the last two stages of the hydraulic fracturing water cycle, contains chemicals 

added to hydraulic fracturing fluids, naturally occurring chemicals found in hydraulically fractured 

rock formations, and any chemical transformation products (Text Box ES-9). By evaluating 

available data sources, we compiled a list of 1,606 chemicals that are associated with the hydraulic 

fracturing water cycle, including 1,084 chemicals reported to have been used in hydraulic 

fracturing fluids and 599 chemicals detected in produced water. This list represents a national 

analysis; an individual well would likely have a fraction of the chemicals on this list and may have 

other chemicals that were not included on this list.

In many stages of the hydraulic fracturing water cycle, the severity of impacts on drinking water 

resources depends, in part, on the identity and amount of chemicals that enter the environment. 

The properties of a chemical influence how it moves and transforms in the environment and how it

interacts with the human body. Therefore, some chemicals in the hydraulic fracturing water cycle 

are of more concern than others because they are more likely to move with water (e.g., spilled 

hydraulic fracturing fluid) to drinking water resources, persist in the environment (e.g., chemicals 

that do not degrade), and/or affect human health. 

Evaluating potential hazards from chemicals in the hydraulic fracturing water cycle is most useful 

at local and/or regional scales because chemical use for hydraulic fracturing can vary from well to 

well and because the characteristics of produced water are influenced by the geochemistry of 

hydraulically fractured rock formations. Additionally, site-specific characteristics (e.g., the local 

landscape, and soil and subsurface permeability) can affect whether and how chemicals enter 

drinking water resources, which influences how long people may be exposed to specific chemicals 

and at what concentrations. As a first step for informing site-specific risk assessments, the EPA 
Executive Summary

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compiled toxicity values for chemicals in the hydraulic fracturing water cycle from federal, state, 

and international sources that met the EPA’s criteria for inclusion in this report.1,2 

The EPA was able to identify chronic oral toxicity values from the selected data sources for 98 of the 

1,084 chemicals that were reported to have been used in hydraulic fracturing fluids between 2005 

and 2013. Potential human health hazards associated with chronic oral exposure to these chemicals 

include cancer, immune system effects, changes in body weight, changes in blood chemistry, 

cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and developmental 

toxicity. Of the chemicals most frequently reported to FracFocus 1.0, nine had toxicity values from 

the selected data sources (Table ES-3). Critical effects for these chemicals include kidney/renal 

toxicity, hepatotoxicity, developmental toxicity (extra cervical ribs), reproductive toxicity, and 

decreased terminal body weight.

Table ES-3. Available chronic oral reference values for hydraulic fracturing chemicals reported 

in 10% or more of disclosures in FracFocus 1.0. 

Chemical name (CASRN)a

Chronic oral 

reference value 

(mg/kg/day)

Critical effect

Percent of 

FracFocus 1.0 

disclosuresb

Propargyl alcohol (107-19-7) 0.002c Renal and hepatotoxicity 33

1,2,4-Trimethylbenzene (95-63-6) 0.01c Decreased pain sensitivity 13

Naphthalene (91-20-3) 0.02c Decreased terminal body 

weight 19

Sodium chlorite (7758-19-2) 0.03c Neuro-developmental 

effects 11

2-Butoxyethanol (111-76-2) 0.1c Hemosiderin deposition in 

the liver 23

Quaternary ammonium compounds, benzylC12-16-alkyldimethyl, chlorides (68424-85-1) 0.44d Decreased body weight 

and weight gain 12

Formic acid (64-18-6) 0.9e Reproductive toxicity 11

Ethylene glycol (107-21-1) 2c Kidney toxicity 47

Methanol (67-56-1) 2c Extra cervical ribs 73

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 35,957 disclosures that met selected quality assurance criteria. See Table 9-2 in Chapter 9.

c From the EPA Integrated Risk Information System database.

d From the EPA Human Health Benchmarks for Pesticides database.

e From the EPA Provisional Peer-Reviewed Toxicity Value database.

 

1 Specifically, the EPA compiled noncancer oral reference values and cancer oral slope factors (Chapter 9). A reference 

value describes the dose of a chemical that is likely to be without an appreciable risk of adverse health effects. In the 

context of this report, the term “reference value” generally refers to reference values for noncancer effects occurring via 

the oral route of exposure and for chronic durations. An oral slope factor is an upper-bound estimate on the increased 

cancer risk from a lifetime oral exposure to an agent. 

2 The EPA’s criteria for inclusion in this report are described in Section 9.4.1 in Chapter 9. Sources of information that met 

these criteria are listed in Table 9-1 of Chapter 9.
Executive Summary

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Chronic oral toxicity values from the selected data sources were identified for 120 of the 599

chemicals detected in produced water. Potential human health hazards associated with chronic oral 

exposure to these chemicals include liver toxicity, kidney toxicity, neurotoxicity, reproductive and 

developmental toxicity, and carcinogenesis. Chemical-specific toxicity values are included in 

Chapter 9. 

Chemicals in the Hydraulic Fracturing Water Cycle Conclusions

Some of the chemicals in the hydraulic fracturing water cycle are known to be hazardous to human 

health. Of the 1,606 chemicals identified by the EPA, 173 had chronic oral toxicity values from 

federal, state, and international sources that met the EPA’s criteria for inclusion in this report. 

These data alone, however, are insufficient to determine which chemicals have the greatest 

potential to impact drinking water resources and human health. To understand whether specific 

chemicals can affect human health through their presence in drinking water, data on chemical 

concentrations in drinking water would be needed. In the absence of these data, relative hazard 

potential assessments could be conducted at local and/or regional scales using the multi-criteria 

decision analysis approach outlined in Chapter 9. This approach combines available chemical 

occurrence data with selected chemical, physical, and toxicological properties to place the severity 

of potential impacts (i.e., the toxicity of specific chemicals) into the context of factors that affect the 

likelihood of impacts (i.e., frequency of use, and chemical and physical properties relevant to 

environmental fate and transport). 

Data Gaps and Uncertainties 

The information reviewed for this report included cases of impacts on drinking water resources 

from activities in the hydraulic fracturing water cycle. Using these cases and other data, 

information, and analyses, we were able to identify factors that likely result in more frequent or 

more severe impacts on drinking water resources. However, there were instances in which we 

were unable to form conclusions about the potential for activities in the hydraulic fracturing water 

cycle to impact drinking water resources and/or the factors that influence the frequency or severity 

of impacts. Below, we provide perspective on the data gaps and uncertainties that prevented us 

from drawing additional conclusions about the potential for impacts on drinking water resources 

and/or the factors that affect the frequency and severity of impacts.

In general, comprehensive information on the location of activities in the hydraulic fracturing water 

cycle is lacking, either because it is not collected, not publicly available, or prohibitively difficult to 

aggregate. This includes information on the: 

• Above- and belowground locations of water withdrawals for hydraulic fracturing; 

• Surface locations of hydraulically fractured oil and gas production wells, where the 

chemical mixing, well injection, and produced water handling stages of the hydraulic 

fracturing water cycle take place;

• Belowground locations of hydraulic fracturing, including data on fracture growth; and

• Locations of hydraulic fracturing wastewater management practices, including the 

disposal of treatment residuals. 
Executive Summary

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There can also be uncertainty in the location of drinking water resources. In particular, depths of

groundwater resources that are, or in the future could be, used for drinking water are not always

known. If comprehensive data about the locations of both drinking water resources and activities in 

the hydraulic fracturing water cycle were available, it would have been possible to more completely

identify areas in the United States in which hydraulic fracturing-related activities either directly 

interact with drinking water resources or have the potential to interact with drinking water

resources.

In places where we know activities in the hydraulic fracturing water cycle have occurred or are

occurring, data that could be used to characterize the presence, migration, or transformation of

hydraulic fracturing-related chemicals in the environment before, during, and after hydraulic

fracturing were scarce. Specifically, local water quality data needed to compare pre- and posthydraulic fracturing conditions are not usually collected or readily available. The limited amount of

data collected before, during, and after activities in the hydraulic fracturing water cycle reduces the 

ability to determine whether these activities affected drinking water resources.

Site-specific cases of alleged impacts on underground drinking water resources during the well

injection stage of the hydraulic fracturing water cycle are particularly challenging to understand 

(e.g., methane migration in Dimock, Pennsylvania; the Raton Basin of Colorado; and Parker County, 

Texas1). This is because the subsurface environment is complex and below ground fluid movement 

is not directly observable. In cases of alleged impacts, activities in the hydraulic fracturing water 

cycle may be one of several causes of impacts, including other oil and gas activities, other industries, 

and natural processes. Thorough scientific investigations are often necessary to narrow down the 

list of potential causes to a single source at site-specific cases of alleged impacts. 

Additionally, information on chemicals in the hydraulic fracturing water cycle (e.g., chemical

identity; frequency of use or occurrence; and physical, chemical, and toxicological properties) is not

complete. Well operators claimed at least one chemical as confidential at more than 70% of wells

reported to FracFocus 1.0 (U.S. EPA, 2015a).2 The identity and concentration of these chemicals,

their transformation products, and chemicals in produced water would be needed to characterize

how chemicals associated with hydraulic fracturing activities move through the environment and

interact with the human body. Identifying chemicals in the hydraulic fracturing water cycle also 

informs decisions about which chemicals would be appropriate to test for when establishing prehydraulic fracturing baseline conditions and in the event of a suspected drinking water impact.

Of the 1,606 chemicals identified by the EPA in hydraulic fracturing fluid and/or produced water,

173 had toxicity values from sources that met the EPA’s criteria for inclusion in this report. Toxicity

values from these selected data sources were not available for 1,433 (89%) of the chemicals,

although many of these chemicals have toxicity data available from other data sources.3 Given the

1 See Text Boxes 6-2 (Dimock, Pennsylvania), 6-3 (Raton Basin), and 6-4 (Parker County, Texas) in Chapter 6. 

2 Chemical withholding rates in FracFocus have increased over time. Konschnik and Dayalu (2016) reported that 92% of 

wells reported in FracFocus 2.0 between approximately March 2011 and April 2015 used at least one chemical that was

claimed as confidential.

3 Chapter 9 describes the availability of data in other data sources. The quality of these data sources was not evaluated as

part of this report. 
Executive Summary

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large number of chemicals identified in the hydraulic fracturing water cycle, this missing 

information represents a significant data gap that makes it difficult to fully understand the severity 

of potential impacts on drinking water resources.

Because of the significant data gaps and uncertainties in the available data, it was not possible to 

fully characterize the severity of impacts, nor was it possible to calculate or estimate the national 

frequency of impacts on drinking water resources from activities in the hydraulic fracturing water 

cycle. We were, however, able to estimate impact frequencies in some, limited cases (i.e., spills of 

hydraulic fracturing fluids or produced water and mechanical integrity failures).1 The data used to 

develop these estimates were often limited in geographic scope or otherwise incomplete. 

Consequently, national estimates of impact frequencies for any stage of the hydraulic fracturing 

water cycle have a high degree of uncertainty. Our inability to quantitatively determine a national 

impact frequency or to characterize the severity of impacts, however, did not prevent us from 

qualitatively describing factors that affect the frequency or severity of impacts at the local level. 

Report Conclusions

This report describes how activities in the hydraulic fracturing water cycle can impact—and have 

impacted—drinking water resources and the factors that influence the frequency and severity of 

those impacts. It also describes data gaps and uncertainties that limited our ability to draw 

additional conclusions about impacts on drinking water resources from activities in the hydraulic 

fracturing water cycle. Both types of information—what we know and what we do not know—

provide stakeholders with scientific information to support future efforts. 

The uncertainties and data gaps identified throughout this report can be used to identify future 

efforts to further our understanding of the potential for activities in the hydraulic fracturing water 

cycle to impact drinking water resources and the factors that affect the frequency and severity of 

those impacts. Future efforts could include, for example, groundwater and surface water 

monitoring in areas with hydraulically fractured oil and gas production wells or targeted research 

programs to better characterize the environmental fate and transport and human health hazards 

associated with chemicals in the hydraulic fracturing water cycle. Future efforts could identify 

additional vulnerabilities or other factors that affect the frequency and/or severity of impacts. 

In the near term, decision-makers could focus their attention on the combinations of hydraulic 

fracturing water cycle activities and local- or regional-scale factors that are more likely than others

to result in more frequent or more severe impacts. These include: 

• Water withdrawals for hydraulic fracturing in times or areas of low water availability, 

particularly in areas with limited or declining groundwater resources; 

• Spills during the management of hydraulic fracturing fluids and chemicals or produced 

water that result in large volumes or high concentrations of chemicals reaching 

groundwater resources; 

 

1 See Chapter 10.
Executive Summary

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• Injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, 

allowing gases or liquids to move to groundwater resources;

• Injection of hydraulic fracturing fluids directly into groundwater resources; 

• Discharge of inadequately treated hydraulic fracturing wastewater to surface water 

resources; and

• Disposal or storage of hydraulic fracturing wastewater in unlined pits, resulting in

contamination of groundwater resources.

The above combinations of activities and factors highlight, in particular, the vulnerability of 

groundwater resources to activities in the hydraulic fracturing water cycle. By focusing attention on 

the situations described above, impacts on drinking water resources from activities in the hydraulic 

fracturing water cycle could be prevented or reduced. 

Overall, hydraulic fracturing for oil and gas is a practice that continues to evolve. Evaluating the 

potential for activities in the hydraulic fracturing water cycle to impact drinking water resources 

will need to keep pace with emerging technologies and new scientific studies. This report provides 

a foundation for these efforts, while helping to reduce current vulnerabilities to drinking water 

resources. 
Executive Summary

ES-48 

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Chapter 1 – Introduction 

1-1 

Chapter 1. Introduction
Chapter 1 – Introduction 

1-2 

This page is intentionally left blank.
Chapter 1 – Introduction 

1-3 

1. Introduction

1.1 Background 

People rely on clean and plentiful water resources to meet their basic needs. In the early 2000s, 

members of the public began to raise concerns about the use of hydraulic fracturing for oil and gas 

production and its potential impacts on drinking water resources. Hydraulic fracturing involves the 

injection of fluids into a well under pressures great enough to fracture oil- and gas-bearing

formations. While hydraulic fracturing has been used to enhance oil and gas production from 

conventional rock formations, the combination of hydraulic fracturing and directional drilling has 

made it economical to produce oil and gas from previously unused unconventional rock 

formations.1 This has led to increases in oil and gas production and expanded activity throughout 

the United States. 

Concerns about the impacts of hydraulic fracturing activities on both the quality and quantity of 

drinking water resources have been raised by the public. Some residents living close to oil and gas 

production wells report changes in the quality of groundwater resources used for drinking water 

and assert that hydraulic fracturing is responsible for these changes. Other concerns include 

impacts on water availability due to water use in hydraulic fracturing, especially in areas of the 

country experiencing drought, and impacts on water quality from the disposal of wastewater 

generated after hydraulic fracturing. 

In response to public concerns, the U.S. Congress urged the U.S. Environmental Protection Agency 

(EPA) to study the relationship between hydraulic fracturing and drinking water (H.R. Rep. 111-

316, 2009). In 2011, the EPA published its Plan to Study the Potential Impacts of Hydraulic 

Fracturing on Drinking Water Resources (U.S. EPA, 2011d; hereafter Study Plan), which described 

the research the Agency would be conducting on activities involving water that support hydraulic 

fracturing (referred to as the “hydraulic fracturing water cycle”). The research described in the

Study Plan began the same year. In 2012, the EPA issued Study of the Potential Impacts of Hydraulic 

Fracturing on Drinking Water Resources: Progress Report (U.S. EPA, 2012h; hereafter Progress 

Report) to update the public on the status of EPA’s research. Since its initiation, the EPA’s hydraulic 

fracturing study has directly resulted in the publication of 27 separate government reports and

scientific journal articles. This assessment integrates results from those reports and scientific 

journal articles with publicly available data and information. It represents the culmination of the

EPA’s hydraulic fracturing study focused on characterizing the relationship between hydraulic

fracturing and drinking water. 

1 Conventional oil- and gas-bearing rock formations are often described as “permeable” and tend to have many large, wellconnected pore spaces that allow fluids to move within the rock formation. Unconventional oil- and gas-bearing rock 

formations do not exhibit these characteristics. See Chapter 3 for more information on uses of the terms conventional and 

unconventional. 
Chapter 1 – Introduction 

1-4 

1.2 Goals

The goals of this assessment are to assess the potential for activities in the hydraulic fracturing 

water cycle to impact the quality or quantity of drinking water resources and to identify factors that 

affect the frequency or severity of those impacts. 

1.3 Scope

The hydraulic fracturing water cycle defines the activities that are within the scope of this 

assessment. This cycle encompasses activities involving water that support hydraulic fracturing 

and consists of five stages: 

1. Water Acquisition: the withdrawal of groundwater or surface water to make hydraulic

fracturing fluids;

2. Chemical Mixing: the mixing of a base fluid (typically water), proppant, and additives at

the well site to create hydraulic fracturing fluids;1

3. Well Injection: the injection and movement of hydraulic fracturing fluids through the oil

and gas production well and in the targeted rock formation;

4. Produced Water Handling: the on-site collection and handling of water that returns to

the surface after hydraulic fracturing and the transportation of that water for disposal or

reuse; and 2

5. Wastewater Disposal and Reuse: the disposal and reuse of hydraulic fracturing

wastewater.3

The hydraulic fracturing water cycle, and thus the scope of this assessment, was developed with 

input from stakeholders (i.e., federal, state, and tribal partners; industry and non-governmental 

organizations; and the general public) and the EPA’s Science Advisory Board (SAB) (U.S. EPA, 

2011d). The hydraulic fracturing water cycle and our assessment scope reflect interest from 

stakeholders in understanding impacts from the act of hydraulic fracturing itself as well as the 

activities involving water that support it, without examining impacts from oil and gas production 

development broadly.

1 A base fluid is the fluid into which proppants and additives are mixed to make a hydraulic fracturing fluid; water is an 

example of a base fluid. Additives are chemicals or mixtures of chemicals that are added to the base fluid to change its 

properties. 

2 “Produced water” is defined in this report as water that flows from and through oil and gas wells to the surface as a byproduct of oil and gas production.

3 “Hydraulic fracturing wastewater” is defined in this report as produced water from hydraulically fractured oil and gas 

wells that is being managed using practices that include, but are not limited to, injection in Class II wells, reuse in other

hydraulic fracturing operations, and various aboveground disposal practices. The term “wastewater” is being used as a 

general description of certain waters and is not intended to constitute a term of art for legal or regulatory purposes. Class 

II wells are used to inject wastewater associated with oil and gas production underground and are regulated under the 

Underground Injection Control Program of the Safe Drinking Water Act. 
Chapter 1 – Introduction 

1-5 

Figure 1-1. Conceptualized view of the stages of the hydraulic fracturing water cycle.

Shown here is a generalized landscape depicting simplified activities of the hydraulic fracturing water cycle, their relationship to each other, and 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 groundwater 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 Disposal and Reuse” inset are (a) disposal via 

injection well, (b) wastewater treatment with reuse or discharge, and (c) evaporation or percolation pit disposal. Note: Figure not to scale. 
Chapter 1 – Introduction 

1-6 

This assessment focuses on hydraulic fracturing in onshore oil and gas wells in the contiguous

United States; limited available information on hydraulic fracturing in Alaska is included. To the 

extent possible, this assessment addresses hydraulic fracturing in all types of oil- and gas-bearing

formations in which it is conducted, including shale, so-called ‘tight’ formations (e.g., certain 

sandstones, siltstones, and carbonates), coalbeds, and conventional rock formations. The 

assessment tends to focus on hydraulic fracturing in shale, reflecting the abundance and availability

of literature and data on hydraulic fracturing in this type of rock formation. 

In this assessment, we consider how activities in the hydraulic fracturing water cycle interact with 

drinking water resources. Consistent with the Study Plan (U.S. EPA, 2011d), drinking water 

resources are defined within this assessment as any groundwater or surface water that now serves, 

or in the future could serve, as a source of drinking water for public or private use. This definition is 

broader than most regulatory definitions of “drinking water” to include both fresh and non-fresh 

bodies of water that are and could be used now or could be used in the future as sources of drinking 

water (Chapter 2). We note that drinking water resources provide not only water that individuals 

actually drink but also water used for many additional purposes such as cooking and bathing.

As part of the assessment, we evaluated immediate, near-term, and delayed effects on drinking 

water resources from normal operations and accidents. For example, we considered how surface 

spills of hydraulic fracturing fluids may have immediate or near-term impacts on neighboring 

surface water and shallow groundwater quality (Chapters 5 and 7). We also considered how the 

potential release of hydraulic fracturing fluids in the subsurface may take years to impact 

groundwater resources, because liquids and gas often move slowly in the subsurface (Chapter 6). 

Additionally, impacts may be transient or long-term, often depending on the characteristics of the 

affected drinking water resource. Finally, impacts may be detected near the hydraulic fracturing 

water cycle activity or some distance away. For instance, we considered that, depending on the 

constituents of treated hydraulic fracturing wastewater discharged to a stream and the flow in that 

stream, drinking water resource quality could be affected a significant distance downstream 

(Chapter 8).

This assessment focuses predominantly on activities supporting a single well or multiple wells at

one site, accompanied by a more limited discussion of cumulative activities and the impacts that 

could result from having many wells on a landscape. Studies of cumulative effects are generally 

lacking, but we use the scientific literature to address this topic where possible.1

We examine impacts of hydraulic fracturing for oil and gas on drinking water resources and address 

factors that affect the frequency or severity of impacts. Specific definitions used in this assessment 

are provided below:

• An impact is any change in the quality or quantity of drinking water resources, regardless

of severity, that results from an activity in the hydraulic fracturing water cycle.

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.
Chapter 1 – Introduction 

1-7 

• A factor is a feature of hydraulic fracturing operations or an environmental condition that

affects the frequency or severity of impacts.

• Frequency is the number of impacts per a given unit (e.g., per geographic area, per unit

time, per number of hydraulically fractured wells, per number of water bodies). Reflecting

the scientific literature, the most common representation of frequency in this assessment

is number of impacts per hydraulically fractured well.

• Severity is the magnitude of change in the quality or quantity of a drinking water resource

as measured by a given metric (e.g., duration, spatial extent, contaminant concentration).

We identify and discuss factors affecting the frequency or severity of impacts to avoid a simple 

inventory of all specific situations in which hydraulic fracturing might alter drinking water quality 

or quantity. This allows knowledge about the conditions under which impacts are likely or unlikely 

to occur to be applied to new circumstances (e.g., a new area of oil or gas development where 

hydraulic fracturing is expected to be used) and could inform the development of strategies to 

prevent impacts. Although no attempt has been made in this assessment to identify or evaluate 

comprehensive best practices for states, tribes, or the industry, we describe ways to avoid or 

reduce the frequency or severity of impacts from hydraulic fracturing activities as they have been 

reported in the scientific literature. Laws, regulations, and policies also exist to protect drinking 

water resources (Text Box 1-1), but a comprehensive summary and evaluation of current or 

proposed regulations and policies is beyond the scope of this assessment. 

Text Box 1-1. Regulatory Protection for Drinking Water Resources.

The quality and quantity of drinking water resources are protected in the United States by a collection of 

federal, state, tribal, and local laws, regulations, and polices. They differ with respect to how water resources 

are defined (Chapter 2) and thus which resources qualify for protection. Some policies protect water 

resources from oil and gas industry activities as part of a larger set of regulated industries, or from oil and gas 

industry activities only, or from hydraulic fracturing-related activities, specifically. Multiple federal and state 

agencies, departments, or divisions are responsible for implementing these laws, regulations, and policies. An 

exhaustive summary of current and emerging laws, regulations, and policies, those responsible for 

implementing them, and enforcement or effectiveness is not in the scope of this assessment. The following 

information is designed to give the reader a general understanding of how the U.S. government and states 

protect drinking water resources from the potential impacts of activities in the hydraulic fracturing water 

cycle. 

On the federal level, the U.S. government regulates some activities in the hydraulic fracturing water cycle to 

protect drinking water resources. For example, under the Clean Water Act, the National Pollution Discharge 

Elimination System (NPDES) program regulates surface discharge of wastewater from the oil and gas sector 

(in addition to many other industries). Issuance and enforcement of NPDES discharge permits is primarily the 

responsibility of the states that have received NPDES program authorization from the EPA. In addition, the 

Safe Drinking Water Act’s (SDWA) Underground Injection Control program regulates the underground 

disposal of hydraulic fracturing wastewater (and wastewater generated in other industries) and, like the

NPDES program, allows states to seek program authorization from the EPA. The federal government does not 

have the authority to regulate hydraulic fracturing as an injection activity under the SDWA except when it 

(Text Box 1-1 is continued on the following page.)
Chapter 1 – Introduction 

1-8 

Text Box 1-1 (continued). Regulatory Protection for Drinking Water Resources.

(1) involves diesel fuel, a result of legislation passed in 2005, or (2) causes an imminent and substantial 

endangerment to the health of persons. Additionally, produced water is exempted from regulation as a

hazardous waste under the Resource Conservation and Recovery Act Subtitle C. In 2015, the U.S. Department 

of the Interior published a set of regulations for conducting hydraulic fracturing operations on federal public 

and tribal lands. It includes requirements to help protect groundwater by updating standards for well 

mechanical integrity, wastewater disposal, and public disclosure of chemicals. As of late 2016, a federal 

district court judge has set aside these regulations as outside the scope of the U.S. Department of the 

Interior’s authority, and this decision is being appealed.

States generally have the primary responsibility for protecting drinking water resources from the impacts of 

hydraulic fracturing activities (Guralnick, 2016; Zirogannis et al., 2016). Some states have put in place broad 

restrictions or moratoria on hydraulic fracturing activities due in part to concerns about potential risks to 

drinking water resources. Many other states allow hydraulic fracturing activities, and several sources of 

information track and/or summarize their laws, regulations, and policies. An online database of statutes and 

regulations applicable to the oil and gas industry and related to water quality, water quantity, and air quality 

in 17 states is maintained by LawAtlas (www. lawatlas.org/oilandgas). 

State approaches vary widely, from comprehensive laws addressing all aspects of hydraulic fracturing

activities to regulations addressing specific activities (Guralnick, 2016). In 2009 and 2014, the Ground Water 

Protection Council (GWPC) summarized regulations that are designed to protect water resources and 

applicable to the oil and gas industry in 27 states; they did not investigate compliance (GWPC, 2014, 2009). 

The summaries revealed that regulations are carried out by either oil and gas agencies, environmental 

agencies, or both, depending on the state. They also identified general categories of existing regulations that 

could control impacts on drinking water resources from activities in the hydraulic fracturing water cycle, 

including permitting, well design and integrity, injection activities, and surface management of fluids. 

Categories were comprised of regulatory “elements.” Certain elements had been adopted across 90% or more 

of states included in the summaries that allowed hydraulic fracturing as of July 2013: surface casing generally 

must be set below the deepest protected groundwater zone; protected groundwater depth is determined on a 

well-specific basis or by rule; and surface casing must be cemented from bottom to top. All other elements 

were adopted at lower and widely varying rates. For example, as of July 2013, a requirement for water well 

testing and monitoring adjacent to hydraulic fracturing operations existed in five states. Other states, 

including California, have added this requirement since then. 

State laws, regulations, and policies are continually changing. Changes may be initiated by state legislatures 

or regulatory agencies (sometimes in response to legal decisions) and generally apply to new wells or future 

hydraulic fracturing operations and not existing wells or wells that have been hydraulically fractured in the 

past. Third-party groups, like the State Review of Oil and Natural Gas Environmental Regulations 

(STRONGER) organization, offer multi-stakeholder reviews of state oil and gas regulatory programs and 

recommendations to improve those programs according to guidelines developed by their workgroups. 

Interstate organizations of state agency representatives also have initiatives to develop oil and gas resources 

while protecting water and other environmental resources, initiatives like the GWPC and Interstate Oil and 

Gas Compact Commission’s States First. In combination with changing policies, new technologies (such as 

those that make it possible to reuse hydraulic fracturing wastewater in subsequent hydraulic fracturing 

operations) have the potential to further reduce impacts on drinking water resources.
Chapter 1 – Introduction 

1-9 

We identify and evaluate potential human health hazards of hydraulic fracturing-related chemicals 

(Chapter 9), but this assessment is not a human health risk assessment. It does not identify 

populations that are exposed to chemicals or other stressors in the environment, estimate the 

extent of exposure, or estimate the incidence of human health impacts. Relatedly, we did not 

conduct site-specific predictive modeling to quantitatively estimate contaminant concentrations in 

drinking water resources, although modeling studies conducted by others are described.

This assessment focuses on the potential for impacts from activities in the hydraulic fracturing 

water cycle on drinking water resources. It does not address all concerns that have been raised 

about hydraulic fracturing nor about oil and gas exploration and production more generally. 

Activities that are not considered in this assessment include acquisition and transport of 

constituents of hydraulic fracturing fluids besides water (e.g., sand mining and chemical 

production); site selection and development; other infrastructure development (e.g., roads, 

pipelines, compressor stations); site reclamation; and well closure. We consider these activities to 

be outside the scope of the hydraulic fracturing water cycle and, therefore, their impacts are not 

addressed in this assessment. Disposal of hydraulic fracturing wastewater in underground injection 

control wells is described and characterized, but consistent with the Study Plan, potential for 

impacts of this practice on drinking water resources is not included. Additionally, this report does 

not discuss the potential impacts of hydraulic fracturing on other water uses (e.g., agriculture or 

industry), other aspects of the environment (e.g., air quality, induced seismicity, or ecosystems),

worker health and safety, or communities. Finally, this assessment focuses on the available science 

and does not review, consider, or recommend policy options.

1.4 Approach 

This assessment relies on scientific literature and data that address topics within the scope of the 

hydraulic fracturing water cycle. Scientific journal articles and peer-reviewed EPA reports 

containing results from the EPA’s hydraulic fracturing study comprise one set of applicable 

literature. Other literature evaluated includes articles published in science and engineering 

journals, federal and state government reports, non-governmental organization (NGO) reports, and 

oil and gas industry publications. Data sources examined include federal- and state-collected data 

sets, databases curated by federal and state government agencies, other publicly available data and 

information, and data submitted by industry to the EPA.1 In total, we cite approximately 1,200 

sources of scientific data and information in this assessment.

1.4.1 EPA Hydraulic Fracturing Study Publications

The research topic areas and projects described in the Study Plan were developed with substantial 

expert and public input and were designed to meet the data and information needs of this 

assessment. As such, peer-reviewed results of research that the EPA conducted under the Study 

Plan, published separately as EPA reports or as journal articles, are incorporated and cited 

1 Confidential and non-confidential business 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. 
Chapter 1 – Introduction 

1-10 

frequently throughout this assessment. As is customary in assessments that synthesize a large body 

of literature and data, the results of EPA research are contextualized and interpreted in 

combination with the other literature and data described in Section 1.4.2. The journal articles and 

EPA reports that give complete and detailed project results can be found on the EPA’s hydraulic 

fracturing study website (www.epa.gov/hfstudy). For ease of reference, a description of the 

individual projects, the type of research activity they represent (i.e., analysis of existing data, 

scenario evaluation, laboratory study, or case study), and the corresponding citations of published 

journal articles and EPA reports that are referenced in this assessment can be found in Appendix A. 

1.4.2 Literature and Data Search Strategy

We used a broad search strategy to identify approximately 4,100 sources of scientific information 

applicable to this assessment. This strategy included requesting input from scientists, stakeholders, 

and the public about relevant data and information, and thorough searches of published 

information and applicable data.1 

Over 1,600 articles, reports, data, and other sources of information were obtained through outreach 

to the public, stakeholders, and scientific experts. The EPA requested material through many 

venues, as follows. We received recommended literature from the SAB, the EPA’s independent 

federal scientific advisory committee, from its review of the EPA’s draft Study Plan; from its 

consultation on the EPA’s Progress Report; during an SAB briefing on new and emerging 

information related to hydraulic fracturing in fall 2013; and from its peer review of the external 

review draft of this assessment. Subject matter experts and stakeholders also recommended 

literature through a series of technical workshops and roundtables organized by the EPA between 

2011 and 2013. In addition, the public submitted literature recommendations to the SAB during the 

SAB review of the draft Study Plan, consultation on the Progress Report, briefing on emerging 

information, and review of the external review draft of this assessment, as well as in response to a 

formal request for data and information posted in the Federal Register (EPA-HQ-ORD-2010-0674) 

in November 2012. The submission deadline was extended from April to November 2013 to 

provide the public with additional opportunity to provide information to the EPA. 

Approximately 2,500 additional sources were identified by conducting searches via online scientific 

databases and federal, state, and stakeholder websites. We searched these databases and websites 

in particular for (1) materials addressing topics not covered by the documents submitted by 

experts, stakeholders, and the public as noted above, and (2) newly emerging scientific studies. 

Multiple targeted and iterative searches on topics determined to be within the scope of the 

assessment were conducted until June 1, 2016. After that time, we included newer literature as it 

was recommended to us during our internal technical reviews or as it came to our attention and 

was determined to be important for filling a gap in information. 

1 This study did not review information contained in state and federal enforcement actions concerning alleged 

contamination of drinking water resources.
Chapter 1 – Introduction 

1-11 

1.4.3 Literature and Data Evaluation Strategy

We evaluated the literature and data identified in the search strategy using the five assessment 

factors outlined by the EPA Science Policy Council in A Summary of General Assessment Factors for 

Evaluating the Quality of Scientific and Technical Information (U.S. EPA, 2003c). The factors are (1) 

applicability and utility, (2) evaluation and review, (3) soundness, (4) clarity and completeness, and 

(5) uncertainty and variability. Table 1-1 lists these factors along with the specific criteria 

developed for this assessment. We first evaluated all materials for applicability. If we determined 

that the material was “applicable” under the criteria, the reference was evaluated on the basis of the 

other four factors. 

Our objective was to consider and then cite literature in the assessment that fully conforms to all 

criteria defining each assessment factor. However, in some cases, literature on a topic did not fully 

conform to an aspect of the outlined criteria. For instance, the preponderance of literature in some 

technical areas is published as white papers and reports for which independent peer review is not 

standard practice or is not well documented. To address these areas in which peer-reviewed 

literature was limited, we cited literature that may not have been peer-reviewed. These references 

often provided useful background information or corroborated conclusions in the peer-reviewed 

literature. 

Table 1-1. The five factors and accompanying criteria 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, 2003c). Criteria are 

incorporated into the Quality Assurance Project Plans for this assessment (U.S. EPA, 2014d, 2013d).

Factor Criteria

Applicability 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.

Review Document has been peer-reviewed.

Soundness Document relies on sound scientific theory and approaches, and conclusions are 

consistent with data presented.

Clarity/completeness Document provides underlying data, assumptions, procedures, and model parameters, 

as applicable, as well as information about sponsorship and author affiliations.

Uncertainty/variability Document identifies uncertainties, variability, sources of error, and/or bias and 

properly reflects them in any conclusions drawn. 

1.4.4 Quality Assurance and Peer Review

The use of quality assurance (QA) and peer review helps ensure that the EPA conducts high-quality 

science that can be used to inform policymakers, industry, and the public. Quality assurance 

activities performed by the EPA ensure that the agency’s environmental data are of sufficient 

quantity and quality to support the data’s intended use. The EPA prepared a programmatic Quality 
Chapter 1 – Introduction 

1-12 

Management Plan (U.S. EPA, 2014e) for all of the research conducted under the EPA’s Study Plan, 

including the review and synthesis of the scientific literature in this assessment. The hydraulic 

fracturing Quality Management Plan describes the QA program’s organizational structure; defines 

and assigns QA and quality control (QC) responsibilities; and describes the processes and 

procedures used to plan, implement, and assess the effectiveness of the quality system. The broad 

plan is then supported by more detailed QA Project Plans (QAPPs). The QAPPs developed for this 

assessment provide the technical approach and associated QA/QC procedures for our data and 

literature search and evaluation strategies introduced in Section 1.4.2 and 1.4.3 (U.S. EPA, 2014d, 

2013d). A QA audit was conducted by the QA Manager during the preparation of this assessment to 

verify that the appropriate QA procedures, criteria, reviews, and data verification were adequately 

performed and documented. Identifying uncertainties is another aspect of QA; uncertainty, 

including data gaps and data limitations, is discussed throughout this assessment. 

This report is classified as a Highly Influential Scientific Assessment (HISA), which is defined by the 

Office of Management and Budget (OMB) as a scientific assessment that (1) could have a potential 

impact of more than $500 million in any year or (2) is novel, controversial, or precedent-setting or 

has significant interagency interest (OMB, 2004). The OMB describes specific peer review 

requirements for HISAs. To meet these requirements, the EPA often engages the SAB as an 

independent federal advisory committee to conduct peer reviews of high-profile scientific matters 

relevant to the agency. Members of an ad hoc panel, the same panel that was convened under the 

auspices of the SAB to provide comment on the Progress Report, also provided comment on an 

external review draft of this assessment.1 Panel members were nominated by the public and chosen 

to create a balanced review panel based on factors such as technical expertise, knowledge, 

experience, and absence of any real or perceived conflicts of interest. Both peer review comments 

provided by the SAB panel (SAB, 2016) and public comments submitted to the panel during their 

deliberations about the external review draft of this assessment were carefully considered in the 

development of this final document. 

1.5 Organization 

This assessment begins with an Executive Summary that summarizes our overall content and 

conclusions. The Executive Summary is written to be accessible to all members of the public.2

This introductory chapter establishes the goals, scope, and approach for the rest of the assessment. 

Following is a characterization of drinking water resources in the contiguous United States

(Chapter 2). Next, we present a general description of hydraulic fracturing activities and the role of 

hydraulic fracturing in the oil and gas industry in the United States (Chapter 3). Chapter 1 is written 

 

1 Information about this process is available online at http://yosemite.epa.gov/sab/sabproduct.nsf/

02ad90b136fc21ef85256eba00436459/b436304ba804e3f885257a5b00521b3b!OpenDocument. 

2 The terminology used in the data and literature cited in this assessment can be very technical in nature and sometimes 

inconsistent. An attempt has been made throughout this document to provide definitions of technical terms and to use 

terminology in a consistent way that enhances understanding of the topics presented for the audiences targeted by each 

part of the assessment. 
Chapter 1 – Introduction 

1-13 

to be accessible to all members of the public. Chapters 2 and 3 are written to be accessible to an 

audience with general science knowledge.

Chapters 4 through 8 are organized around the stages of the hydraulic fracturing water cycle 

(Figure 1-1) and address the potential for activities conducted during those stages to change the 

quality or quantity of drinking water resources. Each stage is covered by a separate chapter. There 

is also a chapter devoted to an examination of the properties of the chemicals and constituents in 

hydraulic fracturing-related fluids (Chapter 9). These chapters are written to be accessible to an 

audience with a moderate amount of technical training and expertise in the respective topic areas. 

The final chapter provides a synthesis of the information in the assessment (Chapter 10). This 

chapter is written to be accessible to an audience with general science knowledge. 

The appendices supply information that support the chapters of the assessment. This includes an 

appendix with a table of all individual products published under the EPA’s hydraulic fracturing 

study and cited in this assessment, as well as answers to the research questions posed in the Study 

Plan (Appendix A). These answers were informed by the products of the study and the data and 

literature reviewed in this assessment.

1.6 Intended Use

This state-of-the-science assessment will contribute to the understanding of the potential impacts 

of activities in the hydraulic fracturing water cycle on drinking water resources and the factors that

influence those impacts. The data and findings can be used by federal, tribal, state, and local 

officials; industry; and the public to better understand and address vulnerabilities of drinking water 

resources to hydraulic fracturing activities.

We expect this report will be used to help facilitate and inform dialogue among interested 

stakeholders, including Congress, other federal agencies, states, tribal governments, the 

international community, industry, NGOs, academia, and the general public. Additionally, the 

identification of knowledge gaps will promote greater attention to these areas by researchers.

This report may support future assessment efforts. We anticipate that it could contribute context to 

site-specific exposure or risk assessments of hydraulic fracturing, to regional public health 

assessments, or to assessments of cumulative impacts of hydraulic fracturing on drinking water 

resources over time or over defined geographic areas of interest. 

Finally, and most importantly, this assessment presents the science to inform decisions by federal, 

state, tribal, and local officials; industry; and the public on how best to protect drinking water 

resources now and in the future.
Chapter 1 – Introduction 

1-14 

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Chapter 2 – Drinking Water Resources in the United States

2-1 

Chapter 2. Drinking Water 

Resources in the United States 

Abstract 

In this assessment, drinking water resources are defined as any body of groundwater or surface water 

that now serves, or in the future could serve, as a source of drinking water for public or private use. An 

estimated 86% of the United States population derives its household drinking water from public water 

systems (PWSs), which mostly use surface water sources, while nearly all of the remaining 14% of 

people self-supply their drinking water from groundwater. 

Future access to high-quality drinking water in the United States will likely be affected by changes in

climate and water use. The existing distribution and abundance of the drinking water resources may not 

be sufficient in some locations to meet future demand. Since 2000, about 30% of the total area of the 

contiguous United States has experienced moderate drought conditions and about 20% has experienced 

severe drought conditions, which often correlates with diminishment of drinking water supplies. As a 

result, non-fresh water resources, such as wastewater from sewage treatment plants, brackish surface 

water and groundwater, and seawater are increasingly treated and used to meet the demand for 

drinking water. 

Hydraulically fractured oil and gas production wells can be located near drinking water sources. 

Between 2000 and 2013, approximately 3,900 PWSs had between one and 144 wells hydraulically 

fractured within 1 mile of their water source; these PWSs served more than 8.6 million people yearround in 2013. An additional 740,000 people self-supply their drinking water in counties where at least 

30% of the population relies on groundwater and where there were at least 400 hydraulically fractured 

wells. Belowground, hydraulic fracturing can occur in close vertical proximity to drinking water 

resources. Available data show that depths to hydraulically fractured rock formations containing oil and 

gas resources can range from less than 1,000 feet (300 meters) to more than 10,000 feet (3,000 meters), 

while drinking water resources may be found between a few tens of feet to as much as 8,000 feet (2,000 

meters) below the surface. The EPA found that, along individual wellbores, where data were available, 

the distance between these two resources ranged from no separation to more than 10,000 feet (3,000 

meters). There is considerable uncertainty in this range of values, however. In many cases, the lack of 

accessible information about the depth to the base of formations containing groundwater resources in 

need of current and future protection prevents calculation of a vertical separation distance.

The locations of drinking water resources relative to hydraulically fractured oil and gas production wells 

influence the potential for activities in the hydraulic fracturing water cycle to impact drinking water 

resources. With increased proximity, activities in the hydraulic fracturing water cycle have more 

potential to affect aboveground and belowground drinking water resources. 
Chapter 2 – Drinking Water Resources in the United States

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Chapter 2 – Drinking Water Resources in the United States

2-3 

2. Drinking Water Resources in the United States

2.1 Introduction 

Drinking water resources provide the water humans consume, cook with, bathe in, and need for 

other purposes. In this assessment, drinking water resources are considered to be any groundwater

or surface water that now serves, or in the future could serve, as a source of drinking water for 

public or private use. 1 This chapter provides information about drinking water resources in the 

United States, including current sources and indications of future trends for drinking water 

resources. Assessment of whether and where activities in the hydraulic fracturing water cycle may 

impact drinking water resources requires consideration, in part, of the locations of water and oil 

and gas resources and what physically separates them. More information about oil and gas 

resources and the areas of the United States where hydraulic fracturing occurs is described in 

Chapter 3, however this chapter focuses on the lateral (horizontal) and vertical distances between 

hydraulic fracturing operations and drinking water resources.

2.2 Ground and Surface Water Resources

All drinking water derives from the finite amount of water found on or below the earth’s surface. 

Fresh water serves as the source for most drinking water.2 To get an idea of the fresh water fraction 

of all water, this section presents an estimate of the earth’s water abundance. Shiklomanov (1993)

estimates the amounts of all water on earth, and here these amounts are expressed as the percent 

of the earth’s total water volume:

• Oceans account for about 96.5%.

• Saline groundwater, saline lakes, and water in the form of ice or vapor account for 2.7%.

• Fresh groundwater, swamps, lakes, and rivers account for the remaining 0.8%, of which

about 99% is groundwater.

Hydrologic Cycle. The process describing the movement of the earth’s water through the 

atmosphere, land, and oceans is referred to as the hydrologic cycle. Text Box 2-1 describes the 

hydrologic cycle, including the manner in which the finite amount of water on the earth moves 

through different locations during the stages of the cycle. On land, surface water and groundwater 

interact, shown in the text box as surface water infiltrating into the ground, and separately as an 

example of groundwater flowing into the river. Water consumption (for example when used for 

agriculture, incorporated into a product, or for drinking purposes), temporarily removes water 

1 In this chapter, a “drinking water source” means the body of water is now supplying, or is known to be capable of 

supplying drinking water. 

2 Published estimates of worldwide water supplies, such as by Shiklomanov, do not use a salinity threshold value to define 

“fresh” or “saline” water. “Fresh” water is characterized in these published estimates as serving as a source for domestic, 

agricultural, and industrial uses. As described further in Section 2.2.1.1, the term “fresh” in this chapter refers to water 

having total dissolved solids content up to 3,000 milligrams per liter.
Chapter 2 – Drinking Water Resources in the United States

2-4 

from one local place in the hydrologic cycle, but it may be returned to a different point in the 

hydrologic cycle. See Chapter 4 for additional discussion of water consumption.

Text Box 2-1. The Hydrologic Cycle. 

The finite amount of water and its movement on earth is often called the hydrologic cycle, depicted below. 

The three basic, and repeating, stages of this cycle include: 

1. Rainfall transfers water from the atmosphere into oceans or onto land, 

2. Water on land moves among surface water bodies and groundwater, and

3. Evaporation from land and the oceans returns water to the atmosphere. 

Rainwater and melted snow collect into rivers, lakes or other water bodies to become surface water, or 

infiltrates into the ground to become groundwater. Humans drink fresh surface and groundwater, and in 

some locations, ocean water treated by desalination. Water resides on land or in the ground for varying 

amounts of time before moving into another of stage of the hydrologic cycle. Residence times for water found 

in different land locations can range from days to millions of years, depending on the path water takes. 

Residence time affects water quality on land or in the ground because water dissolves natural earth salts 

when in contact with those materials. When water on or under land reaches the ocean, its salt content 

ultimately stays in the ocean because evaporation leaves behind dissolved salt creating freshwater vapor. 

Evaporation from land and the ocean contribute fresh water to the atmosphere where it can precipitate once 

again, thus completing a hydrologic cycle. As drawn in this depiction, evaporation includes the release of 

water vapor from plant leaves that originally entered plant root systems in a process known as transpiration.
Chapter 2 – Drinking Water Resources in the United States

2-5 

2.2.1 Groundwater Resources

Groundwater can be found in the subsurface nearly everywhere, but it varies in quality and 

quantity. Groundwater exists in that part of the hydrologic cycle where surface water infiltrates 

through soil into subsurface cracks and voids in rock, creating and sustaining aquifers, a natural 

process known as groundwater recharge.1 The opposite natural process from recharge is discharge, 

where groundwater flows to the surface at springs or through the bottoms of lakes and rivers.

Groundwater also includes water trapped in the pores of sedimentary rocks as they were 

deposited.

The scale of groundwater flow systems can be local, regional, or something in between. Local 

groundwater flows may be small enough to be measured in the tens of feet while regional 

groundwater flows may be large enough to be measured in hundreds of miles (Alley et al., 1999). 

Groundwater movement is related to the rate of groundwater recharge, gravity’s effect on the 

groundwater, and the permeability of the rock through which groundwater flows. Localized 

groundwater flow tends to occur along shallower flow paths with shorter overall residence times, 

whereas regional groundwater flow tends to occur along deeper flow paths with longer residence 

times (Winter et al., 1998). Text Box 2-1 depicts differences between local and regional flow 

regimes.

The U.S. Geological Survey (USGS) has mapped and described more than 60 principal aquifers in the 

United States, although these aquifers are not the only occurrences of groundwater (USGS, 2009).2

Although the depth to the water table can vary from ground surface to a few tens of feet below 

ground surface, the depth to the base of groundwater can be tens of thousands of feet below 

ground.3 The depth to the base of individual principal aquifers can be a relatively uniform or may 

vary by thousands of feet across the aquifer’s areal extent due to sloping geologic formations 

and/or changes in topography. 

2.2.1.1 Groundwater Quality

The quality of groundwater often correlates with its age, which ranges from days to millions of 

years (Alley et al., 1999; Freeze and Cherry, 1979a; Chebotarev, 1955).4 As explained in Text Box 

2-1, groundwater salinity tends to increase with increasing residence time due to gradual 

dissolution of contacted earth materials. Some groundwater can become very saline. These waters 

can result from exposure to soluble sedimentary rocks and/or concentration of salt content due to 

evaporation of liquid water in the subsurface (Zolfaghari et al., 2016; Levorsen, 1965). It is also 

possible that sea water was trapped in sediments during deposition in ancient oceans, which were 

subsequently buried over geologic time. There are instances where groundwater is found at great 

1 An aquifer is a water-bearing geologic formation, group of formations, or part of a formation. Groundwater is the water 

in an aquifer. 

2 Principal aquifers are defined as a regionally extensive aquifer or aquifer system that has the potential to be used to 

supply potable water. Principal aquifers in Puerto Rico and the U.S. Virgin Islands are included.

3 The water table refers to the top, or uppermost surface, of groundwater. Below the water table, the ground is saturated 

with water.

4 Groundwater age used here refers to how long the water has been in the ground.
Chapter 2 – Drinking Water Resources in the United States

2-6 

depths but is relatively fresh. This can be caused by groundwater moving from the surface to deep 

locations relatively quickly with little time to pick up dissolved solids and become saline. This 

phenomenon is more pronounced in mountains where rainwater or melted snow in upland areas 

supply groundwater that moves downward through steeply dipping, permeable sedimentary rock 

layers to reach great depths. Chemicals occurring naturally in groundwater include both inorganic 

(e.g., salts, metals) and organic (carbon-based) types.

Salinity variation. Salinity is often the principal characteristic used to describe the overall quality of 

groundwater. The term “fresh” groundwater often means groundwater containing no more than

1,000 milligrams per liter of total dissolved solids (mg/L TDS) but it is sometimes used to refer to 

groundwater containing no more than 3,000 mg/L TDS (Maupin et al., 2014; U.S. EPA, 2012e; 

Freeze and Cherry, 1979a). When characterizing groundwater quality, scientists generally consider

the relative abundance of sodium, calcium, potassium, magnesium, chloride, bicarbonate, and 

sulfate to account for the bulk of dissolved constituents (Freeze and Cherry, 1979a). Natural salinity 

ranges from less than 100 mg/L to over 300,000 mg/L TDS (Lauer et al., 2016; Clark and Veil, 

2009). Higher salinity groundwater can contribute to palatability problems, and in the very high 

salinity ranges, causes water to be unhealthful for human consumption (Ellis, 1997). People have a 

range of reactions to drinking water salinity. Some people object to the taste of drinking water 

having comparatively lower salinity levels while other people reach this objection threshold at 

higher salinity levels (Burlingame and Waer, 2002). Desalinating water containing salinity values of 

10,000 mg/L TDS to render it potable is technically and economically feasible (Esser et al., 2015).1

As a result, groundwater with salinity values up to 10,000 mg/L TDS is often defined as a protected 

groundwater resource under several laws, including the regulations implementing the federal Safe 

Drinking Water Act (SDWA) and the U.S. Bureau of Land Management (BLM) Onshore Order #2. 

The complete basis and standards for defining a protected groundwater in all locations within the 

United States is beyond the scope of this report. Additional information about protections given to 

groundwater is described in Chapter 1 in Text Box 1-1. 

Groundwater suitable for drinking is found within a large range of depths around the United States. 

The groundwater quality profile with depth varies around the United States. Feth (1965) described 

patterns in the relationship of depth to groundwater containing salinity ranging from 1,000 to 

3,000 mg/L TDS.2The patterns include: (1) large portions of the Southeast and middle Midwest 

have at least 1,000 ft (300 m) of separation between the land surface and groundwater containing 

1,000-3,000 mg/L TDS, and (2) significant portions of the Northeast, northern Midwest, and parts 

of the West have less than 500 ft (200 m) separating the land surface from groundwater containing 

1,000-3,000 mg/L TDS. The report does not contain information about the base or thickness of 

groundwater having certain quality. As a result, these depths represent minimum distances 

between the land surface and bottom depth of groundwater having this salinity range. 

 

1 For instance, desalination of sea water (approximately 35,000 mg/L TDS) now occurs in Florida, California, and Texas.

2 Salinity and total dissolved solids are frequently interchangeable terms. The vast majority of dissolved constituents in 

natural water are inorganic salts, although a minor fraction of dissolved constituents can be organic matter. Feth (1965)

maps groundwater found at ranges of depth with spans of salinity. Singular depth and salinity values are not present on 

the map.
Chapter 2 – Drinking Water Resources in the United States

2-7 

Methane in groundwater. Methane can be found naturally at detectable levels in groundwater

(Kappel and Nystrom, 2012; Eltschlager et al., 2001; Coleman et al., 1988). There are different 

origins of methane in groundwater. Biogenic methane is produced at comparatively low 

temperature and pressure from biologic decay of carbon-bearing matter, while thermogenic 

methane is formed over geologic time when carbon-bearing matter is exposed to elevated pressure 

and temperature conditions typically associated with deep burial (Baldassare et al., 2014). Given 

the buoyancy of natural gas, if a pathway exists or enough time is available, it can move upward and 

accumulate at shallower depths. Natural gas found in small, uneconomic quantities in shallow zones 

may have originated in place or may have migrated upward, and is often referred to as stray gas. 

For more discussion about the issue of stray gas, see Text Box 6-3 in Chapter 6. When consumed in 

drinking water, methane does not generally have human health effects,1 however, it is an explosive 

gas if it comprises between 5% and 15% of a volume of air (Astle and Weast, 1984). If methane 

from well water enters the atmosphere within a confined space under conditions that allow it to 

concentrate, it can pose an explosive threat if it reaches this threshold.

2.2.1.2 Groundwater Quantity

Groundwater quantity can be characterized as the total subsurface water available, although a 

practical limiting property is the rate at which groundwater can be withdrawn from the subsurface, 

a property known as yield (Freeze and Cherry, 1979a). If rock formations in the subsurface contain 

water within exceedingly small or poorly connected pore spaces, then the low yield may preclude 

its practical use as a source of drinking water. 

When recharge and discharge are in balance, the volume of groundwater existing in the subsurface 

remains the same. Recharge and discharge also occur in connection with human-caused activity. 

Groundwater recharge increases due to irrigation, underground injection wells, surface 

impoundments, and dammed reservoirs, while groundwater discharge increases through well

withdrawals for irrigation, household use, etc. (Winter et al., 1998). These activities can locally 

affect the natural balance between groundwater recharge and discharge. Climatic variation that 

changes precipitation rates also affects groundwater recharge rates, which in turn leads to changes

in subsurface groundwater volume (Winter et al., 1998). 

When an aquifer consistently yields water at rates suitable for human use, and the water is of good 

enough quality to drink or be treated for drinking, it can serve as a source of drinking water. 

2.2.2 Surface Water Resources

Surface water is that part of the hydrologic cycle that occurs on land surface and includes water in 

the ocean as well as rainwater or meltwater. Surface water collects into depressions or along 

channels in sufficient volume to create standing or running water all or much of the time. Nonocean surface water has often had little time to become saline, because much of it is not in direct 

contact with anything other than more water in the surrounding surface water body. Non-ocean 

surface water can quickly move into the next phase of the hydrological cycle, either evaporating 

 

1 There is no enforceable drinking water standard established for dissolved methane in drinking water.
Chapter 2 – Drinking Water Resources in the United States

2-8 

into the atmosphere or infiltrating the subsurface. Because surface water is open to the atmosphere 

and is generally located at the lowest points on a landscape, it is susceptible to contamination. 

Contamination sources include atmospheric deposition, and run-off from urban land areas or lands 

used for agricultural or industrial activities (Winter et al., 1998). Many non-ocean surface water 

bodies in the United States have a set of water quality standards based on their designated use, 

which can include recreation, drinking water, supportive of aquatic life, fishery, industrial supply, 

and other uses. In turn, National Discharge Pollution Elimination (NPDES) permits governing point 

source discharge into the surface water bodies are issued under the Clean Water Act and contain 

limits on pollutants designed to achieve these water quality standards.1 When taken together, these 

permits are meant to ensure that the surface water achieves a water quality consistent with the 

designated use.

2.2.2.1 Surface Water Quality

Studies conducted in connection with the National Water Quality Assessment Program show the 

presence of human-made chemicals at low concentrations in the streams surveyed (Kingsbury et 

al., 2008).2 Based on dissolved solids alone, sampled streams range from less than 100 mg/L TDS to 

more than 500 mg/L TDS (Anning and Flynn, 2014). Large lakes can range in salinity from less than 

500 mg/L TDS to more than 200,000 mg/L. By comparison, ocean water has a salinity of about 

35,000 mg/L TDS. Considering the vast array of possible chemical, biological, and radiological 

content in surface water, it is beyond the scope of this report to describe in detail the surface water 

qualities that exist in the United States.

2.2.2.2 Surface Water Quantity

About 7% of the surface area of the United States is covered by surface water, but it is not uniformly 

distributed. The portion of the United States located east of the Mississippi River comprises about 

25% of the total area, yet it contains about 42% of the total land area covered by surface water

(USGS, 2016; U.S. Census Bureau, 2012).The Great Lakes alone, located in the eastern half of the 

United States, contain about one-fifth of the world’s surface fresh water (Government of Canada 

and U.S. EPA, 1995).3 In contrast, the western part of the United States has a lower proportion of 

land covered by surface water with streams that tend to be more intermittent in nature.4 For 

instance, 81 percent of the streams in Arizona, New Mexico, Nevada, Utah, Colorado, and California 

are not permanent streams (Levick et al., 2008). Certain parts of the western U.S. are presently 

experiencing less surface water availability as indicated by declining water reservoir levels with 

some reservoirs in the southwest currently below 50% of their capacity.5 For example, according to 

 

1 Title 40, United States Code of Federal Regulations, Part 131, as of May 25, 2016.

2 See USGS (2012) for more information about this program.

3 Including the portion of the Great Lakes lying within Canada.

4 Not all western states follow this trend. Hawaii and Alaska, for instance, have a significantly higher percentage of land 

mass covered by surface water (41% and 14%, respectively) than the national average.

5 See for instance U.S. DOI (2016b), California Department of Water Resources (2016), and SRP (2016). 
Chapter 2 – Drinking Water Resources in the United States

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the U.S. Department of the Interior (DOI), the largest capacity reservoir in the United States, Lake 

Mead, holds about 37% of its volume capacity as of the fall of 2016 (U.S. DOI, 2016a). 

2.3 Current Drinking Water Sources

Drinking water is supplied to households and businesses by either public water systems (PWSs) or

non-public systems (non-PWSs).1 In 2010, approximately 270 million people (86% of the 

population) in the United States relied on PWSs to supply their homes with drinking water (Maupin 

et al., 2014; U.S. EPA, 2013b). These PWSs provided households with nearly 24 billion gal (91 

billion L) of water per day (Maupin et al., 2014).2 In areas without service by PWSs, approximately 

45 million people (14% of the population) obtain drinking water from non-PWSs, using mostly 

water wells. Non-PWSs account for about 3.6 billion gal (14 billion L) of daily water withdrawals 

(Maupin et al., 2014).3

Both groundwater and surface water serve as drinking water sources in the United States. Surface 

water accounts for about 58% of all drinking water withdrawals and groundwater supplies the 

remaining 42%. Table 2-1 portrays the relative abundance of surface water and groundwater as 

sources for both publicly and non-publicly supplied drinking water.

Of the population receiving water supplied by PWSs, the relative importance of surface and 

groundwater sources for supplying drinking water varies geographically (Figure 2-1). Most larger 

PWSs rely on surface water and are located in urban areas (U.S. EPA, 2011c), whereas most smaller 

PWSs rely on groundwater and are located in rural areas (U.S. EPA, 2014h, 2013b). More than 95% 

of households in rural areas obtain their drinking water from groundwater (U.S. EPA, 2011c). 

PWSs are subject to routine monitoring and testing requirements required under the National 

Primary Drinking Water Standards regulations, whereas no such monitoring or testing is required 

for non-PWSs.4 The required monitoring and testing at PWSs ensures that the public has 

information regarding the extent to which delivered water meets drinking water standards, 

whereas users of non-PWSs (e.g., private water wells) make individual, voluntary decisions about 

how often they monitor and test their water. Lack of monitoring may make non-PWS users more 

vulnerable to contamination, if present, than PWS users.

 

1 PWSs provide water for human consumption from surface water or groundwater 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, 2012g). 

The EPA categorizes PWSs 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. Non-public water systems (non-PWSs) have fewer than 15 service connections and serve fewer than 25 

individuals (U.S. EPA, 1991). Non-PWSs are often private water wells supplying drinking water to a singular residence.

2 The 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. Water withdrawals are distinguished from and are greater than 

water deliveries due to water loss during the process of delivering finished water (Maupin et al., 2014; USGS, 2014b). 

3 A withdrawal means the volume of water taken from its source regardless of how much of that volume is either returned 

to the local hydrologic cycle or is consumed without being returned to the local hydrologic cycle. 

4 See Title 40 of the Code of Federal Regulations, Part 141, promulgated pursuant to the SDWA.
Chapter 2 – Drinking Water Resources in the United States

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Table 2-1. Summary of drinking water sources in the United States in 2010. 

The volume and percentages of daily domestic water withdrawals in the United States are shown by public and 

non-public water systems, total withdrawal, and whether the source is surface water or groundwater. Volume is in 

billions of gallons per day (Bgal/day) and percentages are of either water supply type or total volume withdrawn, 

as indicated in italics. Some figures shown are rounded values. Source of data: Maupin et al. (2014). 

Drinking water source

Public water 

supply

Non-public

water supply

Total volume 

withdrawn

Surface Water

Daily volume withdrawn (billion gallons) 26.3 0.1 26.4

Percent of water supply type 63 2 58

Groundwater 

Daily volume withdrawn (billion gallons) 15.7 3.5 19.2

Percent of water supply type 37 98 42

Total 

Daily volume withdrawn (billion gallons) 42.0 3.6 45.6

Percent of water supply type 92 8 100

Figure 2-1. Geographic variability in drinking water sources for public water systems.

The relative importance of surface and groundwater as sources for public water systems varies by state. The public 

water system sources used in this analysis include infiltration galleries, intakes, reservoirs, springs, and wells. 

Sources: ESRI (2010), U.S. Census Bureau (2013), and U.S. EPA (2013b). 
Chapter 2 – Drinking Water Resources in the United States

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2.3.1 Factors Affecting How Water Becomes a Drinking Water Source

The most common source of drinking water in the world, including in the United States, is fresh 

water (see Section 2.2.1.1). There can be exceptions to the use of fresh water as a drinking water 

source. For instance, projects in California, Florida, Arizona and Texas desalinate sea water or 

brackish groundwater to produce drinking water.1 The principle of supply and demand that affects 

availability of commercial products in the marketplace is also applicable to drinking water 

resources. Water not considered a practical drinking water source under one demand condition 

may become desirable as a drinking water source under different demand conditions. Text Box 2-2

presents El Paso, Texas as such an example. 

Text Box 2-2. El Paso’s Use of Higher Salinity Water for Drinking Water. 

The El Paso Water Utility (EPWU) provides drinking water to over 600,000 people in the City of El Paso, 

Texas and surrounding communities. Historically, the EPWU has withdrawn surface water from the Rio 

Grande River and groundwater to meet water needs. Salinity from the freshwater aquifers typically ranges 

between 300 and 1,000 mg/L TDS. With increases in population and periodic drought conditions stressing 

the water supply, the EPWU instituted a number of different measures to diversify its water supply portfolio. 

Components of the EPWU water supply portfolio include water conservation, surface water, groundwater 

and, more recently, desalinating saline groundwater. Continued long-term pumping of fresh groundwater 

allowed higher salinity groundwater to enter into one of EPWU’s well fields from more saline parts of the 

aquifer. This well field is now used as the source for the Kay Bailey Desalination Plant, which began operation 

in 2007 and desalinates groundwater with salinity ranging from 1,000 and 5,000 mg/L TDS (El Paso Water 

Utilities, 2016). The plant uses reverse osmosis technology to remove the high salt content thereby creating

additional fresh water supplies. Use of this higher salinity water supply has added approximately 25% more 

water availability, decreasing the stress on the original fresh water supplies available to the EPWU and 

highlights the potential value of groundwater that had not formerly been considered a drinking water source.

2.3.1.1 General Considerations Applicable to All Water as Source of Drinking Water

Factors to consider when assessing a possible source of drinking water include availability, 

contaminants in the water, and the cost to obtain and treat water. Surface water in streams, lakes, 

or reservoirs is almost always considered to be a source for drinking water, because they contain 

fresh, readily accessible water. Groundwater is a critically important drinking water source in many 

parts of the United States, especially where surface water is less abundant. Challenges for use as 

drinking water exist for both surface and groundwater. Surface water may not suffice as a drinking 

water source when it exists only temporarily or cannot supply the volume demand. Both surface 

water and groundwater may have contaminant levels that require expensive treatment technology. 

For instance, in an extensive report, the USGS describes how human activities cause unnaturally 

fast and deep groundwater movement, which degrades water quality over long periods in the 

 

1 Brackish water is often a general term used for water having a salinity content intermediate between fresh water and 

sea water, although it may also have a more specific definition, such as the 1,000 – 10,000 mg/L TDS value used in some 

USGS publications.
Chapter 2 – Drinking Water Resources in the United States

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nation’s principal aquifers (DeSimone et al., 2014). Despite these challenges, changes in the demand 

for water affect the consideration of sources of water for drinking purposes.

2.3.1.2 Considerations Applicable to Groundwater as a Drinking Water Source

Determining what groundwater is eligible for use as a drinking water source can include additional 

challenges. Groundwater may be located at significant depth or within low-yield aquifers, requiring 

additional engineering solutions to make them practical and/or cost effective as a drinking water 

source. Aquifers, or parts of aquifers, not in use today for drinking water purposes may nonetheless 

eventually be considered a drinking water source. The future viability of currently unused aquifers 

depends on the definition of what constitutes a drinking water resource and knowledge of the 

physical and chemical characteristics of the aquifers. The extent of knowledge about what exists in 

the subsurface depends on extrapolation from limited subsurface data (e.g., water samples 

collected from wells in, or passing through, aquifers). Although salinity is a common criterion for 

designating an aquifer as a drinking water resource (see Section 2.2.1.4), there is not a uniform 

threshold value for making that determination. The Groundwater Protection Council (GWPC) notes:

There is a great deal of variation between states with respect to defining protected 

groundwater. The reasons for these variations relate to factors such as the quality of water, 

the depth of Underground Sources of Drinking Water, the availability of groundwater, and 

the actual use of groundwater (GWPC, 2009).1

In addition to variation in applicable water quality criteria, the availability of information regarding 

groundwater that meets an applicable criterion (if one exists) is also variable. For instance, the 

bottom depth of aquifers or parts of aquifers that may be defined as a drinking water resource are 

not always readily publicly available. In some locations, such as the State of Texas, estimates of the 

bottom depth of groundwater meeting certain regulatory threshold criteria are made public on a 

website.2 In other parts of the United States the depth of identified protected subsurface drinking 

water resources may not be publicly available. No centralized compilation of groundwater depth 

and quality exists for all locations in the United States, nor does such a reference exist for depths to 

protected groundwater resources. The depths to protected groundwater resources can vary. In one 

example, the EPA described the reported bottom depths of protected groundwater resources as 

ranging from just below ground surface to 8,000 ft (2,000 m) (U.S. EPA, 2015n).3

Even in regions where the bottom depth of protected groundwater resources are generally known, 

there can remain uncertainty regarding precise depths at specific locations. Examples include the 

states of Indiana and Michigan according to the EPA Region 5 Underground Injection Control (UIC)

 

1 An underground source of drinking water (USDW) is defined in the federal regulations that implement the UIC program. 

A USDW is generally considered to be any aquifer, or its portion, that currently serves as a source for a public water 

system; or which contains enough groundwater to supply a public drinking water system, and either now supplies water 

for human consumption, or contains fewer than 10,000 mg/L TDS. See Title 40 of the Code of Federal Regulation, Section 

144.3. 

2 See http://www.beg.utexas.edu/sce/index.html. 

3 This reference provided 1,000-foot (305 meters) depth resolution for the reported base of protected groundwater.
Chapter 2 – Drinking Water Resources in the United States

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program, the State of Utah according to the Utah Geological Survey, and the State of California 

according to the California State Water Resources Board (Esser et al., 2015; Anderson et al., 2012; 

U.S. EPA, 2012e). In these examples, the depth to groundwater meeting the salinity threshold 

necessary for decision-making is stated not to be known with precision, and collection of additional 

groundwater quality information is advised.1

2.4 Future Drinking Water Sources

The future availability of fresh drinking water sources in the United States (Section 2.2.1.1) will 

likely be affected by changes in climate and water use (Georgakakos et al., 2014). Since 2000, about 

30% of the total area of the contiguous United States has experienced moderate drought conditions 

and about 20% has experienced severe drought conditions (National Drought Mitigation Center, 

2015; U.S. EPA, 2015p). Declines in surface water resources have already led to increased 

withdrawals and cumulative net depletions of groundwater in some areas (Castle et al., 2014; 

Georgakakos et al., 2014; Konikow, 2013; Famiglietti et al., 2011). Loss of approximately 240 mi3

(1,000 km3) of groundwater between 1900 and 2008 has been documented by the USGS. USGS

reports that about 20% of that loss occurred in the final eight years of that timeframe and that 

depletion is greater in the arid and semi-arid western states than in the more humid eastern states

(Konikow, 2013). Other sources of water that might not be considered fresh, such as wastewater 

from sewage treatment plants, brackish and saline surface and groundwater, as well as sea water, 

are also increasingly being used to meet water demand. Through treatment or desalination, these 

water sources can reduce the use of high-quality, potable fresh water for industrial processes, 

irrigation, recreation, and toilet flushing (i.e., non-potable uses). In addition, in 2010, approximately 

355 million gal per day (1.3 billion L per day) of treated wastewater was reclaimed through potable 

reuse projects (NRC, 2012). Such projects use reclaimed wastewater to augment surface drinking 

water sources or to recharge aquifers that supply drinking water to PWSs (NRC, 2012; Sheng, 

2005). In 2007, among approximately 13,000 desalination plants worldwide, there existed the 

capacity to produce about 14.7 billion gal (55.6 billion L) of fresh water each day. In 2005, the 

United States had approximately 11 % of that volume capacity (Gleick, 2008; Cooley et al., 2006). 

An increasing number of states are developing new water supplies to augment existing drinking 

water sources through reuse of reclaimed water, recycling of storm water, and desalination (U.S. 

GAO, 2014). Most desalination programs currently use brackish water as a source, although plans 

are underway to expand the use of sea water. States with the highest installed capacity for 

desalination include Florida, California, Arizona, and Texas (Cooley et al., 2006). It is likely that 

various water treatment technologies will continue to expand drinking water sources beyond those 

that are currently being considered. In addition to treatment technologies, there are efforts by 

public water systems to alleviate demand on drinking water supplies such as encouraging more 

modest consumer water usage and repairing leaks in water infrastructure. 

 

1 Decisions dependent on knowledge of threshold salinity values in groundwater can include permitting injection wells 

and oil and gas production well construction design approvals.
Chapter 2 – Drinking Water Resources in the United States

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2.5 Proximity of Drinking Water Resources to Hydraulic Fracturing Operations

Hydraulic fracturing in oil and gas production wells necessarily takes place where oil and gas 

resources are located. The relative locations of drinking water resources influences the degree to 

which they may be affected by activities in the hydraulic fracturing water cycle. With increased 

proximity, hydraulic fracturing activities have a greater potential to affect surface and subsurface 

sources of current and future drinking water (Vengosh et al., 2014; Entrekin et al., 2011). To 

estimate potentially vulnerability populations that use drinking water resources, the EPA 

performed an analysis of the number of hydraulically fractured production wells that are located 

within 1 mi (1.6 km) of a PWS source. The EPA also presents subsurface separation distances 

between the depths of drinking water resources and hydraulic fracturing in production wells.

2.5.1 Lateral Distance between Public Water System Sources and Hydraulic Fracturing

The EPA analyzed the locations of the approximately 275,000 oil and gas wells that were assumed 

to be hydraulically fractured in 25 states between 2000 and 2013 (Chapter 3) to determine the 

number of fractured wells within a 1-mile radius of facilities that withdraw water for a PWS.1,2,3

Based on 2000–2013 DrillingInfo data, the lateral distance from the nearest facility that withdraws 

water for PWS to a hydraulically fractured well ranged from 0.01 to 41 mi (0.02 to 66 km), with an 

average distance of 6.2 mi (10.0 km) and a median distance of 4.8 mi (7.7 km) (DrillingInfo, 2014a; 

U.S. EPA, 2014h). Of the approximately 275,000 wells that were estimated to have been 

hydraulically fractured in 25 states between 2000 and 2013, an estimated 21,900 (8%) were within 

1 mile of at least one PWS groundwater well or surface water intake. Most of these approximately 

6,800 individual facilities that withdraw water for a PWS were located in Colorado, Louisiana, 

Michigan, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, and Wyoming (Figure 2-2). These 

facilities that withdraw water for a PWS had an average of seven hydraulically fractured production 

wells and a maximum of 144 such production wells within a 1-mile radius. These water sources 

supplied water to 3,924 PWSs—1,609 of which are community water systems—that served more 

than 8.6 million people year-round in 2013 (U.S. EPA, 2014h; U.S. Census Bureau, 2013; U.S. EPA, 

2013b).4 

 

1 The EPA estimated the number of oil and gas production wells hydraulically fractured between 2000 and 2013. To do 

this, EPA assumed that all horizontal wells were hydraulically fractured in the year they started producing and assumed 

that all wells within a shale, coalbed, or low-permeability formation, regardless of well orientation, were hydraulically 

fractured in the year they started producing. More details are provided in U.S. EPA (2013c). Not all coalbed methane wells 

are hydraulically fractured, but coalbed methane wells represent production wells that sometimes uses hydraulic 

fracturing. Given that there were 15% of coalbed methane wells relative to all hydraulically fractured wells and the lack of 

data that distinguishes whether or not coalbed wells are hydraulically fractured, EPA included coalbed wells into all 

counts of wells that are hydraulically fractured.

2 The selected 1-mile distance used in this analysis provides a consistent approach. Local topographic conditions could 

support the use of a different analysis at any specific site.

3 A facility that withdraws water for a PWS includes water intakes, water wells, springs, infiltration galleries, and 

reservoirs. It is common for a PWS to operate multiple individual facilities to withdraw the cumulative water supplied by 

the PWS.

4 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 
Chapter 2 – Drinking Water Resources in the United States

2-15 

Figure 2-2. The location of public water system sources having hydraulically fractured wells

within 1 mile. 

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 DrillingInfo data were based on assumptions described in Chapter 3. Sources: DrillingInfo 

(2014), U.S. EPA (2013b), and ESRI (2010). 

The EPA also analyzed the location of hydraulically fractured wells relative to populations where a 

high proportion (≥30%, or at least twice the national average) obtain drinking water from nonPWSs (mostly private groundwater wells).1Based on DrillingInfo well location data and USGS 

drinking water data, between 2000 and 2013, approximately 3.6 million people live in counties 

 

fractured well. If non-community water systems are included, the estimated number of customers increases by 533,000 

people (U.S. EPA, 2012g). A community water system is a PWS which serves at least 15 service connections used by yearround residents or regularly serves at least 25 year-round residents.

1 There is no national data set of non-PWSs. In Maupin et al. (2014), the USGS estimates the proportion of the population 

reliant on non-PWSs, referred to as the “self-supplied population,” by county, based on estimates of the population 

without connections to a public water system. The USGS estimates were used for this analysis.
Chapter 2 – Drinking Water Resources in the United States

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with at least one hydraulically fractured well and where at least 30% of the population relies on 

non-PWSs for drinking water (DrillingInfo, 2014a; USGS, 2014b). The population changes to 

approximately 740,000 people living in counties with more than 400 hydraulically fractured wells 

and at least 30% of the population relies on non-PWSs for drinking water (DrillingInfo, 2014a; 

USGS, 2014b).1The counties having more than 400 hydraulically fractured wells and at least 30% of 

the population relying on non-PWSs for drinking water were located in Colorado, Kentucky, 

Michigan, Montana, New Mexico, New York, Oklahoma, Pennsylvania, Texas, and Wyoming. 

As described in Chapter 1, this assessment defines five stages in the hydraulic fracturing water 

cycle. The lateral distance analysis presented here relates to the wellhead locations of hydraulically 

fractured production wells, and therefore addresses three stages that take place near production 

wellheads, evaluated in Chapters 5, 6, and 7, respectively (chemical mixing, well injection, and 

produced water handling).2 A lateral distance analysis was not possible for the other two stages 

(water acquisition, wastewater disposal and reuse) because there is a lack information about where 

water is acquired for hydraulic fracturing and where the wastewater from any given hydraulically 

fractured well is disposed or treated.

2.5.2 Vertical Distance between Drinking Water Resources and Hydraulic Fracturing

The depth at which hydraulic fracturing takes place varies depending on the depth to the targeted 

production zone. For instance, in a study of wells representing approximately 23,000 production 

wells hydraulically fractured by nine service companies during 2009 and 2010, the EPA found that, 

when measured vertically from the surface to total depth, well depths ranged from less than 2,000 

ft (600 m) to more than 11,000 ft (3,000 m) (U.S. EPA, 2015n). Similarly, based on more than 

38,000 hydraulic fracturing disclosures to the FracFocus registry website, the middle 90% of these 

well disclosures had vertical depths between 2,900 and 13,000 ft (880 and 4,000 m) with a median 

value of about 8,100 ft (2,500 m) (U.S. EPA, 2015a). Hydraulic fracturing can occur at or near the 

bottom of a production well or it may take place at different intermediate depths depending on the 

location of economically producible oil and gas, and thus the total vertical depth of a production 

well does not necessarily correlate to the depth at which hydraulic fracturing occurs (Chapter 6). 

Hydraulic fracturing has been conducted at depths ranging from less than 1,000 ft (300 m) to 

greater than 10,000 ft (3,000 m) depth (U.S. EPA, 2015n; NETL, 2013). The distance from the base 

of the drinking water resource to the shallowest hydraulic fracturing initiation point in a 

production well serves as a separation distance.3 The EPA reports separation distances in depth 

measured along the well ranging from no separation distance (where hydraulic fracturing took 

 

1 Approximately 14% of the U.S. population is self-supplied by non-PWSs (Maupin et al., 2014). This analysis considers 

only counties in which more than double the national average—that is, at least 30% of the county’s population—was 

supplied by non-PWSs.

2 Chapter 7 (Produced Water Handling) examines potential effects on drinking water resources at hydraulically fractured 

wellhead locations, as well as away from wellhead locations.

3 If measured vertically from the shallowest hydraulic fracturing initiation point to the bottom of the drinking water 

resource, this is referred to as a vertical separation distance. If measured along a borehole from the shallowest hydraulic 

fracturing initiation point to the bottom of the drinking water resource, this is referred to as a separation distance in 

measured depth.
Chapter 2 – Drinking Water Resources in the United States

2-17 

place at depths shallower than the reported base of the drinking water resource) to more than 

10,000 ft (3,000 m) (U.S. EPA, 2015n). 

In a given setting, it is the geologic and hydrologic history that determines the depths to potential 

oil and gas and/or subsurface drinking water resources. In some settings, rock formations bearing 

economic quantities of oil or gas also contain groundwater that, based on salinity value alone, 

qualifies it as a drinking water resource. Large distances vertically separate these two resources in 

other settings. Figure 2-3 depicts two different types of these settings. 

Figure 2-3. Separation distance between drinking water resources and hydraulically fractured

intervals in wells

Schematic examples showing a relatively large separation distance (panel a) and the absence of any separation 

distance (panel b) between the shallowest fracture initiation depth in a well to the base of the protected drinking 

water resource. Distances may be presented as vertical or as a measured distance along a non-vertical well. Panel c 

shows result from wells studied representing approximately 23,000 production wells hydraulically fractured 

between 2009 and 2010 (U.S. EPA, 2015n). Error bars in panel c display 95% confidence intervals.

In Figure 2-3, panel (a), the hydraulically fractured oil- and gas-bearing zone is much deeper than 

drinking water resources, therefore separation distance is large. In panel (b), the hydraulically 

fractured oil- and gas-bearing zone is at the same depth as drinking water resources and there is no 

separation. The lack of separation distance can be due to the oil- and gas-bearing zone being 

shallow and/or the drinking water resource being deep. Panel (c) illustrates the distribution of 

separation distances in measured depth for study wells representing approximately 23,000 oil and 

gas production wells hydraulically fractured by nine service companies between 2009 and 2010, as 
Chapter 2 – Drinking Water Resources in the United States

2-18 

reported in U.S. EPA (2015n). The calculation of 95% confidence intervals shown in panel (c) is 

described in the EPA report and was affected by the number of companies in the study and the well 

file selection methods.

2.6 Conclusions

Drinking water resources provide the water humans consume, cook with, bathe in, and need for 

other purposes. An estimated 86% of the United States population derives its household drinking 

water from PWSs that serve at least 25 people. The remaining 14% self-supply their homes with 

drinking water from non-PWSs, which are largely private water wells. Publicly supplied drinking 

water is subject to monitoring and testing to determine compliance with drinking water standards 

while no such monitoring and testing is required at non-PWSs. Surface water is the source for an 

estimated 58% of the volume needed to supply drinking water and groundwater is the source for 

the remaining 42%. 

The existing distribution and abundance of the drinking water resources in the United States may 

not be sufficient in some locations to meet future demand. The future availability of sources of 

drinking water that are considered fresh will likely be affected by changes in climate and water use. 

Since at least 2000, many areas of the United States have experienced significant drought, which 

often correlate with diminishment of ground and surface water supplies in these areas. Locally, 

measures are now being implemented to prolong use of current drinking water sources such as 

encouraging more modest drinking water use and using treated wastewater or other non-potable 

water sources to help meet demand. 

Between 2000 and 2013, the EPA estimates there were approximately 275,000 oil and gas 

production wells hydraulically fractured in 25 states. To produce a consistent measure of proximity 

between these hydraulically fractured oil and gas production wells and drinking water resources 

during this time frame, the EPA counted the number hydraulically fractured oil and gas production 

wells located within 1 mile of public drinking water sources, and performed a count of the counties 

with a relatively high reliance on self-supplied drinking water that also contain one or more of 

these hydraulically fractured production wells. Between 2000 and 2013, approximately 3,900 

public water systems had between one and 144 wells hydraulically fractured within 1 mile of their 

water source; these public water systems served more than 8.6 million people year-round in 2013. 

An additional 740,000 people between 2000 and 2013 self-supplied their drinking water in

counties where at least 30% of the population relies on groundwater and having at least 400

hydraulically fractured wells. 

Depending on the nature of the geologic setting, hydraulically fractured oil and gas production 

wells can be located near where people get their drinking water. Depths to hydraulically fractured 

oil and gas resources can range from less than 1,000 ft (300 f) to more than 10,000 ft (3,000 m) 

while drinking water resources may be found between a few tens of feet to as much as 8,000 ft 

(2,000 m) below the surface. There is limited publicly available information to determine the 

vertical distance separating the shallowest hydraulic fracturing initiation point in a production well 

from the deepest drinking water resource. The EPA found, among 323 wells studied statistically 

representing more than 23,000 production wells hydraulically fractured by nine service companies 

between 2009 and 2010, the distance along the wells between these two resources ranged from 

none to more than 10,000 ft (3,000 m).
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Chapter 3. Hydraulic Fracturing for 

Oil and Gas in the United States

Abstract 

This chapter provides a general description of the practice of hydraulic fracturing, where it is conducted,

how prevalent it is, and how hydraulic fracturing-based oil and gas production fits into the context of 

energy production in the United States. Some of the information in this chapter also serves as an 

introduction to the more in-depth technical chapters in the assessment.

Hydraulic fracturing is a technique used to increase oil and gas production from underground oiland/or gas-bearing rock formations (reservoirs). The technique involves the injection of hydraulic 

fracturing fluids through the production well and into the reservoir under pressures great enough to 

fracture the reservoir rock. Hydraulic fracturing fluids typically consist mainly of water, a “proppant” 

(typically sand) that props open the created fractures, and additives (usually chemicals) that modify the 

properties of the fluid for fracturing. Fractures created during hydraulic fracturing enable better flow of 

oil and gas from the reservoir into the production well. Water that naturally occurs in the oil and gas 

reservoirs also typically flows into and through the production well to the surface as a byproduct of the 

oil and gas production process. 

Since the mid-2000s, the combination of modern hydraulic fracturing and directional drilling has 

become widespread and significantly contributed to a surge in oil and gas production in the United 

States. Slightly more than 50% of oil production and nearly 70% of gas production in 2015 is estimated 

to have occurred using hydraulic fracturing. Hydraulic fracturing is widely used in unconventional (low 

permeability) oil and gas reservoirs that include shales, so-called tight oil and tight gas formations, and 

coalbeds, but it is also used in conventional reservoirs. 

There is no comprehensive national database of wells that are hydraulically fractured in the United 

States. Using data from several commercial and public sources, the EPA estimates that 25,000 to 30,000 

new wells were drilled and hydraulically fractured in the United States annually between 2011 and 

2014. These hydraulic fracturing wells are geographically concentrated; in 2011 and 2012 almost half of 

hydraulic fracturing wells were located in Texas, and a little more than a quarter were located in the 

four states of Colorado, Pennsylvania, North Dakota, and Oklahoma. 

New drilling activity for hydraulic fracturing wells is generally linked with oil and gas prices, and those 

peaked in the United States between 2005 and 2008 for gas and between 2011 and 2014 for oil. 

Following price declines, the number of new hydraulically fractured wells in 2015 decreased to about 

20,000. Despite recent declines in prices and new drilling, U.S. gas and oil production continues at levels 

above those in recent decades, and production for both is predicted to continue growing in the long 

term, led by hydraulic fracture-based production from unconventional reservoirs.
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3. Hydraulic Fracturing for Oil and Gas in the 

United States

3.1 Introduction 

This chapter provides general background information on hydraulic fracturing and will help the 

reader understand the in-depth technical chapters that follow. We describe the purpose and 

process of hydraulic fracturing and the situations and settings in which it is used (Section 3.1). Then

we provide a general description of activities at a hydraulic fracturing well site including assessing 

and preparing the well site, well drilling and construction, the hydraulic fracturing event, the oil 

and gas production phase, and eventual site closure (Section 3.3). A characterization of the 

prevalence of hydraulic fracturing in the United States is then presented (Section 3.4), followed by a 

review of its current and future importance in the oil and gas industry and its role in the U.S. energy 

sector (Section 3.5), and a brief conclusion (Section 3.6).

3.2 What is Hydraulic Fracturing? 

Hydraulic fracturing is a technique used to increase oil and gas production from underground oilor gas-bearing rock formations (reservoirs).1 The technique involves the injection of hydraulic 

fracturing fluids through the production well and into the reservoir under pressures great enough 

to fracture the reservoir rock. The injected hydraulic fracturing fluid carries “proppant” (typically 

sand) into the fractures so that they remain propped open after the pressurized injection is 

stopped. In addition to water, which typically makes up most of the injected fracturing fluid, the 

fluid also contains chemical additives (additives) that serve a variety of purposes. These additives, 

for example, can increase the fluid viscosity (how “thick” the fluid is) so that it carries the proppant 

into the fractures more effectively, can help control well corrosion, can help minimize microbial 

growth in the well, and so on (King and Durham, 2015; Gupta and Valkó, 2007). The resulting 

fractures enable better flow of oil and gas from the reservoir into the production well. Water that 

naturally occurs in the reservoirs also typically flows into and through the production well to the 

surface as a byproduct of the production process.

Although hydraulic fracturing is not new, how and where it is employed has changed (Text Box 

3-1). For about a half-century after its introduction in the late 1940s, it was used to increase 

production from vertical wells in conventional oil and gas reservoirs. Conventional reservoirs 

develop over geologic time (many millions of years) when naturally buoyant oil and gas very slowly 

migrate upward from the shale rock formations in which they formed until they are trapped by 

geologic formations or structures and accumulate under a confining layer (Figure 3-1). As the oil 

and gas accumulate, the pressure may increase. If the reservoir is under enough pressure and has 

 

1 A version of hydraulic fracturing, sometimes called hydrofracturing or hydrofracking, can be used to increase water 

yields from water wells and is typically done by injecting only water under pressure. This application of hydraulic 

fracturing is out of the scope of this assessment. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-4 

Text Box 3-1. Hydraulic Fracturing: Not New, but Different and Still Changing.

From the mid-1800s to the 1940s, operators of oil and gas wells occasionally tried to increase production by 

pumping fluids or sometimes dropping explosives into wells. In the late 1940s, a fracturing technique to 

increase production was patented by the Stanolind Oil and Gas Company and licensed to the Halliburton Oil 

Well Cementing Company (Montgomery and Smith, 2010). Close to 1 million wells were hydraulically 

fractured from the late 1940s to about 2000 (IOGCC, 2002). The typical well design and hydraulic fracturing 

operations during most of that time, though, were very different from today’s modern hydraulic fracturing 

operations.

The groundwork for the transformation to modern hydraulic fracturing was laid in the 1970s and early 

1980s. Public-private research and development (R&D) partnerships that included industry, the Department 

of Energy, and the Gas Research Institute were established because large amounts of natural gas were known 

to occur in some shale rock formations yet traditional production well technology was not able to recover 

much of the gas (Avila, 1976). These R&D programs played a key role in advancing technologies such as deep 

horizontal drilling and fracturing with higher water volumes that ultimately enabled production from shales 

and other unconventional sources of gas and oil (DOE, 2015; NRC: Committee on Benefits of DOE R&D on 

Energy Efficiency and Fossil Energy, 2001). During this period, the U.S. Congress began offering tax incentives 

for producers to use the developing technologies in the field (Wang and Krupnick, 2013; EIA, 2011a; Yergin, 

2011). Advances in directional drilling technologies led to the first horizontal wells being drilled in the mid1980s in the Austin Chalk oil-bearing rock formation in Texas (Pearson, 2011; Haymond, 1991). Directional 

drilling and other technologies matured in the late 1990s. In 2001, the Mitchell Energy company developed a 

cost-effective technique to fracture the Barnett Shale in Texas. The company was bought by Devon Energy, a 

company with advanced experience in directional and horizontal drilling, that, in 2002, drilled seven wells 

and developed in the Barnett Shale using the combination of horizontal drilling and hydraulic fracturing; fiftyfive more wells were completed in 2003 (Yergin, 2011). The techniques were rapidly adopted and further 

developed by others (DOE, 2011b; Montgomery and Smith, 2010). By 2005, the techniques were being used 

in unconventional (low-permeability) oil and gas reservoirs outside of Texas. Modern hydraulic fracturing 

quickly became the industry standard, driving a surge in U.S. production of oil and natural gas. 

Hydraulic fracturing techniques and technologies continue to evolve. Wells are being drilled with longer

horizontal sections and are more closely spaced. Multiple, horizontal sections extending from a single vertical 

well enable production from larger subsurface areas from a single well pad on the land’s surface. These

historic and continuing technological developments enable production from previously unused oil and gasbearing geologic formations, altering and expanding the geographic range of oil and gas production activities.

Left: Early hydraulic fracturing site, late 1940s (source: Halliburton, used with permission). Right: Contemporary 

hydraulic fracturing operation, late 2000s (source: NYSDEC (2015), used with permission). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-5

adequate natural permeability, the economic extraction of oil and/or gas may only require using a 

drilled well to bring the oil or gas to the surface.1 

If the natural pressure is not high enough for the oil and gas to readily flow to the surface, various 

pumping and “lift” techniques can be used to help the oil and gas move up the well to the surface 

(Hyne, 2012). In other situations, operators may pump water or a mix of water and carbon dioxide

(or other similar mixtures) into the reservoir through injection wells to help move and enhance the 

extraction of oil and gas through nearby production wells. These techniques address pressure and 

fluid characteristics in the reservoir, are not designed to fracture the reservoir rock, and therefore 

are production-increasing techniques that are distinct from hydraulic fracturing. The discussions in 

the remainder of this chapter focus on hydraulic fracturing in unconventional reservoirs. 

Hydraulic fracturing is now combined with directional drilling technologies to access oil and gas in 

unconventional reservoirs (although hydraulic fracturing is still used in conventional reservoirs, 

too).2 Unconventional reservoirs have a very low natural permeability, which prevents oil and gas 

from flowing through the rock into wells in economic amounts. Production from unconventional 

reservoirs becomes economically feasible when wells, typically horizontal or deviated, are drilled

and hydraulically fractured through long portions of the production zone (the targeted oil- and gasbearing zones within a reservoir). See Figure 3-1 for a diagram of horizontal and other well types 

and the reservoir types from which they can produce. Text Box 3-2 provides a brief discussion on 

the use of the terms conventional and unconventional.

More details about the geologic formations that can be unconventional reservoirs are presented 

below: 

• Shales. Some organic-rich black shales serve as the source of oil and gas found in 

conventional resources when, over geologic time, the lighter and more buoyant oil and gas 

migrate upward from these shales and become trapped under impermeable confining 

layers (Figure 3-1). Shales have very low permeability and the oil and gas are contained in 

poorly connected pore space in the shale rock. With hydraulic fracturing and directional 

drilling now enabling oil and gas production from very low permeability formations, some 

of these shale source rocks are now unconventional reservoirs in addition to being 

sources. Some shales produce predominantly gas and others predominantly oil; often 

there will be some co-production of gas from oil wells and co-production of liquid oil from 

gas wells (USGS, 2013a; EIA, 2011a). 

• Tight formations. Some oil- and gas-bearing sandstone, siltstone, and carbonate 

formations can be referred to as “tight” formations (for example, “tight sands”) because of 

their relatively low permeability and the fact that oil and gas are contained in small, poorly 

connected pore spaces. Given a range of permeabilities, some tight formations require 

 

1 Permeability in rocks is the ability of fluids, including oil and gas, to flow through well-connected pores or small 

openings in the rock.

2 Directional drilling is the practice of controlling the direction and deviation (angle) of a borehole during drilling to 

extend the borehole in a predetermined orientation and to a targeted area in the subsurface. Directional drilling is 

required for drilling a deviated or horizontal well and is common in unconventional reservoirs. The terms deviated wells 

and directional wells are often used interchangeably. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-6 

hydraulic fracturing for economic production and some do not. In the literature, “tight gas”

generally refers to gas in tight sands and is distinguished from “shale gas.” Oil resources 

from shale and other tight formations, in contrast, are frequently referred together under 

the label “shale oil” or “tight oil” (Schlumberger, 2014; USGS, 2014a). 

• Coalbeds. Organic-rich coal, found in coalbeds, can be a source of methane (natural gas). 

The gas primarily adheres to the coal surface rather than being contained in pore space or 

structurally trapped in the formation. A range of techniques can be used to extract 

methane from coalbeds and these techniques sometimes, but not always, employ hydraulic 

fracturing. A key component of all coalbed methane production is the need to “dewater” 

the coalbeds (pumping out naturally occurring or injected water) to reduce the pressure in 

the coal allowing the methane to be released and flow from the coal into the production 

well (Palmer, 2010; Al-Jubori et al., 2009; USGS, 2000). 

 

Figure 3-1. Conceptual illustration of the types of oil and gas reservoirs and production wells 

used in hydraulic fracturing. 

A vertical well is producing from a conventional oil and gas reservoir (right). The impermeable gray confining layer 

(sometimes called a cap rock) traps the lighter and more buoyant gas (red) and oil (green) as it migrates up from 

the deeper oil- or gas-rich shale source rock. Also shown are wells producing from unconventional reservoirs: a 

horizontal well producing from a deep shale (center); a vertical well producing methane (gas) from coalbeds 

(second from left); and a deviated well producing from a tight sand reservoir (left). Multiple deviated or horizontal 

wells can be constructed and operated from a single well site. Note that the oil- or gas-rich shale serves as both a 

source and a reservoir. Modified from Schenk and Pollastro (2002) and Newell (2011).
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Text Box 3-2. “Conventional” Versus “Unconventional.”

The terms “conventional” and “unconventional” are widely used in articles and reports to distinguish types of 

oil and gas reservoirs, wells, production techniques, and more. In this report, the terms are mainly used to 

distinguish different types of oil and gas reservoirs: “conventional” reservoirs are those that can support the 

economically feasible production of oil and gas using long-established technologies, and “unconventional” 

reservoirs are those in which production has become economical only with the advances that have occurred 

in hydraulic fracturing (often combined with directional drilling) in recent years.

Note that as hydraulic fracturing has increasingly become a standard industry technique, the word 

“unconventional” is less apt than it once was to describe these oil and gas reservoirs. In a sense, “the 

unconventional has become the new conventional” (NETL, 2013). 

The following three maps show the locations of major shale gas and oil resources, tight gas 

resources, and coalbed methane resources, respectively, in the contiguous United States (Figure 

3-2, Figure 3-3, and Figure 3-4). To explain the terminology used in the maps: a group of known or 

possible oil and gas accumulations in the same region and with similar geologic characteristics can 

be referred to as a play (Schlumberger, 2014). Plays can sometimes be geologically layered atop one 

another (or “stacked”) and are located in broad depressions filled with sedimentary rock 

formations in the earth’s continental crust known as basins. A group of similar coalbed methane 

(gas) reservoirs can be referred to as coalbed methane fields (rather than plays) and are also found 

in basins. The plays and fields in the maps below represent unconventional reservoirs that are 

being exploited now or could be exploited in the future using hydraulic fracturing. 

There is a wide range of depths at which hydraulic fracturing occurs across the country. For 

example, approximate average depths for some of the largest gas-producing reservoirs are as deep 

as 6,000 ft (2,000 m) in the Marcellus Shale in Pennsylvania and West Virginia, 7,500 ft (2,300 m) in 

the Barnett Shale in Texas, and 12,000 ft (3,700 m) for the Haynesville-Bossier Shale in Louisiana 

and Texas (NETL, 2013).1 A few other, smaller plays are shallower, with depths less than 2,000 ft 

(600 m) in parts of the Antrim (Michigan), Fayetteville (Arkansas), and New Albany (Indiana and 

Kentucky) shale plays (NETL, 2013; GWPC and ALL Consulting, 2009). Coal seams that can be 

drilled to produce gas (coalbed methane) range in depth from less than 600 ft (200 m) to more than 

6,000 ft (2,000 m) with production often occurring at depths between 1,000 and 3,000 ft (300 and 

900 m) (U.S. EPA, 2006; ALL Consulting, 2004). Coalbed methane production occurs in the San Juan 

Basin in New Mexico, the Powder River Basin in Wyoming and Montana, and the Black Warrior 

Basin in Alabama and Mississippi. See Chapter 6 for more information on the general locations and 

depths of formations being hydraulically fractured. 

 

1 These are approximate average depths; hydraulic fracturing occurs in shallower and deeper zones in all these plays.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-8 

Figure 3-2. Major shale gas and oil plays in the contiguous United States. 

The plays represent geologically similar accumulations of oil and gas that are or could be developed. Adapted from EIA (2015). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-3. Major tight gas plays in the contiguous United States.

The plays represent geologically similar accumulations of gas that are or could be developed. Adapted from EIA (2011b). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-4. Coalbed methane fields and coal basins in the contiguous United States. 

The fields represent gas-bearing coal deposits that are or could be developed. Adapted from EIA (2011b).
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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How a hydraulic fracturing operation is conducted depends on the characteristics of the oil- or gasbearing formation (such as the geology, depth, and other factors). Hydraulic fracturing operations 

in shales, such as the Marcellus and Haynesville, require that relatively large volumes of water and 

proppant to be pumped at high pressures through deep wells with long horizontal sections in the 

production zone. In some tight formations, such as in the Permian Basin, hydraulic fracturing can be 

conducted with smaller water volumes and using less pressure in shorter vertical or deviated wells 

(Gallegos and Varela, 2015). Hydraulic fracturing technologies can be applied to coalbed methane 

production in various ways, for example, with much smaller water volumes and no proppant, or 

with water-based gels or foams and proppant. Coalbed methane production sometimes involves no 

hydraulic fracturing, with only pumping of the naturally occurring formation water out of the 

coalbeds to enable the release and production of the trapped methane.1

3.3 Hydraulic Fracturing and the Life of a Well

A variety of activities take place at a well site over the course of the operational life of a 

hydraulically fractured oil and gas production well. Not all of these activities are within the scope of 

this assessment (that includes water acquisition, chemical mixing, well injection, produced water

handling, and wastewater disposal and reuse). However, in this chapter we include some 

information on a wider range of activities related to the well site to provide context for the reader.

The overview of well operations presented in this section is broad, illustrates common activities, 

and describes some specific operational details. The details of well preparation, hydraulic 

fracturing and production operations, and closure can vary between companies, reservoirs, and 

states, and even from well to well. The activities involved in well development and operations may 

be conducted by the well owner and/or operator, their representatives, and/or service companies 

working for the well owner. 

Figure 3-5 shows the general sequence and duration of activities at a hydraulic fracturing well site, 

including the activities that comprise the five stages of the hydraulic fracturing water cycle (noted 

above and defined in Chapter 1). The hydraulic fracturing event itself is the period of the most 

operational activity during the life of a well and is short in duration compared to the other well site 

activities. The hydraulic fracturing activity typically lasts from about a day to several weeks (U.S. 

EPA, 2016c; Halliburton, 2013; NYSDEC, 2011). The subsequent phase of oil and gas production, 

during which produced water also flows from the well, is the longest phase during the life of the 

well and can last decades (King and Durham, 2015).2

 

1 Some subsurface geologic formations, including coalbeds and oil and gas reservoirs, can contain naturally occurring 

water that is commonly referred to as “formation water,” “native water,” or (if salty) “native brines.”

2 In general, produced water is water that flows from the subsurface through oil and gas wells to the surface as a byproduct of oil and gas production. See Section 3.3.3 and Chapter 7 for more details.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-5. General timeline and summary of activities that take place during the preparation 

and through the operations of an oil or gas well site at which hydraulic fracturing is used.

3.3.1 Site Preparation and Well Construction 

Before hydraulic fracturing and production can occur, preliminary steps include assessing and 

preparing the site, and drilling and constructing the production well. 

3.3.1.1 Site Assessment and Preparation

Selecting a suitable well site requires an assessment of geologic (subsurface) and geographic 

(surface) factors. Geophysical surveys of the subsurface can be conducted using data gathering 

techniques from the land surface or subsurface, and rock samples may be gathered from outcrops 

or from exploratory or test wells. Other information is obtained by well logging in which 

geophysical instruments that collect data on subsurface conditions are lowered into or installed in a 

well (Kundert and Mullen, 2009).1Analyzing all of this information together enables operators to 

develop an understanding of the potential reservoir characteristics (such as permeability and the 

presence of natural fractures and water), the position of such formations in relation to other 

 

1 Well logging is used to obtain information on mechanical integrity, well performance, and reservoir properties that can 

affect oil and gas production. Well logging data from other wells in the nearby area also provides information on the 

reservoir. More information on well logging is found in Chapter 6 and Appendix D. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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formations, including water-bearing zones, and details about the quantity and quality of the oil and 

gas resource. 

Geographic factors involved in well site assessment include topography and land cover; proximity 

to roads, pipelines, water sources, other oil and gas wells, and abandoned oil or gas wells; possible 

well setback requirements; potential for site erosion; location relative to environmentally sensitive 

areas; and location relative to populated areas (Drohan and Brittingham, 2012; Arthur et al., 

2009a).1 Land ownership also plays an important role in well site selection. During site assessment 

and before site development and well drilling, the well owner/operator obtains a mineral rights 

lease, negotiates with landowners, and applies for necessary permits from the appropriate federal, 

state, and local authorities (Hyne, 2012). This initial site assessment phase of the process may take 

several months (King and Durham, 2015; King, 2012). 

The site is typically surveyed to plan and finalize well site location and access. Sometimes an access 

road may need to be built to accommodate trucks delivering equipment and supplies to be used at 

the site (Hyne, 2012). The operator levels and grades the well site to manage drainage, complete 

access routes, and prepare the well pad. The well pad is a smaller area within the broader well site 

where the production well will be drilled and the hydraulic fracturing activities will be 

concentrated. Well pads can range in size from less than an acre to several acres depending on the 

scope of the operations (King, 2012; NYSDEC, 2011). Multiple wells can be located on a single well 

pad at a well site (King, 2012; NYSDEC, 2011) 

To manage the various fluids that are used for or generated during operations, storage pits 

(sometimes referred to as impoundments) are excavated, graded and constructed on the well site, 

and/or steel tanks are installed. These are used to hold water and materials (such as drilling mud) 

related to the well-drilling activities, water used in the hydraulic fracturing process, or the 

produced water that is generated post-fracturing (Hyne, 2012). Pit construction is generally 

governed by local regulations. In some areas, regulations may prohibit the use of pits or require pits 

to be lined to prevent fluid seepage into the shallow subsurface. One alternative to constructing a 

pit for drilling fluids is the use of a closed loop drilling system that stores, partly treats, and recycles 

the drilling fluid (Astrella and Wiemers, 1996). Often piping is installed along the surface or in the 

shallow subsurface of the well site to deliver water for hydraulic fracturing, remove produced 

water, or transport the oil and gas once production begins (Arthur et al., 2009a). 

Water may be acquired from local surface water or groundwater resources, or reused from other 

well sites. Water is required for the drilling phase as well as for hydraulic fracturing (Chapter 4). 

Figure 3-6 depicts the pumping of water for well site operation from a local surface water source. 

After site and well pad preparation, drill rigs and associated equipment (including the drill rig 

platform, generators, well blowout preventer, fuel storage tanks, cement pumps, drill pipe, and 

casing) are brought onto the site. 

 

1 Regarding well setbacks, some states and sometimes local city or county governments can have requirements that define 

how close an oil and gas well can be located to drinking water supplies or other water bodies.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-6. Surface water being pumped for oil and gas development. 

Photo credit: Arkansas Water Science Center (USGS). 

3.3.1.2 Well Drilling and Construction

Wells are generally drilled and constructed by repeating several basic steps. The operator begins by 

using the drill rig (temporarily located on the well pad) to hoist a section of long drill pipe up and 

attaching a drill bit to the bottom of the drill pipe. The drill rig is then used to rotate and advance 

the drill pipe/drill bit combination (also known as the drill string) downward through the soil and 

rock. As the drill string continues moves downward, new sections of pipe are added at the surface, 

enabling the drilling to proceed deeper (Hyne, 2012). During drilling, a drilling fluid is pumped 

down through the center of the drill string to the drill bit to lubricate and cool it, and to help 

remove the drill cuttings from the well (King, 2012).1

Drilling is temporarily halted at certain pre-determined intervals, the drill string is removed from 

the wellbore (also called the borehole), and long sections of another type of steel pipe called casing 

are lowered into the wellbore and set in place.2 Cement is then pumped into the space between the 

outside of the casing and the wellbore. This process is repeated, with the next interval of drilling 

 

1 Drilling fluids, sometimes called drilling mud, consist primarily of water, foam, oil or air, with the most common drilling 

mud consisting mainly of water and clay (Williamson, 2013). Drill cuttings are the small pieces of broken and ground-up 

rock generated during the drilling process.

2 The wellbore is the drilled hole and can refer to both the open hole or an uncased portion of the well.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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using a smaller diameter drill bit that fits inside the existing casing. The result can be multiple 

layers of casing and cement with surface casing and cement typically set below the groundwater

resource to be protected. Figure 3-7 illustrates different types of casing as defined by their locations 

within the well, shows multiple casing and cement layers, and shows examples of two wells with 

differences in the extent of cement.1

Figure 3-7. Illustration of well construction showing different types of casing and cement. 

The well on the left is cemented continuously from the surface to the production zone and the well 

on the right has cement in sections, including sections cemented across protected groundwater.

The cement protects the casing from corrosion by formation water, helps physically support the 

casing in the borehole, and stabilizes the borehole against collapse or deformation (Renpu, 2011).2

The casing and cement help to isolate geologic zones of high pressure, isolate water-bearing zones, 

and maintain the integrity of the production well for transporting oil and gas to the surface. Casing 

and cement provide important barriers that keep fluids within the well (oil, gas, hydraulic 

fracturing fluids) isolated and separated from fluids outside the well (formation water) (Hyne, 

2012). Figure 3-8 shows sections of casing ready for installation. 

 

1 In different portions of the well, multiple concentric sections of casing of different diameters can be used as shown by 

the surface and production casings in Figure 3-7. The largest casing diameter can range between 30 in. (76 cm) to 42 in. 

(107 cm) with casing diameters typically larger in the shallower portions of a well and smaller in the deeper portions 

(Hyne, 2012). See Appendix D for details on well construction and casing diameters. 

2 Some naturally occurring formation water can be very saline (salty or briny), which can be corrosive to metal. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-8. Sections of well casing ready for installation at a well site in Colorado.

Photo credit: Gregory Oberley (U.S. EPA).

Some wells are cemented continuously from the surface down to the production zone. Other wells 

are partially cemented with, for example, cement from the surface to some distance below the 

deepest protected groundwater zone and perhaps cement across high pressure or water- or oilbearing zones. Sometimes there can be multiple casing and cement layers (Figure 3-7). There are 

advantages, in some situations, to not fully cementing the casing as long as high pressure or waterand oil-bearing zones are cemented. For example, some sections may not be cemented to allow 

monitoring of the pressure in the space between the casing and the borehole or to prevent damage 

to weak rock formations due to the weight of the cement1 (King and Durham, 2015; API, 2009). 

Although wells are initially drilled vertically (more or less straight down), the sections of the wells 

that are hydraulically fractured in the production zone of the reservoir can be vertical, deviated, or 

horizontal (Figure 3-1). The operator determines the well orientation that will provide the best 

access to the targeted zone(s) within a reservoir and that will align the production section of the 

well with natural fractures and other geologic structures in a way that helps improve production. 

Deviated wells may be “S” shaped or continuously slanted. So-called “horizontal wells” have one or 

more extensions or branches oriented approximately 90 degrees from the vertical portion of the 

well; these horizontal sections are often referred to as “laterals.” The lengths of laterals can range 

from 2,000 to 10,000 ft (600 to 3,000 m) or more (Hyne, 2012; Miskimins, 2008; Bosworth et al., 

1998). Multiple laterals can extend in different directions from a single well (and multiple wells can 

be located on a single well site). This allows access to more of the production zone with a higher 

well density in the subsurface, which can be required for unconventional reservoirs, while having 

fewer well sites on the land surface. 

 

1 The use of lighter cement or special cementing techniques can also prevent damage of weaker rock formations. See 

Chapter 6 and Appendix D for more details on well construction and cementing. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Once well construction is completed, the operator can move the drilling rig and related drilling 

equipment, install the wellhead (the top portion of the well), and prepare the well for hydraulic 

fracturing and subsequent production of oil and gas. Chapter 6 and Appendix D contain more 

details on well construction, casing, and cement.

Figure 3-9 (from northeastern Pennsylvania) and Figure 3-10 (from northwestern North Dakota) 

show, in the context of the local landscape, well sites during well drilling and construction prior to 

hydraulic fracturing activities. 

Figure 3-9. Aerial photograph of two hydraulic fracturing well sites and a service road in 

Springville Township, Pennsylvania.

Photo credit: Image@J Henry Fair / Flights provided by LightHawk. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-18 

Figure 3-10. Aerial photograph of hydraulic fracturing well sites near Williston, North Dakota.

Photo credit: Image@J Henry Fair / Flights provided by LightHawk. 

3.3.2 Hydraulic Fracturing

The hydraulic fracturing phase is an intense phase of work in the life of the well that involves 

complex operational activities at the well site. This phase of work is short in duration, compared to 

other work phases in the life of a well, and typically lasts less than two weeks per well. It consists of 

multiple activities, is typically a process done in repetitive stages, and requires a variety of 

equipment and materials. During this phase of work, the well is prepared for hydraulic fracturing, 

specialized equipment is hauled to the well site, the hydraulic fracturing fluid components –the 

water, proppant, and additives– are moved to the well site, and the hydraulic fracturing fluid is 

mixed and injected under pressure through the well and into the targeted production zone in the 

subsurface (Figure 3-11). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-11. Well site with equipment (and pits in the background) in preparation for 

hydraulic fracturing in Troy, Pennsylvania. 

Image from NYSDEC (2015). Reprinted with permission. 

3.3.2.1 Injection Process

The section of well located in the production zone can be prepared for the injection and fracturing 

process in several different ways. One approach is used when the production casing and cement 

extend all the way into the production zone; this requires the use of focused explosive charges to 

perforate (blast holes in) the casing and cement in a segment of the well within the production 

zone. In another approach, known as a formation packer completion, only the casing, equipped with 

holes that can be opened and closed, is extended into the production zone. The resulting 

perforations or holes allow the injected hydraulic fracturing fluids to flow out of the well to fracture 

the reservoir rock and allow the oil and gas to flow into the well. Another technique is an open hole 

completion in which the casing is set and cemented just to the edge of the production zone, so the 

borehole extends open (with no casing or cement) into the production zone. In open hole 

completions, oil and gas flow directly into the borehole and eventually into the cased section of the 

well leading to the surface (Hyne, 2012; Cramer, 2008; Economides and Martin, 2007). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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After the subsurface portion of the well is prepared for injection, a wellhead assembly is 

temporarily installed on the wellhead to which high pressure fluid lines are connected for injection 

of the fluids into the well. Figure 3-12 shows three wellheads with injection piping attached in 

preparation for hydraulic fracturing injection. Pressures required for fracturing can vary widely 

depending on depth, formation pressure, and rock type and can range from 2,000 psi to 12,000 psi

(U.S. EPA, 2016c; Salehi and Ciezobka, 2013; Abou-Sayed et al., 2011; Thompson, 2010). 

Figure 3-12. Three wellheads on a multi-well pad connected to the piping used for hydraulic 

fracturing injection. 

Photo credit: DOE/NETL

The portion of the well to be fractured can sometimes be done all at once or done in multiple 

interval (U.S. EPA, 2016c; GWPC and ALL Consulting, 2009). When done in multiple intervals, 

shorter lengths or segments of the well are closed-off (using equipment inserted down into the 

well) and fractured independently in “stages” (Lee et al., 2011). Fluids are first injected to clean the 

well (removing any cement or debris). Then, for each stage fractured, a series of hydraulic 

fracturing fluid mixtures is injected to initiate fractures and carry the proppant into the fractures 

(Hyne, 2012; GWPC and ALL Consulting, 2009). The fracturing process can require moving millions 

of gallons of fluids around the well site through various hoses and lines, blending and mixing the 

fluids with proppant, and injecting the mixture at high pressures down the well. For more details on 

hydraulic fracturing chemical mixtures and stages, see Chapter 5.

The hydraulic fracturing produces propped-open fractures that extend into the production zone 

and create more flow paths that contact a greater volume of the oil- and gas-bearing rock within the 

production zone of the reservoir. This increase in flow paths and in the volume of the production 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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zone accessed by the production well is how hydraulic fracturing increases production. In this 

regarding, hydraulic fracturing can be considered a production or well “stimulation” technique. 

The process and the fracturing pressures during injection are closely monitored throughout the 

fracturing event. Microseismic monitoring (a geophysical survey technique) can be used to estimate 

the horizontal and vertical extent of the fractures created and, used with other monitoring and 

operational data, provides important information for designing subsequent fracture jobs (Cipolla et 

al., 2011). Engineers can design fracture systems using modeling software to help optimize the 

process. More details of injection, fracturing, and related monitoring are provided in Chapter 6 and 

Appendix D. 

3.3.2.2 Fracturing Fluids

To conduct the chemical mixing and preparation of the hydraulic fracturing fluids, water- and 

chemical-filled tanks and other storage containers are transported and installed on site. The 

components that make up the hydraulic fracturing fluid for injection are commonly mixed on a 

truck-mounted blender on the well pad. Hoses and pipes are used to transfer the water, proppant, 

and chemicals from storage units to the mixing equipment and to the well into which the mixed 

hydraulic fracturing fluid will be injected. The injection process happens in stages with specific 

chemicals added at different times during each stage. The composition of the hydraulic fracturing 

fluid, therefore, can change over time during the process (Knappe and Fireline, 2012; Fink, 2003). 

See Chapter 5 for more details on mixing and staged injection.

Hydraulic fracturing fluids (sometimes referred to as “fluid systems”) are generally either waterbased or gel-based. Other fluid systems include foams or emulsions made with nitrogen, carbon 

dioxide, or hydrocarbons; acid-based fluids; and others (Montgomery, 2013; Saba et al., 2012; 

Gupta and Hlidek, 2009; Gupta and Valkó, 2007; Halliburton, 1988). Water-based systems are used 

more often with the most common type being “slickwater” formulations, which include polymers as 

friction reducers and are typically used in very low permeability reservoirs such as shales (Barati 

and Liang, 2014). Because slickwater fluids are thinner (have lower viscosity) they do not as easily 

carry sand proppant into fractures, so larger volumes of water and greater pumping pressures are 

required to effectively transport proppants into fractures. In contrast, gelled fluids (used in “gel 

fracs”) are more viscous, and more proppant can be transported with less water as compared to 

slickwater fractures (Brannon et al., 2009). Gel fracs are generally used in reservoirs with higher 

permeability (Barati and Liang, 2014). 

The composition of a typical water-based hydraulic fracturing fluid by volume is 90% to 97% 

water, 2% to 10% proppant, and 2% or less additives (U.S. EPA, 2015a; OSHA, 2014a, b; Carter et 

al., 2013; Knappe and Fireline, 2012; Spellman, 2012; Sjolander et al., 2011; SWN, 2011). In a 

detailed study, the EPA analysis of FracFocus 1.0 data for nearly 39,000 wells nationally in 2011 

and 2012 indicates that the fracturing fluid injected into a well consists of nearly 90% water, 10% 

proppant, and less than 1% additives (on a mass basis) (U.S. EPA, 2015a). The proportions of water, 

proppant, and additives in the fracturing fluid, and the specific additives used, can vary depending 

on a number of factors, including the rock type and the chemistry of the reservoir, whether oil or 

gas is being produced, operator preference, and to some degree on local or regional availability of 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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chemicals (Arthur et al., 2014; Spellman, 2012; GWPC and ALL Consulting, 2009; Gupta and Valkó, 

2007). Hydraulic fracturing fluid composition and chemical use changes as processes are tested and 

refined by companies and operators. These changes are driven by economics, scientific and 

technological developments, and concerns about environmental and health impacts. Further detail 

on hydraulic fracturing fluid systems is presented in Chapter 5. 

Sources of water for hydraulic fracturing fluid include groundwater, surface water, and reused

wastewater (URS Corporation, 2011; Blauch, 2010; Kargbo et al., 2010). The water may be brought 

to the production well from an offsite regional source via trucks or piping, or it may be more locally

sourced (for example, pumped from a nearby river or a groundwater well). Selection of water 

source depends upon availability, cost, water quality needs, and the logistics of delivering it to the 

site. Figure 3-13 shows a row of water tankers storing water on a well site. Chapter 4 provides 

additional details on water acquisition and the amounts of water used for hydraulic fracturing.

Figure 3-13. Water tanks (blue, foreground) lined up for hydraulic fracturing at a well site in 

central Arkansas.

Photo credit: Martha Roberts (U.S. EPA). 

Proppants are most commonly silicate minerals, primarily quartz sand (GWPC and ALL Consulting, 

2009). Sand proppants can be coated with resins that make them more durable. Ceramic materials

are also sometimes used as proppants due to their high strength and resistance to crushing and 

deformation (Beckwith, 2011). 

Additives generally constitute less than 2.0% of hydraulic fracturing fluids (Carter et al., 2013; 

Knappe and Fireline, 2012; GWPC and ALL Consulting, 2009). The EPA analyzed additive data in the 

EPA FracFocus 1.0 project database and estimated that chemicals used as additives were about 

0.43% (the median value by mass) of the total amount of fluid injected for hydraulic fracturing (U.S. 

EPA, 2015a). Given the total volume of hydraulic fracturing fluid, these small percentages of 

chemicals in the fluid mean that a typical hydraulic fracturing job can handle, mix, and inject tens of 

thousands of gallons of chemicals. Chapter 5 includes details on the number, types, and estimated 

quantities of chemicals typically used in hydraulic fracturing. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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3.3.3 Fluid Recovery, Handling, and Disposal or Reuse

At the end of the hydraulic fracturing process, the pressurized injection is stopped and the direction 

of fluid flow reverses. Initially, the fluid flowing back into the well and to the surface is mostly the 

injected fracturing fluid (sometimes referred to as flowback). The composition of the fluid changes 

over time, though, and after the first few weeks or months the proportion of hydraulic fracturing 

fluid flowing back into the well decreases and the proportion of formation water flowing into the 

well and to the surface increases (NYSDEC, 2011). In this assessment, the water that flows from the 

subsurface through oil and gas wells to the surface as a by-product of oil and gas production is 

referred to as produced water. The amount of produced oil or gas flowing into the well gradually 

increases until it is the primary constituent of the fluid emerging from the well at the surface. 

Produced water continues to flow from the production well along with the oil or gas throughout the 

operating life of the production well (Barbot et al., 2013). See Chapter 7 for details, descriptions, 

and discussions of the chemical composition and quantities of produced water recovered. 

Produced water is sometimes referred to as hydraulic fracturing wastewater. Along with other 

liquid waste collected from the well pad (such as rainwater runoff), it is typically stored 

temporarily on-site in pits (Figure 3-14) or tanks. This wastewater can be moved offsite via truck or 

pipelines for treatment and reuse or for disposal. Most hydraulic fracturing wastewater in the 

United States is disposed of by injection into deep, porous geologic rock formations, often located 

away from the production well site. This disposal-by-injection occurs not through oil and gas 

production wells, but through wastewater injection wells regulated by EPA Underground Injection 

Control (UIC) programs under the Safe Drinking Water Act.1 See Chapter 8 for a brief discussion of 

wastewater injection. 

Figure 3-14. A pit on the site of a hydraulic fracturing operation in central Arkansas.

Photo credit: Caroline E. Ridley (U.S. EPA).

 

1 States may be given federal EPA approval to run a UIC program under the Safe Drinking Water Act. Most oil- and gasrelated UIC programs are implemented by the states although some are implemented by the EPA. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Other wastewater handling options include discharge to surface water bodies either with or 

without treatment, evaporation or percolation pits, or reuse for subsequent fracturing operations 

either with or without treatment (U.S. EPA, 2012h; U.S. GAO, 2012). Decisions regarding 

wastewater handling are driven by factors such as cost (including costs of temporary storage and 

transportation), availability of facilities for treatment, reuse, or disposal, and regulations

(Rassenfoss, 2011). Chapter 8 contains details of the treatment, reuse, and disposal of wastewater.

3.3.4 Oil and Gas Production

After the hydraulic fracturing activity is completed, the fracturing-related equipment is removed 

and operators drain, fill in with soil, and regrade pits that are no longer needed unless multiple 

wells are drilled and fractured on the same pad. The well pad size is reduced as the operation 

moves toward the production phase (NYSDEC, 2011). Prior to and during production, the operator 

runs production tests to determine the maximum flow rate that the well can sustain and to 

determine optimum equipment settings (Hyne, 2012; Schlumberger, 2006). During production, 

monitoring of mechanical integrity and performance (with pressure tests, corrosion monitoring, 

etc.) can be conducted to ensure that the well is performing as intended. Such well tests and 

monitoring may be required by state regulations. 

Produced gas typically flows from the well through a pipe to a “separator” that separates the gas 

from water and any liquid oil and gas (NYSDEC, 2011). The finished gas is typically piped to a 

compressor station where it is pressurized and then piped to a main pipeline for sale (Hyne, 2012). 

Production at oil wells proceeds similarly, although oil/water or oil/water/gas separation typically 

occurs on the well pad, no compressor is needed, and the oil can be hauled by truck or train, or 

piped from the well pad to offsite storage and sale facilities.1 

During the life of the well it may be necessary to repair components of the well and replace old 

equipment. Sometimes the well is re-fractured to boost production.2 Routine maintenance 

activities, often referred to as “workovers,” may be done with the well still in production 

(Vesterkjaer, 2002) or sometimes require stopping production and removing the wellhead to clean 

out debris or repair components of the well (Hyne, 2012). More extensive re-workings of a well, 

sometimes referred to as “re-completions,” can include making additional perforations in the well 

in new sections to produce oil and/or gas from another production zone, lengthening the borehole, 

or drilling new horizontal extensions (laterals) from an existing borehole. 

3.3.4.1 Production Rates and Duration

The production life of a well depends on a number of factors, such as the amount of oil or gas in the 

reservoir, the reservoir pressure, the rate of production, and the economics of well operations, 

including the price of oil and gas. In hydraulically fractured wells in unconventional reservoirs, 

 

1 In some oil production operations, the oil reservoir being tapped may include some natural gas that is extracted along 

with oil through the production wells. In cases where no facilities or pipelines are in place to handle the natural gas or 

move it to a market, the gas can be “flared” (ignited and burned at the well site) or vented into the atmosphere. 

2 Sometimes boosting or reinvigorating production in a well is referred to as “well stimulation.” In some cases, well 

stimulation can refer to either the initial well hydraulic fracturing event or the re-fracturing of a well.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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initial high production is typically followed by a rapid drop and then a slower decline in production 

(Patzek et al., 2013). The production phase may be 40 to 60 years in tight gas reservoirs (Ross and 

King, 2007) or range from 5 to 70 years in a gas- or liquids-rich shale (King and Durham, 2015). 

However, because the current hydraulic fracturing-led production surge is less than a decade old

with limited well production history, there is an incomplete picture of production declines and it is

not known how much and for how long these wells will ultimately produce (Patzek et al., 2013). 

3.3.5 Site and Well Closure

Once a well reaches the end of its useful life, it is removed from production and disconnected from 

any pipelines that transferred produced oil or gas offsite. The well is then sealed to prevent any

movement of fluids inside or along the borehole. This is done by removing the wellhead, cutting the

casing off below ground surface, and then sealing portions of the well with one or more cement or

mechanical plugs placed permanently in sections of the well. Spaces between plugs may be filled 

with a thick clay (bentonite) or drilling mud (NPC, 2011b). State regulations identify plugging 

locations within the borehole and the materials for plugging (Calvert and Smith, 1994). After

plugging and cementing, a steel plate is welded on top of the well casing to provide a complete seal

(API, 2010). Permanently closing a well like this is called “plugging” a well. Some states require

formal notification of the location of these plugged wells. Proper plugging prevents fluids at the 

surface from seeping down the borehole and migration of fluids through the borehole (NPC,

2011b). See Chapter 6 for more details regarding fluid movement in wells and through the

borehole. 

To complete site closure, any remaining production-related equipment is removed and the site land

cover and topography are restored to pre-well pad conditions to the extent possible. Some surface

structures from the former operations may be left in place for subsequent reuse.

3.4 How Widespread is Hydraulic Fracturing? 

There is no national database or complete national registry of wells that have been hydraulically

fractured. However, hydraulic fracturing activity for oil and gas production in the United States is 

substantial based on various reports and data sources. According to the Interstate Oil and Gas

Compact Commission (IOGCC), close to 1 million wells had been hydraulically fractured in the

United States by the early 2000s (IOGCC, 2002). A recent U.S. Geological Survey report estimated

approximately 1 million wells with 1.8 million hydraulic fracturing treatment records from 1947 to

2010 (more than one fracturing event, or treatment, can be conducted on a single well) (Gallegos 

and Varela, 2015). Roughly a third of these 1 million wells were drilled and hydraulically fractured 

between 2000 and 2013/2014 based on estimates from FracFocus (2016); Baker Hughes (2015); 

Gallegos et al. (2015); DrillingInfo (2014a); IHS Inc. (2014). This timeframe marks the beginning of

modern hydraulic fracturing (refer to Text Box 3-1). Figure 3-15 shows the location of the

approximately 275,000 oil and gas wells that were drilled and hydraulically fractured between

2000 and 2013 across the United States based on well and locational data from DrillingInfo

(DrillingInfo, 2014a). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-15. Locations of the approximately 275,000 wells drilled and hydraulically fractured 

between 2000 and 2013.

Based on data from the DrillingInfo Database. 

The following two satellite photographs show hydraulic fracturing well sites in a regional context. 

These Landsat images show the locations, number, and density of hydraulic fracturing well sites

across landscapes in northwest Louisiana (Figure 3-16) and western Wyoming (Figure 3-17). The 

orange circles around some of the well sites identify them as operations for which well information 

was reported to the FracFocus 1.0 registry and included in the EPA FracFocus 1.0 project database 

(U.S. EPA, 2015c). Note that some of the well sites in the Landsat images, taken in 2014, are for 

wells that were constructed after the development of the EPA FracFocus 1.0 project database. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-16. Landsat photo showing hydraulic fracturing well sites near Frierson, Louisiana. 

Imagery from USGS Earth Resources Observation and Science, Landsat 8 Operational Land Imager (scene 

LC80250382014232LGN00) captured 8/20/2014, accessed 5/1/2015 from USGS’s EarthExplorer 

(http://earthexplorer.usgs.gov/). Inset imagery from United States Department of Agriculture National Agriculture 

Imagery Program (entity M 3209351_NE 15_1_20130703_20131107) captured 7/3/2013, accessed 5/1/2015 from 

USGS’s EarthExplorer (http://earthexplorer.usgs.gov/). FracFocus well locations are from the EPA FracFocus 1.0 

project database (U.S. EPA, 2015c). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Figure 3-17. Landsat photo showing hydraulic fracturing well sites near Pinedale, Wyoming. 

Imagery from USGS Earth Resources Observation and Science, Landsat 8 Operational Land Imager (scene 

LC80370302014188LGN00) captured 7/7/2014, accessed 5/1/2015 from USGS’s EarthExplorer 

(http://earthexplorer.usgs.gov/). Inset imagery from United States Department of Agriculture National Agriculture 

Imagery Program (entity M 4210927_NW 12_1_20120623_20121004) captured 6/23/2012, accessed 5/1/2015 

from USGS’s EarthExplorer (http://earthexplorer.usgs.gov/). FracFocus well locations are from the EPA FracFocus

1.0 project database (U.S. EPA, 2015c). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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3.4.1 Number of Wells Fractured per Year

Approximately 25,000 to 30,000 new oil and gas wells were hydraulically fractured each year in the 

United States between 2011 and 2014 based on data from several commercial data sets and 

publicly available data from organizations that track drilling and hydraulic fracturing activities

(Table 3-1). These estimates do not include fracturing activity in older, existing wells (wells more 

than one-year old that may or may not have been hydraulically fractured in the past). Likely 

following the decline in oil prices (starting in about 2014) and gas prices (in about 2008), the 

estimated number of new hydraulically fractured wells declined to about 20,000 in 2015 according 

to well information submitted to FracFocus (FracFocus, 2016). Future drilling activity and the 

annual number of new wells will be influenced by future oil and gas prices.

Table 3-1. Estimated number of new wells hydraulically fractured nationally by year from 

various sources. 

Data from FracFocus (2016); Baker Hughes (2015); DrillingInfo (2014a); IHS Inc. (2014) as provided in Gallegos et al. 

(2015). 

Data Source 2011 2012 2013 2014

IHS 29,650 31,073 29,114 11,980 a

DrillingInfo 23,144 22,865 15,903 b NA

Baker Hughes NA 24,948 25,368 26,548

FracFocus c 14,025 22,471 26,400 28,285

a The IHS well count for 2014 is incomplete as it represents data only for 8 months (January through August). 

b The DrillingInfo well count for 2013 is incomplete because some months are missing from some state data sets. 

c The FracFocus 2011 and 2012 counts are underestimates because reporting well information to FracFocus was voluntary when 

it began in 2011. The number of states requiring reporting to FracFocus has increased over time. See FracFocus discussion 

below. The FracFocus well counts for 2011 and 2012 are from the EPA FracFocus 1.0 project database (U.S. EPA, 2015c) 

developed from the FracFocus national registry, and the FracFocus counts for 2013 and 2014 are from (FracFocus, 2016). 

The Information Handling Services (IHS) annual well count estimates presented in Table 3-1 are 

from IHS data made available in a U.S. Geological Survey publication that evaluated well data from 

2000 to 2014 (Gallegos et al., 2015). The IHS data are compiled from a variety of public and private 

sources and are commercially available from IHS Energy. A well is identified as a hydraulic 

fracturing well apparently based on well operational information. Gallegos et al. (2015) estimated, 

based on the IHS data, that approximately 371,000 wells were hydraulically fractured between 

January 2000 and August 2014.

DrillingInfo, another commercial database, is developed using data obtained from individual state 

oil and gas agencies (DrillingInfo, 2014a). Because DrillingInfo data does not identify whether a 

well has been hydraulically fractured, EPA relied on information about well orientation and the oilor gas-producing rock formation type to infer which wells were likely hydraulically fractured. This 

is a similar approach to that used by the EPA for estimating oil and gas well counts for its 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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greenhouse gas inventory work (U.S. EPA, 2013c).1 Using this approach, we estimate from the 

DrillingInfo data the annual numbers presented in Table 3-1 above and also estimate that a total of 

approximately 275,000 oil and gas wells were drilled and hydraulically fractured between 2000 

and 2013.2

Well counts tracked by Baker Hughes provide another estimate of new wells fractured annually. 

This field service company compiles new-well information based on its extensive field work in oil 

and gas producing areas and through state agencies. Baker Hughes started compiling this publicly 

available well count data in 2012, but stopped in 2014. The well count data are categorized into 14 

basins containing reservoirs that are mostly unconventional (and, therefore, likely hydraulically

fractured wells) and one “other” category (Baker Hughes, 2015). The well count estimates in the 

table above are for the 14 basins and, therefore, are considered estimates of new wells 

hydraulically fractured in each year. 

FracFocus is a national registry for operators of hydraulically fractured oil and gas wells to report 

information about well location and depth, date of operations, and water and chemical use. The 

registry, publicly accessible online (www.fracfocus.org), was developed by the Groundwater

Protection Council and the Interstate Oil and Gas Compact Commission. Submission of information

to FracFocus was initially voluntary (starting in January 2011), but many states now require 

reporting of hydraulic fracturing well activities to FracFocus. As of May 2015, 23 states required 

reporting to FracFocus (Konschnik and Dayalu, 2016). The annual well counts in the table above 

are from the EPA FracFocus 1.0 project database for 2011 and 2012 (U.S. EPA, 2015c) and from the 

FracFocus 2016 Quarterly Report for 2013 and 2014 (FracFocus, 2016). The well counts in the 

earliest years are underestimates because not all states required oil and gas well operators to 

submit hydraulic fracturing data to FracFocus.3The FracFocus registry has undergone several 

updates since its launch in 2011. For more details on FracFocus, see FracFocus (2016), Konschnik 

and Dayalu (2016), U.S. EPA (2015a), U.S. EPA (2015c), and DOE (2014a).4

In addition to these new well counts, some portion of existing wells are also re-fractured. Several 

studies indicate that re-fracturing occurs in less than 2% of wells. Shires and Lev-On (2012)

 

1 Using the DrillingInfo data, EPA assumed that all horizontal wells were hydraulically fractured in the year they started 

producing and assumed that all wells within a shale, coalbed, or low-permeability formation, regardless of well 

orientation, were hydraulically fractured in the year they started producing. More details are provided in (U.S. EPA, 

2013c). Not all coalbed methane wells are hydraulically fractured, but coalbed methane wells represent gas production 

that sometimes uses hydraulic fracturing. Given the small percent of coalbed methane wells relative to all hydraulically 

fractured wells and the lack of data that distinguishes whether or not coalbed wells are hydraulically fractured, EPA 

included coalbed production wells into all counts of wells that are hydraulically fractured. 2 The different well count totals from IHS and DrillingInfo are likely due to different sources of data, different approaches 

for defining hydraulically fractured wells in those sources, and somewhat different timeframes. The higher IHS count 

likely includes hydraulically fractured vertical and deviated wells in conventional reservoirs (the DrillingInfo estimate 

does not) and covers a time period that is a year or more longer. 

3 We compared state records of hydraulic fracturing wells in North Dakota, Pennsylvania, and West Virginia in 2011 and 

2012 to those reported to FracFocus during those same years and found the FracFocus wells counts underestimated the 

number of fracturing jobs in those states by approximately 30% on average. See Chapter 4, Text Box 4-1. 

4 Analyses of the FracFocus data based on the EPA FracFocus 1.0 project database (U.S. EPA, 2015c) are presented in 

Chapter 4 regarding water volumes and in Chapter 5 regarding chemical use.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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suggested that the rate of re-fracturing in natural gas wells is about 1.6% whereas analysis for the 

EPA’s 2012 Oil and Gas Sector New Source Performance Standards indicated a re-fracture rate of 

1% for gas wells (U.S. EPA, 2012f). The percentage of hydraulically fractured producing gas wells 

that were re-fractured in a given year ranged from 0.3% to 1% across the 1990-2013 period

according to the EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks (U.S. EPA, 2015h). 

The above rates are calculated by comparing the number of re-fractured wells in a single year to all 

hydraulically fractured wells cumulatively over a multi-year time period. However, when 

calculating the rates of wells that conduct re-fracturing in a given year compared to the total 

number of wells in that same year, the re-fracturing rate is higher. Data provided to the EPA’s 

Greenhouse Gas Reporting Program (GHGRP) for 2011 to 2013 suggest that 9-14% of the gas wells

hydraulically fractured in each year were pre-existing wells undergoing re-fracturing (U.S. EPA, 

2014b).1Another rate presenting a somewhat different measure (estimated by an EPA review of 

well records from 2009 to 2010) found that 16% of the surveyed wells had been re-fractured at 

least once (U.S. EPA, 2016c).2

In summary, a complete count of the number of hydraulically fractured wells in the United States is 

hampered by a lack of a definitive and readily accessible source of information, and the fact that 

existing well and drilling databases and registries track information differently and therefore are 

not entirely comparable. There is also uncertainty about whether existing information sources are 

representative of the nation (or parts of the nation), whether they include data for all production 

well types, and to what degree they include activities in both conventional and unconventional 

reservoirs. Taking these limitations into account, however, it is reasonable to conclude that 

between approximately 25,000 and 30,000 new wells (and, likely, additional pre-existing wells)

were hydraulically fractured each year in the United States from about 2011 to 2014, and 

approximately 20,000 wells were hydraulically fractured in 2015. 

3.4.2 Hydraulic Fracturing Rates

Estimates of hydraulic fracturing rates, or the proportion of all oil and gas production wells that are 

hydraulically fractured, also indicate widespread use of the practice. Data from IHS Inc. (2014)

indicate that approximately 62% of all new oil and gas wells in 2013 were hydraulically fractured. 

Data from DrillingInfo (2014a), indicate a similar rate of 64% of all new production wells in 2012. 

Estimates of hydraulic fracturing rates reported by states in response to an IOGCC survey tended to 

be considerably higher. Of eleven oil and gas producing states that responded to the survey, ten 

(Arkansas, Colorado, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, and 

West Virginia) estimated that 78% to 99% of new wells in their states were hydraulically fractured 

in 2012. Louisiana was the one exception, reporting a fracturing rate of 3.9% (IOGCC, 2015). 

Hydraulic fracturing may be more prevalent in gas wells than in oil wells. A 2010 to 2011 survey of 

20 natural gas production companies reported that 94% of the gas wells that they operated were 

 

1 The GHGRP reporting category that covers re-fracturing is “workovers with hydraulic fracturing.” This re-fracturing data 

is for gas wells only (and does not include oil wells). 

2 This EPA report is based on a statistical survey so there is some uncertainty and a margin of error regarding the 16% refracturing rate. This rate includes both oil and gas wells. For more details, see Chapter 6 and U.S. EPA (2016). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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fractured (Shires and Lev-On, 2012), a rate that is higher than many of the reported statistics for oil 

and gas together (presented in the previous paragraph). Recent EIA data on the portion of oil and 

gas production attributable to hydraulically fractured wells also suggest possibly higher rates of 

hydraulic fracturing for gas. In 2015, production from hydraulically fractured wells accounted for 

an estimated 67% of natural gas production (EIA, 2016d) and 51% of oil production (EIA, 2016c). 

3.5 Trends and Outlook for the Future

Future oil and gas drilling and production activities, including hydraulic fracturing, will be 

primarily affected by the cost of well operation (partly driven by technology) and the price of oil 

and gas. Scenarios of increasing, stable, and decreasing hydraulic fracturing activity all appear to be 

possible (Weijermars, 2014). The section below provides some discussion on trends and future 

prospects for production quantities and locations. 

Fossil fuels–oil, gas, and coal–have been dominant energy sources in the United States over the last 

half century (Figure 3-18). The relative importance of oil, gas, and coal has changed several times, 

with a significant recent shift starting in the mid-2000s as hydraulic fracturing transformed oil and 

gas production. Coal, the leading fossil fuel from the mid-1980s to the mid-2000s, has experienced a 

large decrease in production, dropping from approximately 33% of U.S. energy production in 2007 

to approximately 20% (about 18 quadrillion Btus) by the end of 2015 (EIA, 2016a).1 In contrast, 

natural gas production has risen to unprecedented levels, and oil production has resurged to levels 

not seen since the 1980s. Oil accounted for 15% of U.S. energy production in 2007 and increased to 

approximately 23% (about 20 quadrillion Btus) by the end of 2015, and natural gas as a portion of 

domestic energy production went from 31% to 37% (about 33 quadrillion Btus) (EIA, 2016a). 

Figure 3-18. Primary U.S. energy production by source, 1950 to 2015. 

Source: EIA (2016a). 

 

1 A Btu, or British thermal unit, is a measure of the heat (or energy) content of fuels. At the scale of national U.S. 

production, the graph in Figure 3-18 presents Btus in quadrillions, or a thousand million million (which is 1015, or a 1 

with 15 zeros).
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-33

The surge in both oil and gas production started in the mid- to late-2000s and was driven by market 

forces (supply and demand) and the related developments in and expanded use of hydraulic 

fracturing. Figure 3-19 focuses on the years 2000 to 2015 and presents data showing the steady 

increase in the portion of oil and gas production coming from hydraulically fractured wells. Oil and 

gas production associated with hydraulic fracturing was insignificant in 2000, but by 2015 it 

accounted for an estimated 51% of US oil production and 67% of US gas production (Figure 3-19). 

Figure 3-19. U.S. production of oil (left) and gas (right) from hydraulically fractured wells from 

2000 to 2015. 

Source: EIA (2016c) (oil) and EIA (2016d) (gas), based on IHS Global Insight and DrillingInfo, Inc.

Hydraulic fracturing activities are concentrated geographically in the United States. In 2011 and 

2012 about half of hydraulic fracturing wells were located in Texas with another quarter located in 

the four states of Colorado, Pennsylvania, North Dakota, and Oklahoma (U.S. EPA, 2015c). The maps 

in Figure 3-20 show changes starting in 2000 in the national geography of oil and gas production 

through the increased use of horizontal drilling, which frequently is associated with hydraulic 

fracturing. Some traditional oil- and gas-producing parts of the country, such as Texas, have seen an 

expansion of historical production activity as a result of modern hydraulic fracturing. Pennsylvania, 

a leading oil- and gas-producing state a century ago, has seen a resurgence in oil and gas activity. 

Other states that experienced a steep increase in production, such as North Dakota, Arkansas, and 

Montana, have historically produced less oil and gas.

3.5.1 Natural Gas 

Drilling of new natural gas wells declined markedly as natural gas prices fell in 2008 (Figure 3-21). 

Nevertheless, over the coming decades natural gas production is expected to increase and that 

increase will be associated significantly with wells that are hydraulically fractured. Projections by 

EIA indicate that gas production from shale (and tight oil reservoirs) will almost double from 2015 

to 2040 when it will constitute nearly 70% of total natural gas production (EIA, 2016d). Slight 

increases are projected for production from tight gas reservoirs and coalbed methane production is 

expected to continue fairly steady at relatively low levels (EIA, 2016a) (Figure 3-22). These 

projections are dependent on estimated future prices of natural gas and other assumptions, and 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-34 

Figure 3-20. Location of horizontal wells that began producing oil or natural gas in 2000, 2005, 

and 2012. 

Based on data from DrillingInfo (2014a). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-35

Figure 3-21. Natural gas prices and drilling activity, United States, 1988 to 2015. 

Sources: EIA (2016b) and EIA (2016f).

Figure 3-22. Historic and projected natural gas production by source (trillion cubic feet).

Source: EIA (2016a). 

the details are subject to change. Nonetheless, a continuing increase in production is generally 

suggested and the locations of historical production identified in Figure 3-23 indicate areas of 

continued and future hydraulic fracturing activities for natural gas production. 

The geographic concentration and trends in shale gas production by play (and identified by state) 

are shown in Figure 3-23. The Barnett Shale, where the modern hydraulic fracturing boom started, 

was the largest producer of shale gas until about 2010, producing 1.5 trillion cubic feet (tcf) (42.5 

billion cubic meters [bcm]) that year and remains a significant producer. In 2009, the Marcellus and 

Haynesville plays produced 0.12 and 0.43 tcf (3.4 and 12.2 bcm), respectively, but by 2011, 

production from the Haynesville play surpassed that in the Barnett play, and by 2013 the Marcellus 

Shale surpassed both the Barnett and the Haynesville to become the play with the most production. 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-36 

By 2014, the Marcellus play was producing 4.8 tcf (135.9 bcm) of gas annually, with the Eagle Ford, 

Haynesville, and Barnett each producing roughly 1.5 tcf (42.5 bcm). Estimates of technically 

recoverable resources, a general indicator of potential future production, are noted for the 

Marcellus (about 150 tcf [4.25 trillion cubic meters]), Haynesville (73 tcf [2.07 trillion cubic 

meters]), Eagle Ford in Texas (55 tcf [1.56 trillion cubic meters]), and Utica in Ohio, Pennsylvania, 

and West Virginia (55 tcf [1.56 trillion cubic meters]). This suggests that these four plays will be 

active contributors of shale gas production for the foreseeable future (EIA, 2013).1 Other gas plays 

with significant resources include the Fayetteville in Arkansas, the Woodford in Oklahoma, and the 

Mancos in Colorado. 

Figure 3-23. Production from U.S. shale gas plays, 2000-2014. 

Source: EIA (2016g). The graph shows shale plays in the same vertical order as the legend. 

3.5.2 Oil

While prices and drilling activity for natural gas were peaking between 2005 and 2008 and then 

falling (Figure 3-21), prices and drilling for oil were rising. These peaked between 2011 and 2014, 

and then rapidly declined as well (Figure 3-24). EIA projections to 2040 indicate a continued 

growth in total U.S. oil production, although the projected growth is not as fast or as large as that 

projected for natural gas. Tight oil production, presumably from hydraulically fractured wells, is 

expected to account for much of the projected growth (Figure 3-25); by 2040, tight oil is expected 

to account for nearly 65% of all U.S. crude oil production (EIA, 2016d). These production 

projections are dependent on estimated future prices of oil and other assumptions and, therefore, 

will likely be revised over time as energy markets and prices change. Currently, these projections 

 

1 Technically recoverable resources are the volumes of oil or natural gas that could be produced with current technology, 

regardless of oil and natural gas prices and production costs (EIA, 2013). 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-37

indicate a continuing, but lower rate of growth (as compared to the period from about 2005 to 

2015). The locations of historical production identified in Figure 3-26 indicate areas of continued 

and future hydraulic fracturing activities for oil.

Figure 3-24. Crude oil prices and drilling activity, United States, 1988 to 2015. 

Sources: EIA (2016b) and EIA (2016e). 

Figure 3-25. Historic and projected oil production by source (million barrels per day).

Source: EIA (2016a). 

The geographic concentration and trends in tight oil production by play (and identified by state) 

are shown in Figure 3-26. Early tight oil production in the United States was centered in the 

Permian Basin in west Texas and New Mexico, at plays that included the Spraberry and the 

Bonespring. After 2009, the Bakken play (centered in western North Dakota) and the Eagle Ford 

play (in Texas) emerged as the largest-producing tight oil plays. Oil production in the Bakken 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-38 

increased from 99 million bbls (16,000 million L) in 2009 to 394 million bbls (63,600 million L) in 

2014 (EIA, 2016g). Production from Eagle Ford increased from 12 million bbls (2,000 million L) in 

2009 to 498 million bbls (79,100 million L) in 2014 (EIA, 2016g). 

General estimates of potential resources suggest that future tight oil production in the United States 

will continue to be led by Texas and North Dakota. Technical recoverable resources are estimated 

at about 23 billion bbls (3,600 billion L) for the Bakken, about 21 billion bbls (3,300 billion L) for 

the Permian Basin, and about 10 billion bbls (1,600 billion L) for Eagle Ford (EIA, 2015). Other 

plays with significant estimated resources include the Niobrara-Codell in Colorado and Wyoming 

and the Granite Wash in Oklahoma and Texas (EIA, 2012). 

Figure 3-26. Production from U.S. tight oil plays, 2000-2014. 

Source: EIA (2016g). The graph shows tight oil plays in the same vertical order as the legend.

3.6 Conclusions 

Hydraulic fracturing is the injection of hydraulic fracturing fluids through the production well and 

into the subsurface oil or gas reservoir under pressures great enough to fracture the reservoir rock. 

The fractures allow for increased flow of oil and/or gas from the reservoir into the well. Water used 

in the hydraulic fracturing fluid is typically obtained from sources in the vicinity of the well. Water 

that naturally occurs in the oil and gas reservoir rocks often flows into the production well and 

through the well to the surface as a byproduct of the oil and gas production process. This byproduct 

water, commonly referred to as produced water, requires handling and management. 

Many well site and operational activities are conducted to prepare a site and well for hydraulic 

fracturing and oil and/or gas production. The actual hydraulic fracturing event is of relatively short 

duration, usually several weeks or less, but it is also a phase of work with numerous complex 
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

3-39

operational activities to handle, mix, and inject the hydraulic fracturing fluid under pressure 

through the production well. The injected hydraulic fracturing fluid typically contains mostly water, 

includes a proppant (commonly sand) which ensures that the fractures remain propped open after 

injection, and contains less than two percent additives (chemicals) that improve the fluid 

properties for fracturing. These small percentages of additives, given the total volume of hydraulic 

fracturing fluids, mean that a typical hydraulic fracturing job can use tens of thousands of gallons of 

chemicals. 

Since about 2005, the combination of hydraulic fracturing and directional drilling pioneered in the 

Barnett Shale in Texas has become widespread in the oil and gas industry. Hydraulic fracturing 

combined with directional drilling is now a standard industry practice. It has significantly 

contributed to the surge in United States oil and gas production, and accounted for slightly more 

than 50% of oil production and nearly 70% of gas production in 2015. Hydraulic fracturing has 

resulted in expanded production from unconventional shale and so-called tight oil or gas reservoirs 

that had previously been largely unused. This hydraulic fracturing-based production activity is 

geographically concentrated. About three-quarters of new hydraulic fracturing wells in 2011 and 

2012 were located in five states (Texas, Colorado, Pennsylvania, North Dakota, and Oklahoma) with 

about half of all wells located in Texas. 

There is no national database or complete national registry of wells that have been hydraulically 

fractured in the United States. Based on the data available from various commercial and public 

sources, we estimate that 25,000 to 30,000 new wells were drilled and hydraulically fractured in 

the United States annually between 2011 and 2014. In addition to these new wells, some existing 

wells not previously fractured were fractured, and some that had been fractured in the past were 

re-fractured. New drilling of hydraulic fracturing wells, influenced by oil and gas prices, peaked in 

the United States between 2005 and 2008 for gas and between 2011 and 2014 for oil. Following 

price declines, the number of new hydraulically fractured wells in 2015 was about 20,000. Future 

drilling and production will be influenced by future gas and oil prices. Despite recent declines in 

prices and new drilling, oil and gas production in the United States continues at historically high 

levels with projections of continued growth in the medium and long term led by hydraulic 

fracturing-based production from unconventional reservoirs.
Chapter 3 – Hydraulic Fracturing for Oil and Gas in the United States

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Chapter 4 – Water Acquisition

4-1

Chapter 4. Water Acquisition

Abstract 

In this chapter, the EPA examined the potential impacts of water withdrawals for hydraulic fracturing on 

drinking water resource quantity and quality, and identified common factors affecting the frequency and 

severity of impacts. Groundwater and surface water resources used for hydraulic fracturing also 

currently serve or in the future may serve as drinking water sources, and water withdrawals for 

hydraulic fracturing can affect the quantity or quality of the remaining drinking water resource. 

Hydraulic fracturing used a median of 1.5 million gallons (5.7 million liters) of water per well from 2011 

through early 2013. Surface water supplies almost all water used for hydraulic fracturing in the eastern 

United States, whereas surface water or groundwater is used in the West. Reuse of hydraulic fracturing 

wastewater as a percentage of injected volume is generally low, with a median of 5% according to an 

EPA literature survey. Greater reuse occurs where disposal options are limited (e.g., the Marcellus Shale 

in Pennsylvania) and not necessarily where water availability is lowest. 

Hydraulic fracturing generally uses and consumes a relatively small percentage of water when 

compared to total water use, water consumption, and water availability at the national, state, and county 

scale. There are exceptions, however. For example, EPA’s analysis shows that counties in southern and 

western Texas have relatively high hydraulic fracturing water withdrawals and low water availability. 

These findings indicate where impacts are more likely to occur or be severe, but local information (i.e., 

at the scale of the drinking water resource) is needed to determine whether potential impacts have been 

realized. In some example cases (e.g., the Eagle Ford Shale in Texas, the Haynesville Shale in Louisiana), 

local impacts to drinking water resource quantity have occurred in areas with increased hydraulic 

fracturing activity. In these instances, hydraulic fracturing water withdrawals contributed to local 

impacts along with other water users and the lack of precipitation. 

Drought or seasonal times of low water availability can increase the frequency and severity of 

impacts, while water management practices such as the establishment of low-flow criteria (termed

passby flows), shifting from fresh to brackish water sources, or increasing the reuse of wastewater 

for hydraulic fracturing can help protect drinking water resources. 

Uncertainty about the extent of impacts on drinking water resources stems from the lack of 

available data at the local scale. The EPA could assess the potential for impacts at the county scale,

but often could not determine whether impacts occurred at drinking water withdrawal locations. 

Overall, hydraulic fracturing uses and consumes a relatively small percentage of water at the county 

scale, but not always, and impacts can still occur depending on the local balance between withdrawals 

and availability. Regional or local-scale factors, such as drought or water management, can modify this 

balance to increase or decrease the frequency or severity of impacts.
Chapter 4 – Water Acquisition

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Chapter 4 – Water Acquisition

4-3

4. Water Acquisition

4.1 Introduction 

Water is a crucial component of nearly all hydraulic fracturing operations, generally making up 90 – 

97% of the total fluid volume injected into a well (Chapter 5).1 Ground- and surface water resources 

that serve as sources of water for hydraulic fracturing also provide water for public water supplies 

or private drinking water wells. For this reason, water withdrawals for hydraulic fracturing can 

impact drinking water resources by changing the quantity or quality of the remaining resource.2 In 

this chapter, we consider potential impacts of water acquisition for hydraulic fracturing on both 

drinking water resource quantity and quality, and, where possible, identify factors that affect the 

frequency or severity of impacts.3 

We define impacts broadly in this assessment to include any change in the quantity or quality of 

drinking water resources; see Chapter 1 for more information. This definition applies reasonably 

well to the subsequent chapters (Chapters 5-8); however, by this definition, even the smallest water 

withdrawals would be considered impacts. Recognizing this, we focus on a smaller subset of 

potential impacts, specifically water withdrawals that have the potential to limit the availability of 

drinking water or alter its quality. Whether water withdrawals have this potential depends 

primarily on the balance between water use and availability at the local scale.4,5 By “local” in this 

chapter, we refer to the scale at which impacts to drinking water resources are expected to occur. 

This usually means a given surface water (e.g., river or stream) or groundwater resource (i.e., 

aquifer), or a given watershed where we have detailed information about local water dynamics 

(e.g., case studies). We note the scale at which data are available and findings are reported.

 

1 This range is based on multiple sources that either present hydraulic fracturing fluid composition as a function of 

volume (e.g., 95% of the total volume injected) or as a function of mass (e.g., 90% of the total mass injected). See Chapter 

5 for additional information.

2 Surface water withdrawals can affect water quality by altering in-stream flow and decreasing the dilution of pollutants 

or changing water chemistry (Section 4.5.3). Groundwater withdrawals may alter water quality by inducing vertical 

mixing of fresh groundwater with contaminated water from the land surface or underlying formations, or by promoting 

changes in reduction-oxidation conditions and mobilizing chemicals from geologic sources (Section 4.5.1). 

3 Water acquired for use in other oil and gas development steps besides hydraulic fracturing is beyond the scope of this 

chapter, including the water used in well drilling and well pad preparation and water removal for the production of 

coalbed methane. Furthermore, water released to the atmosphere via gas combustion is also outside the scope of this 

chapter.

4 Throughout this chapter we use the terms “water use” and “water withdrawals” interchangeably to refer to the water 

that is acquired for hydraulic fracturing operations. 

5 There is no standard definition for water availability, and it has not been assessed recently at the national scale (U.S. 

GAO, 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. GAO, 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.
Chapter 4 – Water Acquisition

4-4 

A variety of factors can modify the balance between water use and availability. For example, 

multiple hydraulically fractured wells require more water than a single well, making it critical to 

assess the cumulative effects of multiple wells over a given area or time period. Furthermore, the 

combined effects of multiple water users pumping from the same aquifer can compound stress on 

already declining groundwater supplies. Alternatively, locally high rates of hydraulic fracturing 

wastewater reuse may help offset the need for fresh water withdrawals. These and other factors 

are discussed throughout the chapter. 

This chapter proceeds roughly in two halves. In the first half, we address water use and 

consumption by hydraulic fracturing.1 We provide an overview of the types of water used for 

hydraulic fracturing (Section 4.2); the amount of water used per well (Section 4.3); and then 

estimates of hydraulic fracturing water use and consumption at the national, state, and county 

scale, both in absolute terms and relative to total water use and consumption (Section 4.4). 

Although most available data and literature pertain to water use, we discuss water consumption 

because hydraulic fracturing consumes a substantial proportion of the water it uses, so that a 

proportion of the water is lost from the local hydrologic cycle. See Section 4.4 and Chapter 2 for 

more information. 

In the second half of the chapter, we assess the potential for impacts by location in certain states 

(and major oil and gas regions within select states) where hydraulic fracturing currently occurs 

(Section 4.5; Appendix B.2). For each state and region, we discuss the water used and consumed by 

hydraulic fracturing, and then compare it to water availability. We do this using several lines of 

evidence: (1) literature information (both quantitative and qualitative) on state and regional 

hydraulic fracturing water use and availability; (2) comparisons between our county level 

estimates of hydraulic fracturing water use and an index of water availability; and (3) local case 

studies from the Eagle Ford play in Texas, the Upper Colorado River Basin in Colorado, and the 

Susquehanna River Basin in Pennsylvania.2 The use of case studies provides insight into the local, 

sub-county scale, where impacts are most likely to be observed in both space and time. 

Overall, this chapter provides a national assessment of where potential impacts to drinking water 

quantity and quality are most likely due to water acquisition for hydraulic fracturing. We utilize 

case studies where data are available to understand local dynamics and whether impacts are 

indeed realized. In the absence of case studies, we use county level data to assess where potential 

impacts are most likely. Finally, we identify the common factors affecting the frequency and 

severity of impacts. We provide a synthesis of our findings in Section 4.6. 

 

1 We refer specifically to “water consumption” when data are available or it is explicitly noted in the scientific literature. 

However, when specific information is not available, we use “water use” or “water withdrawals” as general terms to refer 

to both water use and consumption by hydraulic fracturing.

2 The EPA’s Review of Well Operator Files for Hydraulically Fractured Oil and Gas Production Wells (i.e., the “Well File 

Review;” see Text Box 6-1) was originally planned to inform the water acquisition stage of the hydraulic fracturing water 

cycle, but did not yield any useable information on this topic, and is therefore not cited as a source of information in this 

chapter. Although information in some well files was of good quality, the well files generally contained insufficient or 

inconsistent information on nearby surface water and groundwater quality, injected water volumes, and wastewater 

volumes and disposition; therefore, these data were not summarized (U.S. EPA, 2015n). 
Chapter 4 – Water Acquisition

4-5

4.2 Types of Water Used

The three major sources of water for hydraulic fracturing are surface water (i.e., rivers, streams, 

lakes, and reservoirs), groundwater, and reused hydraulic fracturing wastewater.1,2,3 These sources 

often vary in their initial water quality and in how they are provisioned to hydraulic fracturing 

operations. In this section, we provide an overview of the sources (Section 4.2.1), water quality 

(Section 4.2.2), and provisioning of water (Section 4.2.3) required for hydraulic fracturing. Detailed 

information on the types of water used by state and locality is presented in Section 4.5. 

4.2.1 Source

Whether water used in hydraulic fracturing originates from surface water or groundwater

resources is largely determined by the type of locally available water sources. Water transportation 

costs can be high, so the industry tends to acquire water from nearby sources if available (Nicot et 

al., 2014; Mitchell et al., 2013a; Kargbo et al., 2010). Surface water supplies most of the water for 

hydraulic fracturing in the eastern United States, whereas surface water or groundwater is used in 

the more semi-arid to arid western states. In western states that lack available surface water 

resources, groundwater generally supplies the majority of water needed for fracturing (Table 4-1). 

Brackish sources of groundwater can be important for reducing demand on fresh groundwater 

resources in certain regions (e.g., the Permian Basin and Eagle Ford Shale in Texas; see Section 

4.5.1).4 Local policies also may direct the industry to seek withdrawals from designated sources

(U.S. EPA, 2013a); for instance, some states have encouraged the industry to seek water 

withdrawals from surface water rather than groundwater due to concerns over aquifer depletion. 

See Section 4.5.4 and Section 4.5.5 for more information. 

 

1 We use the term “hydraulic fracturing wastewater” to refer to 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. The term 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 (see Chapter 8 and Appendix J, the Glossary, for more 

detail). 

2 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. 

3 We use the term “reuse” regardless of the extent to which the wastewater is treated (Nicot et al., 2014); we do not 

distinguish between reuse and recycling except when specifically reported in the literature. 

4 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. 
Chapter 4 – Water Acquisition

4-6 

Table 4-1. Estimated proportions of hydraulic fracturing source water from surface water and 

groundwater. 

Location Surface water Groundwater Year or time 

period of 

estimate 

Louisiana—Haynesville Shale 87%a 13%a 2009 - 2012 

Oklahoma―Statewide 63%b 37%b 2011

Pennsylvania—Marcellus Shale, Susquehanna River Basin 92%c 8%c 2008 - 2013

Texas―Barnett Shale 50%d 50%d 2011 - 2013

Texas―Eagle Ford Shale 10%e 90%e 2011

Texas―TX-LA-MS Salt Basinf 30%e 70%e 2011

Texas―Permian Basin 0%e 100%e 2011

Texas―Anadarko Basin 20%e 80%e 2011

West Virginia―Statewide, Marcellus Shale 91%g 9%g 2012

a Percentages calculated from fracturing supply water usage data only. Rig supply water and other sources were excluded as 

they fall outside the scope of this assessment. Data from October 1, 2009, to February 23, 2012, for 1,959 Haynesville Shale 

natural gas wells (LA Ground Water Resources Commission, 2012). 

b Proportion of surface water and groundwater 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). 

c Calculated from SRBC (2016) data from July 2008 to December 2013. 

d Nicot et al. (2014). 

e Nicot et al. (2012). 

f Nicot et al. (2012) refer to this region of Texas as the East Texas Basin.

g Estimated proportions are for 2012, the most recent estimate for a full calendar year available from West Virginia DEP (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 water or groundwater. Therefore, we excluded purchased 

water in calculating the relative proportions of surface water and groundwater shown in Table 4-1 (West Virginia DEP, 2014). 

The reuse of wastewater from past hydraulic fracturing operations reduces the need for 

withdrawals of fresh surface water or groundwater.1 In a survey of literature values from 10 states, 

basins, or plays, we found a median of 5% of the water used in hydraulic fracturing comes from 

reused hydraulic fracturing wastewater, with this percentage varying by location (Table 4-2).2,3

1 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.

2 Throughout this chapter, we preferentially report medians where possible because medians are less sensitive to outlier 

values than averages. Where medians are not available, averages are reported.

3 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 wells). This 

distinction is sometimes overlooked, which can lead to a misrepresentation of the extent to which wastewater is reused to 

offset total fresh water used for hydraulic fracturing.
Chapter 4 – Water Acquisition

4-7

Table 4-2. Percentage of injected water volume that comes from reused hydraulic fracturing 

wastewater in various states, basins, and plays.

See Section 4.5 and Appendix B.2 for additional discussion of reuse practices by state and locality and variation 

over time where data are available. 

State, basin, or play Estimate of the percentage 

of injected water volume 

that comes from reused 

hydraulic fracturing 

wastewatera

Year or time 

period of 

estimate 

(NA = not 

available)

California—Monterey Shale 13%b 2014

Colorado—Wattenberg Field, Denver-Julesburg Basin 0%c NA

Pennsylvania—Statewide 19%d 2014

Pennsylvania–Marcellus Shale, Susquehanna River Basin 16%e 2008 – 2013

Texas—Barnett Shale 5%f 2011

Texas—Eagle Ford Shale 0%f 2011

Texas—TX-LA-MS Salt Basing 5%f 2011

Texas—Permian Basin (far west portion) 0%f 2011

Texas—Permian Basin (Midland portion) 2%f 2011

Texas—Anadarko Basin 20%f 2011

West Virginia—Statewide 15%h 2012

Overall Meani 8%

Overall Medianj 5%

a All estimates in this table refer to the percentage of injected water volume that comes from reused hydraulic fracturing 

wastewater. However, different literature sources used slightly different terminology when referring to this percentage. In the 

table footnotes below, we reference the terminology reported in the literature source cited.

b Produced water as a percentage of total water volume for 480 well stimulations according to completion reports between 

January 1, 2014, and December 10, 2014 (CCST, 2015a). All but two of these stimulations were conducted in Kern County, 

California (the remaining two were completed in Ventura County, California). Well stimulations mostly consisted of hydraulic 

fracturing operations, but also included smaller numbers of matrix acidizing and acid fracturing operations (CCST, 2015a). c 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). d Percentage of recycled water used in hydraulic fracturing in 2014 based on data from the Pennsylvania Bureau of Topographic 

and Geologic Survey (Schmid and Yoxtheimer, 2015). This percentage was higher at 23% in 2013, but we present the most 

recent estimate available in the above table. The slight decline to 19% in 2014 may be explained by the fact that some 

completion reports had not yet been processed when these data were published, yet the data generally show an upward trend 

over time in reuse as a percentage of injected volume (Schmid and Yoxtheimer, 2015). e Flowback water as a percentage of total water injected from July 2008 to December 2013 (SRBC, 2016). This percentage was 

22% in 2013 alone (SRBC, 2016). f Estimated percentage of recycling/reused water in 2011 (Nicot et al., 2012). g Nicot et al. (2012) refer to this region of Texas as the East Texas Basin. h Reused fracturing water as a percentage of total water used for hydraulic fracturing in 2012, calculated from data provided by 

the West Virginia DEP (2014). i Calculated based on the values presented in Table 4-2, excluding the value for Pennsylvania’s Susquehanna River Basin to 

avoid double counting with the statewide value. The overall mean is not weighted by the number of wells in a given state, 

basin, or play. 

j Calculated based on the values presented in Table 4-2, excluding the value for Pennsylvania’s Susquehanna River Basin to 

avoid double counting with the statewide value. The overall median is not weighted by the number of wells in a given state, 

basin, or play.
Chapter 4 – Water Acquisition

4-8 

Available data on reuse trends indicate increased reuse as a percentage of injected volume over 

time in both Pennsylvania and West Virginia, likely due to the lack of nearby disposal options in 

Class II injection wells regulated by the Underground Injection Control (UIC) Program (Section 

4.5.3). 

The reuse of wastewater for hydraulic fracturing is limited by the amount of water that returns to 

the surface during production (Nicot et al., 2012). In the first 10 days of well production, 5% to 

almost 50% of the hydraulic fracturing fluid volume can be collected, with values varying across 

geologic formations (Chapter 7, Table 7-1). Longer duration measurements are rare, but between 

10% and 30% of the hydraulic fracturing fluid volume has been collected in the Marcellus Shale in 

Pennsylvania over nine years of production, while over 100% has been collected in the Barnett 

Shale in Texas over six years of production (Chapter 7, Table 7-2).1 Assuming that 10% of hydraulic 

fracturing fluid volume is collected in the first 30 days and 100% of the wastewater is reused, it 

would take 10 wells to produce enough water to hydraulically fracture a new well. As more wells 

are hydraulically fractured in a given area, the potential for wastewater reuse increases. 

The decision to reuse hydraulic fracturing wastewater appears to be driven by economics and the 

quality of the wastewater, and not concerns over local water availability (Section 4.2.2). Water 

transportation costs (i.e., trucking, piping), the availability of Class II wells, and local regulations can 

play a role in determining whether hydraulic fracturing wastewater is reused to offset the need for 

fresh water withdrawals (Schmid and Yoxtheimer, 2015). Besides hydraulic fracturing wastewater, 

other wastewaters may be reclaimed for use in hydraulic fracturing. These include acid mine 

drainage, wastewater treatment plant effluent, and other sources of industrial and municipal 

wastewater (Nicot et al., 2014; Ziemkiewicz et al., 2013). Limited information is available on the 

extent to which these other wastewaters are used.

4.2.2 Quality

Water quality is an important consideration when sourcing water for hydraulic fracturing. Fresh 

water is most often used to maximize hydraulic fracturing fluid performance and to ensure 

compatibility with the geologic formation being fractured. This finding is supported by the EPA’s 

analysis of disclosures to the FracFocus Chemical Disclosure Registry (version 1.0; hereafter, the 

EPA FracFocus report) (U.S. EPA, 2015b), as well as by regional analyses from Texas (Nicot et al., 

 

1 It is possible to collect over 100% of the hydraulic fracturing fluid volume because water from the formation returns to 

the surface along with the injected water.
Chapter 4 – Water Acquisition

4-9

2012) and the Marcellus Shale (Mitchell et al., 2013a).1,2 Fresh water was the most commonly cited 

water source by companies included in an analysis of nine hydraulic fracturing service companies 

on their operations from 2005 to 2010 (U.S. EPA, 2013a). Three service companies noted that the 

majority of their water was fresh, because it required minimal testing and treatment (U.S. EPA, 

2013a).3 The majority of the nine service companies recommended testing for certain water quality 

parameters (pH and maximum concentrations of specific cations and anions) in order to ensure 

compatibility among the water, other fracturing fluid constituents, and the geologic formation (U.S. 

EPA, 2013a). 

The reuse of hydraulic fracturing wastewater may be limited to an extent by water quality. Over the 

production life of a well, the quality of the wastewater produced begins to resemble the quality of 

the water naturally found in the geologic formation and may be characterized by high 

concentrations of total dissolved solids (TDS) (Goodwin et al., 2014). High concentrations of TDS 

and other individual dissolved constituents in wastewater, including specific cations (calcium, 

magnesium, iron, barium, strontium), anions (chloride, bicarbonate, phosphate, and sulfate), and

microbial agents, can interfere with hydraulic fracturing fluid performance by producing scale in 

the borehole or by interfering with certain additives in the hydraulic fracturing fluid (e.g., high TDS 

may inhibit the effectiveness of friction reducers) (Gregory et al., 2011; North Dakota State Water 

Commission, 2010). Due to these limitations, wastewater can require treatment or blending with

fresh water to meet the level of water quality desired in the hydraulic fracturing fluid formulation.4 

Options for treating hydraulic fracturing wastewater to facilitate reuse are available and being used 

by the industry in some cases. For example, filter socks, centrifuge, dissolved air flotation, or 

settling technologies can remove suspended solids, and physical/chemical precipitation or 

electrocoagulation can remove dissolved metals (Schmid and Yoxtheimer, 2015). For more 

information on treatment of hydraulic fracturing wastewater, see Chapter 8. 

 

1 The FracFocus Chemical Disclosure Registry (often referred to as FracFocus; www.fracfocus.org) is a national hydraulic 

fracturing chemical disclosure registry managed by the Ground Water Protection Council and the Interstate Oil and Gas 

Compact Commission. FracFocus was created to provide the public access to reported chemicals used for hydraulic 

fracturing within their area. It was originally established in 2011 (version 1.0) for voluntary reporting by participating oil 

and gas well operators. 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, 2015b). 

2 Of all disclosures reviewed 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, 2015b). 

3 Service companies did not provide data on the percentage of fresh water versus non-fresh water used for hydraulic 

fracturing (U.S. EPA, 2013a). 

4 The EPA FracFocus report suggests that fresh water makes up the largest proportion of the base fluid when blended 

with water sources of lesser quality (U.S. EPA, 2015b). 
Chapter 4 – Water Acquisition

4-10 

4.2.3 Provisioning

Water for hydraulic fracturing is typically either self-supplied by the industry or purchased from 

public water systems.1 Self-supplied water for fracturing generally refers to permitted direct 

withdrawals from surface water or groundwater or the reuse of wastewater. Nationally, 

self-supplied water is more common, although there is much regional variation (U.S. EPA, 2015b; 

CCST, 2014; Mitchell et al., 2013a; Nicot et al., 2012). Water purchased from municipal public water 

systems can be provided either before or after treatment (Nicot et al., 2014). Water for hydraulic 

fracturing is also sometimes purchased from smaller private entities, such as local land owners 

(Nicot et al., 2014). 

4.3 Water Use Per Well

In this section, we provide an overview of the amount of water used per well during hydraulic 

fracturing. We discuss water use in the life cycle of oil and gas operations (Section 4.3.1) and 

national per well estimates and associated variability (Section 4.3.2). More detailed 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

Water is needed throughout the life cycle of oil and gas production and use, including both at the 

well for processes such as well pad preparation, drilling, and fracturing (i.e., the upstream portion), 

and later for end uses such as electricity generation, home heating, or transportation (i.e., the 

downstream portion) (Jiang et al., 2014; Laurenzi and Jersey, 2013). Most of the upstream water 

usage and consumption occurs during hydraulic fracturing (Jiang et al., 2014; Clark et al., 2013; 

Laurenzi and Jersey, 2013).2 Water use per well estimates in this chapter focus on hydraulic 

fracturing in the upstream portion of the oil and gas life cycle, as the downstream portion of the 

lifecycle is outside the scope of this assessment.3 

 

1 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 water or groundwater 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.

2 Laurenzi and Jersey (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, Jiang et al. (2014) reported that 86% of water 

consumption occurred at the fracturing stage for the Marcellus Shale, 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 et al. (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 et al. (2013) similarly illustrate the importance of the 

hydraulic fracturing stage in water use, particularly in terms of the upstream portion of the life cycle.

3 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 Jersey (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 
Chapter 4 – Water Acquisition

4-11

4.3.2 National Estimates and Variability in Water Use Per Well for Hydraulic Fracturing

At its most basic level, the volume of water used per well for hydraulic fracturing equals the 

concentration of water in the hydraulic fracturing fluid multiplied by the total volume of the fluid 

injected. In turn, the total volume of fluid injected generally equals the volume of fluid in the 

fractures, plus the volume of the well itself, plus any fluid lost due to “leakoff” or other unintended 

losses.1 

Nationally, most operators employ fracturing fluids with water as a base fluid, meaning the 

concentration of water in the fluid is high (U.S. EPA, 2015b; Yang et al., 2013; GWPC and ALL 

Consulting, 2009). The EPA inferred that more than 93% of reported disclosures to FracFocus used 

water as a base fluid (U.S. EPA, 2015b). The median reported concentration of water in the 

hydraulic fracturing fluid was 88% by mass, with 10th and 90th percentiles of 77% and 95%, 

respectively. Only roughly 2% of disclosures (761 wells) reported the use of non-aqueous 

substances as base fluids, typically either liquid-gas mixtures of nitrogen or carbon dioxide. Both of 

these formulations still contained substantial amounts of water, as water made up roughly 60% 

(median value) of the fluid in them (U.S. EPA, 2015b). Other formulations were rarely reported. 

Fluid formulations are discussed further in Chapter 5.

On average, hydraulic fracturing requires more than a million gallons (3.8 million liters) of water 

per well. Jackson et al. (2015) reported a national average of 2.4 million gal (9.1 million L) of water 

per well, calculated from FracFocus disclosures between 2010 and 2013. According to the EPA’s 

project database of disclosures to FracFocus 1.0 (hereafter the EPA FracFocus 1.0 project database), 

the median volume of water used per well was 1.5 million gal (5.7 million L) between 2011 and 

early 2013, based on 37,796 disclosures nationally (U.S. EPA, 2015b, c).2 Data on reported 

Information Handling Services well numbers and median volumes in Gallegos et al. (2015) show 

that overall per well volumes have increased in recent years from approximately 1.5 million gal (5.7 

million L) in 2011 to 2.7 million gal (10.2 million L) in 2014.3 

The recent increase in water use per well has been driven primarily by the proportional increase in 

horizontal wells (Gallegos et al., 2015) (Figure 4-1). Increases in horizontal well length affect total 

volumes injected primarily by allowing a larger fracture volume to be stimulated (Economides et 

al., 2013). As horizontal wells get longer, fracture, well, and total volumes all increase. Importantly, 

increases in the well length and water use per well do not necessarily mean an increase in water 

intensity (the amount of water used per unit energy extracted). Goodwin et al. (2014) found water 

 

evaporation (209.0 gal (791.2 L)/MWh). Similar results were found for gas extraction in the Eagle Ford Shale (Scanlon et 

al., 2014b). 

1 Leakoff is the fraction of the hydraulic fracturing fluid that infiltrates into the formation (e.g., through an existing natural 

fissure) and is not recovered during production. This water lost to the formation can be a substantial fraction of the water 

injected (O'Malley et al., 2015). See Chapter 6 for more information about leakoff and some recent findings related to the 

relationship between hydraulic fracturing fluid volume and fracture volume.

2 All water use data included in the EPA’s FracFocus 1.0 project database were obtained from disclosures made to 

FracFocus. 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, 2015c). For the purposes of 

this chapter, we discuss water use per disclosure in terms of water use per well.

3 Derived from supporting information in Gallegos et al. (2015). Calculated by multiplying the median volume by the 

number of wells for each well type, then summing volumes across well types, and dividing by the total number of wells. 
Chapter 4 – Water Acquisition

4-12 

intensity did not increase in the Denver Basin despite increases in well length and water use per 

well. 

 

Figure 4-1. Median water volume per hydraulically fractured well nationally, expressed by 

well type and completion year. 

Adapted using data from Gallegos et al. (2015). Note: shown in orange is the estimated median across all well 

types, derived from Gallegos et al. (2015) supporting information Tables S2 and S3. Calculated by multiplying the 

median volume by the number of wells for each well type, then summing volumes across well types, and dividing 

by the total number of wells for each year. This estimated median across all well types reflects the central 

tendency of the data, and was calculated because the individual data are proprietary and not published, 

preventing the calculation of an overall median. 

There is substantial variation around these per well estimates. For instance, the 10th and 90th

percentiles from the EPA FracFocus 1.0 project database are 74,000 gal and 6 million gal (280,000 L 

and 23 million L) per well, respectively.1 Even in specific basins, plays, and within a single oil and 

gas field, water use per well varies widely. For example, Laurenzi and Jersey (2013) reported 

volumes ranging from 1 to 6 million gal (3.8 to 23 million L) per well (10th to 90th percentile) in the 

Wattenberg Field in Colorado.

Of the major unconventional formation types discussed in Chapter 2 (shales, tight formationsincluding tight sands or sandstones, and coalbeds), coalbeds generally require less water per well. 

 

1 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.
Chapter 4 – Water Acquisition

4-13

Coalbed methane (CBM) comes from coal seams that often have a high initial water content and 

tend to occur at much shallower depths (U.S. EPA, 2015k). In part because of the shallower depths, 

shorter well lengths result in lower water use per well, often by an order of magnitude or more

compared to operations in shales or tight formations (e.g., Murray, 2013). 

4.4 Hydraulic Fracturing Water Use and Consumption at the National, State, 

and County Scale

In this section, we provide an overview of water use and consumption for hydraulic fracturing at 

the national, state, and county scale. We then compare these values to total water use and 

consumption at these scales. We do this to contextualize hydraulic fracturing water use and 

consumption with total water use and consumption, and to illustrate whether hydraulic fracturing 

is a relatively large or small user and consumer of water at these scales. Later, we compare 

hydraulic fracturing water use to water availability estimates at the county scale (Text Box 4-2). 

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 Class II wells, 

among other means.

Hydraulic fracturing water use is a function of the water use per well and the total number of wells 

fractured at a given spatial scale during the time period analyzed, calculated from the EPA 

FracFocus 1.0 project database (U.S. EPA, 2015c). Water consumption estimates are derived from 

United States Geological Survey (USGS) water use data, and therefore both use and consumption 

are presented with the published water use numbers being first.

4.4.1 National and State Scale

Hydraulic fracturing uses and consumes billions of gallons of water each year in the United States, 

but at the national and state scales, it is a relatively small user and consumer of water compared to 

total water use and consumption. According to the EPA’s FracFocus 1.0 project database, hydraulic 

fracturing used 36 billion gal (136 billion L) of water in 2011 and 52 billion gal (197 billion L) in 

2012, yielding an average annually of 44 billion gal (167 billion L) of water in 2011 and 2012 across 

all 20 states in the project database (U.S. EPA, 2015b, c). National water use for hydraulic fracturing 

can also be estimated by multiplying the water use per well by the number of wells hydraulically 

fractured. If the median water use per well (1.5 million gal) (5.7 million L) from the EPA’s 

FracFocus 1.0 project database is multiplied by 25,000 to 30,000 wells fractured annually (Chapter 

3), national water use for hydraulic fracturing is estimated to range from 38 to 45 billion gal (142 to 

170 billion L) annually. Other calculated estimates have ranged higher than this, including 

estimates of approximately 80 billion gal (300 billion L) (Vengosh et al., 2014) and 50 to 72 billion 

gal (190-273 billion L) (U.S. EPA, 2015e). These estimates are higher due to differences in the 

estimated water use per well and the number of wells used as multipliers. For example, Vengosh et 
Chapter 4 – Water Acquisition

4-14 

al. (2014) derived the estimate of approximately 80 billion gal (300 billion L) by multiplying an 

average of 4.0 million gal (15 million L) per well (estimated for shale gas wells) by 20,000 wells 

(the approximate total number of fractured wells in 2012).1

All of these estimates of water use for hydraulic fracturing are small relative to total water use and 

consumption at the national scale. The USGS compiles national water use estimates every five years 

in the National Water Census, with the most recent census conducted in 2010 (Maupin et al., 

2014).2The USGS publishes water use, not consumption estimates, yet by applying consumption 

factors for each use category in the 2010 National Water Census, we derived estimates of total 

water consumption. We also used a consumption factor to estimate hydraulic fracturing water 

consumption from values in the EPA FracFocus 1.0 project database.3 Comparing these estimates, 

average annual hydraulic fracturing water use in 2011 and 2012 was less than 1% of total 2010 

annual water use for all of the 20 states combined where operators reported water use to 

FracFocus in 2011 and 2012. Hydraulic fracturing water consumption followed the same pattern 

when compared to total water consumption (Appendix Table B-1).4

At the state scale, hydraulic fracturing also generally uses billions of gallons of water, but accounts 

for a low percentage of total water use or consumption. Of all states in the EPA FracFocus 1.0

project database, operators in Texas used the most water (47% of water use reported in the EPA 

FracFocus 1.0 project database) (U.S. EPA, 2015c) (Appendix Table B-1). This was due to the large 

number of wells in that state, since hydraulic fracturing water use is proportional to the number of 

wells. Over 94% of reported water use occurred in just seven of the 20 states in the EPA FracFocus

1.0 project database (listed in order of highest statewide hydraulic fracturing water use): Texas, 

Pennsylvania, Arkansas, Colorado, Oklahoma, Louisiana, and North Dakota (U.S. EPA, 2015c) 

(Appendix Table B-1). Hydraulic fracturing is a small percentage when compared to total water use 

(<1%) and consumption (<3%) in each individual state (Appendix Table B-1). Other studies have 

shown similar results, with hydraulic fracturing water use and consumption ranging from less than 

 

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 U.S. EPA (2015c) FracFocus 1.0 project database likely 

leads to a more robust estimate when used to calculate national 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.

2 The National Water Census includes uses such as public supply, irrigation, livestock, aquaculture, thermoelectric power, 

industrial, and mining at the national, state, and county scale. The 2010 National Water Census included hydraulic 

fracturing water use in the mining category; there was no designated category for hydraulic fracturing alone. 

3 See footnotes for Appendix Table B-1 or for Table 4-3 for a description of the consumption estimate calculations.

4 Water use percentages were calculated by averaging annual water use for hydraulic fracturing in 2011 and 2012 for a 

given state or county (U.S. EPA, 2015c), and then dividing by 2010 USGS total water use (Maupin et al., 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 

Water Census (Maupin et al., 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). Consumption estimates 

were calculated in the same manner, except consumption, not use, values were employed. County level data from the 

USGS 2010 Water Census are available online at http://water.usgs.gov/watuse/data/2010/ (accessed November 11, 

2014). 
Chapter 4 – Water Acquisition

4-15

1% of total use in West Virginia (West Virginia DEP, 2013), Colorado (Colorado Division of Water 

Resources et al., 2014), and Texas (Nicot et al., 2014; Nicot and Scanlon, 2012), to approximately 

4% in North Dakota (North Dakota State Water Commission, 2014). 

4.4.2 County Scale

Water use and consumption for hydraulic fracturing is also relatively small in most, but not all, 

counties in the United States (Table 4-3; Figure 4-2; Figure 4-3a,b; and Appendix Table B-2). Based 

on the EPA FracFocus 1.0 project database, reported fracturing water use in 2011 and 2012 was

less than 1% compared to 2010 USGS total water use in 299 of the 401 reporting counties (Figure 

4-3a; Appendix Table B-2). However, hydraulic fracturing water use was 10% or more compared to 

total water use in 26 counties, 30% or more in nine counties, and 50% or more in four counties 

(Table 4-3; Figure 4-3a). McMullen County in Texas had the highest percentage at over 100% 

compared to 2010 total water use.1 Total consumption estimates followed the same pattern, but 

with more counties in the higher percentage categories (hydraulic fracturing water consumption 

was 10% or more compared to total water consumption in 53 counties; 30% or more in 25 

counties; 50% or more in 16 counties; and over 100% in four counties) (Table 4-3; Figure 4-3b). 

Estimates based on the EPA’s FracFocus 1.0 project database may form an incomplete picture of 

hydraulic fracturing water use in a given state or county, because the majority of states with data in 

the project database did not require disclosure to FracFocus during the time period analyzed (U.S. 

EPA, 2015b). We conclude that this likely does not substantially alter the overall patterns observed

in Figure 4-3a,b. See Text Box 4-1 for further details. These percentages also depend both upon the 

absolute water use and consumption for hydraulic fracturing and the relative magnitude of other 

water uses and consumption in that state or county. For instance, a rural county with a small 

population might have relatively low total water use prior to hydraulic fracturing.2 Also, just 

because water is used in a certain county does not necessarily mean it originated in that county. 

The cost of trucking water can be substantial (Slutz et al., 2012), and the industry tends to acquire 

water from nearby sources when possible (Section 4.2.1); however, water can also be piped in from 

more distant, regional supplies. Despite these caveats, it is clear that hydraulic fracturing is 

generally a relatively small user (and consumer) of water at the county level, with the exception of a 

small number of counties where water use and consumption for fracturing can be high relative to 

other uses and consumption. 

 

1 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). 
Chapter 4 – Water Acquisition

4-16 

Table 4-3. Average annual 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). Average annual hydraulic fracturing water use data in 2011 and 2012 from 

the EPA’s FracFocus 1.0 project database (U.S. EPA, 2015c). Total annual water use data in 2010 from the USGS 

(Maupin et al., 2014). States listed by order of appearance in the chapter. 

State County

Total annual 

water use in 

2010 (millions 

of gal)a

Average annual

hydraulic 

fracturing water 

use in 2011 and 

2012 

(millions of gal)b

Hydraulic 

fracturing 

water use 

compared to 

total water 

use (%)c

Hydraulic fracturing 

water consumption 

compared to total 

water consumption 

(%)c,d

Texas McMullen 657.0 745.9 113.5 350.4

Karnes 1861.5 1055.2 56.7 120.1

La Salle 2474.7 1288.7 52.1 93.7

Dimmit 4073.4 1794.2 44.0 81.3

Irion 1335.9 411.4 30.8 74.5

Montague 3989.5 925.3 23.2 77.8

De Witt 2394.4 546.6 22.8 48.6

Loving 781.1 138.4 17.7 94.1

San Augustine 1131.5 182.1 16.1 50.8

Live Oak 1916.3 294.0 15.3 40.1

Wheeler 6522.6 858.0 13.2 21.5

Cooke 4533.3 454.3 10.0 29.9

Pennsylvania Susquehanna 1617.0 751.3 46.5 123.4

Sullivan 222.7 66.5 29.9 79.8

Bradford 4354.5 1059.4 24.3 78.2

Tioga 2909.1 566.3 19.5 47.3

Lycoming 5854.6 704.6 12.0 33.8

West Virginia Doddridge 405.2 78.5 19.4 69.4

Ohio Carroll 1127.9 152.7 13.5 37.3

North Dakota Mountrail 1248.3 449.4 36.0 98.3

Dunn 1076.8 309.5 28.7 43.1

Burke 394.2 63.6 16.1 40.8

Divide 806.7 102.2 12.7 18.6
Chapter 4 – Water Acquisition

4-17

State County

Total annual 

water use in 

2010 (millions 

of gal)a

Average annual

hydraulic 

fracturing water 

use in 2011 and 

2012 

(millions of gal)b

Hydraulic 

fracturing 

water use 

compared to 

total water 

use (%)c

Hydraulic fracturing 

water consumption 

compared to total 

water consumption 

(%)c,d

Arkansas Van Buren 1587.8 899.6 56.7 168.8

Louisiana Red River 1606.0 569.6 35.5 83.2

Sabine 1522.1 395.2 26.0 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 et al., 2014). 

b Average of water used for hydraulic fracturing in 2011 and 2012 calculated from the EPA FracFocus 1.0 project database (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 state or county (U.S. EPA, 2015c), and then dividing by 2010 USGS total water use (Maupin et al., 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 (Diehl and Harris, 2014). 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 Class II wells – see Chapter 8.
Chapter 4 – Water Acquisition

4-18 

Figure 4-2. Average annual hydraulic fracturing water use in 2011 and 2012 by county. 

Source: U.S. EPA (2015c). Water use in millions of gallons (Mgal). Counties shown with respect to major U.S. Energy Information Administration (EIA) shale 

basins (EIA, 2015). Orange borders identify states that required some degree of reporting to FracFocus in 2011 and 2012.
Chapter 4 – Water Acquisition

4-19 

(a)

(b) 

Figure 4-3. (a) Average annual hydraulic fracturing water use in 2011 and 2012 compared to 

total annual water use in 2010, by county, expressed as a percentage; (b) Average annual

hydraulic fracturing water consumption in 2011 and 2012 compared to total annual water 

consumption in 2010, by county, expressed as a percentage.

Average annual hydraulic fracturing water use data in 2011 and 2012 from the EPA’s FracFocus 1.0 project 

database (U.S. EPA, 2015c). Total annual water use data in 2010 from the USGS (Maupin et al., 2014). See Table 4-3

for descriptions of calculations for estimating consumption. Counties shown with respect to major U.S. EIA shale 

basins (EIA, 2015). Orange borders identify states that required some degree of reporting to FracFocus in 2011 and 

2012. Note: Values over 100% denote counties where the average annual hydraulic fracturing water use or 

consumption in 2011 and 2012 exceeded the total annual water use or consumption in that county in 2010. 
Chapter 4 – Water Acquisition

4-20 

Text Box 4-1. Using the EPA’s FracFocus 1.0 Project Database to Estimate Water Use for 

Hydraulic Fracturing.

The FracFocus Chemical Disclosure Registry (often referred to as FracFocus; www.fracfocus.org) is a national 

hydraulic fracturing chemical disclosure registry managed by the Ground Water Protection Council and the 

Interstate Oil and Gas Compact Commission. FracFocus was created to provide the public access to reported 

chemicals used for hydraulic fracturing within their area. It was originally established in 2011 (version 1.0) 

for voluntary reporting by oil and gas well operators. The EPA used the data available from FracFocus 

between January 1, 2011 and February 28, 2013 to develop the EPA FracFocus 1.0 project database; the 

database and a related EPA report were both peer reviewed and published (U.S. EPA, 2015b, c). Six of the 20 

states discussed in this assessment required disclosure to FracFocus at various points during this time; 

another three of the 20 states offered the choice of reporting to FracFocus or the state during this same time 

period (U.S. EPA, 2015b). Estimates based on the EPA’s FracFocus 1.0 project database could form an 

incomplete picture of hydraulic fracturing water use, because most states with data in the project database 

(14 out of 20) did not require disclosure to FracFocus during the time period analyzed (U.S. EPA, 2015b). 

Water use for fracturing is a function of the water use per well and the total number of wells fractured over a 

given spatial area or a given period of time. For water use per well, we found seven literature values for 

comparison with values from the EPA’s FracFocus 1.0 project database. On average, water use estimates per 

well in the project database were 77% of literature values (the median was 86%); Colorado’s Denver Basin 

was the only location where the project database estimate as a percentage of the literature estimate was low 

(14%) (Appendix Table B-3). In general, water use per well estimates from the EPA’s FracFocus 1.0 project 

database appear to align closely with the literature estimates for most areas for which we have data, with the 

exception of the Denver Basin of Colorado. 

For the number of wells, we compared data in the EPA’s FracFocus 1.0 project database to numbers available 

in state databases from North Dakota, Pennsylvania, and West Virginia (Appendix Table B-4). These were the 

state databases from which we could distinguish hydraulically fractured wells from other oil and gas wells. 

On average, we found that the EPA FracFocus 1.0 project database included 67% of the wells listed in state 

databases for 2011 and 2012 (Appendix Table B-4). Unlike North Dakota and Pennsylvania, West Virginia did 

not require operators to report fractured wells to FracFocus during this time period, possibly explaining its 

lower reporting rate. Multiplying the average EPA FracFocus 1.0 project database values of 77% for water use 

per well and 67% for well counts yields 52%. Thus, the EPA FracFocus 1.0 project database estimates for 

water use could be slightly over half of the estimates from these three state databases during this time period. 

These values are based on small sample sizes (seven literature values and three state databases) and should 

be interpreted with caution. Nevertheless, these numbers suggest that estimates based on the EPA’s 

FracFocus 1.0 project database likely form an incomplete picture of hydraulic fracturing water use during this 

time period.

To assess how this might affect hydraulic fracturing water use estimates in this chapter, we doubled the 

water use value in the EPA’s FracFocus 1.0 project database for each county, an adjustment much higher than 

any likely underestimation. Even with this adjustment, fracturing water use was still less than 1% compared 

to 2010 total water use in the majority of the 401 U.S. counties represented in the EPA FracFocus 1.0 project 

database (299 counties without adjustment versus 280 counties with adjustment). The number of counties 

where hydraulic fracturing water use was 30% or more of 2010 total county water use increased from nine to 

21 with the adjustment. 

These results indicate that most counties have relatively low hydraulic fracturing water use relative to total 

water use, even when accounting for likely underestimates. Since consumption estimates are derived from 

use, these will also follow the same pattern. Thus, potential underestimates based on the EPA’s FracFocus 1.0

project database likely do not substantially alter the overall pattern shown in Figure 4-3. Rather, 

underestimates of hydraulic fracturing water use would mostly affect the percentages in the small number of 

counties where fracturing already constitutes a higher percentage of total water use and consumption.
Chapter 4 – Water Acquisition

4-21 

4.5 Potential for Impacts by Location

The potential for hydraulic fracturing water acquisition to impact drinking water availability or 

alter its quality depends on the balance between water withdrawals and water availability at a 

given location. Where water availability is high compared to the volume of water withdrawn for 

hydraulic fracturing, this water use can be accomodated. However, where water availability is low 

and hydraulic fracturing water use is high, these withdrawals are more likely to impact drinking 

water resources. The balance between withdrawals and availability can vary greatly by geographic 

location. Moreover, a combination of regional or site-specific factors can alter this balance, making 

impacts more or less likely, or more or less severe. For these reasons, we discuss the various factors 

and potential for impacts by geographic location in the following section. 

We organize this discussion by state, addressing 15 states accounting for almost all disclosures

reported in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c): Texas (Section 4.5.1); 

Colorado and Wyoming (Section 4.5.2); Pennsylvania, West Virginia, and Ohio (Section 4.5.3); North 

Dakota and Montana (Section 4.5.4); Arkansas and Louisiana (Section 4.5.5), Oklahoma and Kansas 

(Appendix B.2.1); and Utah, New Mexico, and California (Appendix B.2.2). We highlight the states 

that best illustrate concepts relating to the potential for impacts, or factors that affect the frequency 

or severity of these impacts in Section 4.5; the remaining states are discussed in Appendix B.2. 

Within Section 4.5 and Appendix B, we address each state in order of most hydraulically fractured 

wells to least, and combine states with similar geographies or activity. For certain states, we 

address major oil and gas regions separately (e.g., the Permian Basin in Texas). Each section 

describes the number of fractured wells in that state or region, the type of water used, water use 

per well, and water use estimates at the county scale. We then discuss the potential for impacts by 

comparing water use and water availability and addressing factors (e.g., drought or the amount of 

water reused to offset fresh water use) that might alter the frequency or severity of impacts. As 

noted in the chapter introduction, we use several lines of evidence to evaluate the potential for 

impacts and factors for each location. We use the scientific literature, county level assessments, and 

local case studies where available.

4.5.1 Texas

Hydraulic fracturing in Texas accounts for the bulk of the activity reported nationwide, comprising 

48% of the disclosures in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c) (Figure 4-4; 

Appendix Table B-5). There are five major basins in Texas: the Permian, Western Gulf (includes the 

Eagle Ford play), Fort Worth (includes the Barnett play), TX-LA-MS Salt (includes the Haynesville 

play), and the Anadarko (Figure 4-5); together, these five basins contain 99% of Texas’ reported 

wells (Appendix Table B-5).
Chapter 4 – Water Acquisition

4-22 

Figure 4-4. Locations of wells in the EPA FracFocus 1.0 project database, with respect to U.S. 

EIA shale plays and basins. 

Note: Hydraulic fracturing can be conducted in geologic settings other than shale; therefore, some wells on this 

map are not associated with any EIA shale play or basin (EIA, 2015; U.S. EPA, 2015c). 

Figure 4-5. Major U.S. EIA shale plays and basins for Texas. 

Source: EIA (2015). 
Chapter 4 – Water Acquisition

4-23 

Types of water used: What is known about water sources in Texas largely comes from direct surveys 

and interviews with industry operators and water suppliers (Nicot et al., 2014; Nicot et al., 2012). 

Overall, groundwater is the dominant source throughout most of the state (Nicot et al., 2014; Nicot 

et al., 2012) (Table 4-1). The exception is the Barnett Shale, where both surface water and 

groundwater are used in approximately equal proportions. 

Hydraulic fracturing in Texas uses mostly fresh water (Nicot et al., 2012).1 The exception is the far 

western portion of the Permian Basin, where brackish water makes up an estimated 80% of total 

hydraulic fracturing water use. Brackish water is used to a lesser extent in the Anadarko Basin, the 

Midland portion of the Permian Basin, and the Eagle Ford Shale (Table 4-4). Reuse of wastewater as 

a percentage of total water use is generally low (5% or less) in all major basins and plays in Texas, 

except for the Anadarko Basin in the Texas Panhandle, where it is 20% (Nicot et al., 2012) (Table 

4-2). 

Table 4-4. Estimated brackish water use as a percentage of total hydraulic fracturing water 

use in the main hydraulic fracturing areas of Texas, 2011.a

Adapted from Nicot et al. (2012).

b

Play Percentage

Barnett Shale 3%

Eagle Ford Shale 20%

Texas portion of the TX-LA-MS Salt Basinc 0%

Permian Basin―Far West 80%

Permian Basin―Midland 30%

Anadarko Basin 30%

a Nicot et al. (2012) define brackish water as any water with a total dissolved solids (TDS) content of >1,000 mg/L, but <35,000 

mg/L, although they often limit that range to between 1,000 and 10,000 mg/L.

b 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%.

c Nicot et al. (2012) refer to this region of Texas as the East Texas Basin.

The majority of water used in Texas for hydraulic fracturing is self-supplied via direct ground or 

surface water withdrawals (Nicot et al., 2014). Less often, water is purchased from local 

landowners, municipalities, larger water districts, or river authorities (Nicot et al., 2014). 

Water use per well: Water use per well varies across Texas basins, with reported medians from 

2011 to early 2013 of 3.9 million gal (14.8 million L) in the Fort Worth Basin, 3.8 million gal 

(14.4 million L) in the Western Gulf, 3.3 million gal (12.5 million L) in the Anadarko, 3.1 million gal 

(11.7 million L) in the TX-LA-MS Salt, and 840,000 gal (3.2 million L) in the Permian (Appendix 

 

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, 2015b). Nineteen percent of Texas disclosures included information related to water 

sources (U.S. EPA, 2015b). 
Chapter 4 – Water Acquisition

4-24 

Table B-5). Relatively low water use in the Permian Basin, which contains roughly half the reported 

wells in the state, is due to the abundance of vertical wells, mostly for oil extraction (Nicot et al., 

2012). 

Water use per well is increasing in most locations in Texas. In the Barnett Shale, water use per well 

increased from approximately 3 million gal (11 million L) in the mid-2000’s to approximately 5 

million gal (19 million L) in 2011 as the horizontal lengths of wells increased (Nicot et al., 2014). 

Similar increases in lateral length and water use per well were reported for the Texas-Haynesville, 

East Texas, and Anadarko basins, and most of the Permian Basin (Nicot et al., 2012; Nicot and 

Scanlon, 2012).1 

Water use/consumption at the county scale: Water use and consumption for hydraulic fracturing can 

be significant in some Texas counties. Texas contains five of nine counties nationwide where 

operators used more than 1 billion gal (3.8 billion L) of water annually for hydraulic fracturing, and 

five of nine counties where fracturing water use in 2011 and 2012 was 30% or more compared to 

total water use in those counties in 2010 (Table 4-3, Figure 4-3a; Appendix Table B-2).2

According to detailed county level projections, water use for hydraulic fracturing is expected to 

increase with oil and gas production in the coming decades, peaking around the year 2030 (Nicot et 

al., 2012). These projections were made before the recent decline in oil and gas prices, and so are 

highly uncertain. If these projections hold, the majority of counties are expected to have relatively 

low water use for fracturing in the future, but hydraulic fracturing water use could equal or exceed 

10%, 30%, and 50% compared to 2010 total county water use in 30, nine, and three counties, 

respectively, by 2030 (Appendix Table B-7). 

Potential for impacts: Of all locations surveyed in this chapter, the potential for water quantity and 

quality impacts due to hydraulic fracturing water acquisition appears to be highest in southern and 

western Texas. This area includes the Anadarko, the Western Gulf (Eagle Ford play), and the 

Permian Basins. According to Ceres (2014), 28% and 87% of the wells fractured in the Eagle Ford 

play and Permian Basin, respectively, are in areas of high to extremely high water stress.3 A 

comparison of hydraulic fracturing water use to water availability at the county scale also suggests 

the potential for impacts in this region (Text Box 4-2). 

 

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 et al., 2014; Laurenzi and Jersey, 2013). 

2 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 (Table 4-3). Nicot and Scanlon (2012) found similar variation among 

counties when they compared hydraulic fracturing water consumption to total county water consumption for the Barnett 

play. Their 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 10.5% 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).
Chapter 4 – Water Acquisition

4-25 

Text Box 4-2. Hydraulic Fracturing Water Use as a Percentage of Water Availability Estimates.

Researchers at Sandia National Laboratories assessed county level water availability across the continental 

United States (Tidwell et al., 2013). Assessments of water availability in the United States are generally 

lacking at the county scale, and this analysis—although undertaken for siting new thermoelectric power 

plants—can be used to assess potential impacts of hydraulic fracturing water withdrawals. 

The authors generated annual water availability estimates for five categories of water: unappropriated 

surface water, unappropriated groundwater, appropriated water potentially available for purchase, brackish 

groundwater, and wastewater from municipal treatment plants (Tidwell et al., 2013). In the western United 

States, water is generally allocated by the principle of prior appropriation—that is, first in time of use is first 

in right. New development must use unappropriated water or purchase appropriated water from vested 

users. In their analysis, the authors assumed 5% of appropriated irrigated water could be purchased; they 

also excluded wastewater required to be returned to streams and the wastewater fraction already reused. 

Given regulatory restrictions, they considered no fresh water to be available in California for new 

thermoelectric plants. Their definition of brackish water ranged from 3,000 to 10,000 ppm TDS, and from 50 

to 2,500 ft (15-760 m) below the surface. 

Combining their estimates of unappropriated surface water and groundwater and appropriated water 

potentially available for purchase, we derived a fresh water availability estimate for each county (except for 

those in California) and then compared this value to reported water use for hydraulic fracturing in 2011 and 

2012 (U.S. EPA, 2015c). We also added the estimates of brackish groundwater and wastewater from 

municipal treatment plants to fresh water estimates to derive estimates of total water availability and did a 

similar comparison. Since the water availability estimates already take into account current water use for oil 

and gas operations, these results should be used only as indicator of areas where shortages might arise in the 

future. Here we focus on hydraulic fracturing water use compared to water availability. If we compared 

hydraulic fracturing water consumption to water availability, consumption would be lower relative to 

availability since by definition, water consumption is less than water use. Hence, water use versus availability 

acts as an upper-bound estimate, and includes consumption.

Overall, hydraulic fracturing water use represented less than 1% of fresh water availability in over 300 of the 

395 counties analyzed (Figure 4-6a). This result suggests that there is ample water available at the county 

scale to accommodate hydraulic fracturing in most locations. However, there was a small number of counties 

where hydraulic fracturing water use was a relatively high percentage of fresh water availability. In 17 

counties, fracturing water use actually exceeded the index of fresh water available; all of these counties were 

located in the state of Texas and were associated with the Anadarko, Barnett, Eagle Ford, and Permian 

basins/plays (Figure 4-5). In Texas counties with relatively high brackish water availability, hydraulic 

fracturing water use represented a much smaller percentage of total water availability (fresh + brackish + 

wastewater) (Figure 4-6b). This finding illustrates that potential impacts can be avoided or reduced in these 

counties through the use of brackish water or wastewater for hydraulic fracturing; a case study in the Eagle 

Ford play in southwestern Texas echoes this finding (Text Box 4-3).

(Text Box 4-2 is continued on the following page.)
Chapter 4 – Water Acquisition

4-26 

Text Box 4-2 (continued). Hydraulic Fracturing Water Use as a Percentage of Water 

Availability Estimates.

(a) 

(b) 

Figure 4-6. Average annual 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, 2015). Orange borders identify states that required 

some degree of reporting to FracFocus in 2011 and 2012. Data from U.S. EPA (2015c) 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. The total water available for California is the sum of brackish water plus wastewater only.
Chapter 4 – Water Acquisition

4-27 

Surface water availability is generally low in southern and western Texas (Figure 4-7a), and both 

fracturing operations and residents rely heavily on groundwater (Figure 4-7b). Similar to trends 

nationally, groundwater aquifers in Texas have experienced substantial declines caused by 

withdrawals (Konikow, 2013; TWDB, 2012; George et al., 2011). Groundwater in the Pecos Valley, 

Gulf Coast, and Ogallala aquifers in southern and western Texas is estimated to have declined by 

roughly 5, 11, and 44 mi3 (21, 45.5, and 182 km3), respectively, between 1900 and 2008 (Konikow, 

2013).1

 (a)

(b)

Figure 4-7. (a) Estimated annual surface water runoff from the USGS; (b) Reliance on

groundwater as indicated by the ratio of groundwater pumping to stream flow and pumping. 

Estimates for Figure 4-7a 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, 2014c). Higher ratios (darker blues) in Figure 4-7b indicate greater reliance on groundwater. Figure 

adapted from Tidwell et al. (2012), using data provided by the U.S. Department of Energy’s Sandia National 

Laboratories on December 12, 2014. 

 

1 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. Groundwater depletion from the Carrizo-Wilcox aquifer is included in the estimate for the southern portion 

of the Gulf Coast aquifer (Konikow, 2013). 
Chapter 4 – Water Acquisition

4-28 

Groundwater quality degradation associated with aquifer pumping and the cumulative effects of all 

water users is well documented in the southern portion of the Ogallala aquifer. The quality of 

groundwater used by many private, public supply, and irrigation wells is poorest in the aquifer’s 

southern portion, with elevated concentrations of TDS, chloride, nitrate, fluoride, manganese, 

arsenic, and uranium (Chaudhuri and Ale, 2014a; Gurdak et al., 2009; McMahon et al., 2007).1

Extensive groundwater pumping can alter the quality of drinking water resources by inducing 

vertical mixing of high-quality groundwater with recharge water from the land surface that has 

been contaminated by nitrate or pesticides, or with lower-quality groundwater from underlying 

geologic formations (Gurdak et al., 2009; Konikow and Kendy, 2005). Pumping can also promote 

changes in reduction-oxidation (redox) conditions and thereby mobilize chemicals from geologic 

sources (e.g., uranium) (DeSimone et al., 2014). Similar patterns of groundwater quality 

degradation associated with prolonged aquifer depletion (i.e., salinization and contamination) have 

also been observed in other Texas aquifers, notably the northwest Edwards-Trinity (plateau), Pecos 

Valley, Carrizo-Wilcox, and southern Gulf Coast aquifers.2 

The Texas Water Development Board (TWDB) estimates that overall demand for water (including 

water for hydraulic fracturing) out to the year 2060 will outstrip supply in southern and western 

Texas (TWDB, 2012). Furthermore, the TWDB expects groundwater supply in the major aquifers to 

decline by 30% between 2010 and 2060, mostly due to declines in the Ogallala aquifer (TWDB, 

2012).3,4 Irrigated agriculture is by far the dominant user of water from the Ogallala aquifer 

(Gurdak et al., 2009), but fracturing operations, along with other uses, now contribute to the 

aquifer’s depletion. 

The state has also experienced moderate to extreme drought conditions for much of the last decade, 

and the second-worst and longest drought in Texas history between March 2010 and November 

2014 (TWDB, 2016; National Drought Mitigation Center, 2015) (Figure 4-8). Sustained drought 

conditions compound water availability concerns, and climate change is expected to place further 

stress on groundwater both now and in the future (Aghakouchak et al., 2014; Melillo et al., 2014) 

(Chapter 2). In their evaluation of the potential impact of climate change on groundwater recharge 

in the western United States, Meixner et al. (2016) show the largest declines in recharge are 

expected in specific aquifers in the southwestern United States, including the southern portion of 

the Ogallala aquifer, which is expected to receive 10% less recharge through the year 2050. 

 

1 Elevated levels of these constituents result from both natural processes and human activities, such as groundwater

pumping (Chaudhuri and Ale, 2014a; Gurdak et al., 2009).

2 Persistent salinity has been observed in west Texas, specifically in the southern Ogallala, northwest Edwards-Trinity 

(plateau), and Pecos Valley aquifers, largely due to prolonged irrigational groundwater pumping and ensuing alteration of 

hydraulic gradients leading to groundwater mixing (Chaudhuri and Ale, 2014b). High levels of groundwater 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, 2013; 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). 

3 TWDB (2012) defines groundwater supply as the amount of groundwater that can be produced given current permits 

and existing infrastructure. By contrast, TWDB (2012) defines groundwater availability as the amount of groundwater

that is available regardless of legal or physical availability. Total groundwater availability in Texas is expected to decline 

by approximately 24% between 2010 and 2060 (TWDB, 2012). 

4 This message is echoed in the 2017 Texas State Water Plan (TWDB, 2016). 
Chapter 4 – Water Acquisition

4-29 

Groundwater moves slowly, and natural recharge rates are lower during times of drought 

(DeSimone et al., 2014). Consequently, as water withdrawals continue to outpace the rate of 

recharge, aquifer storage will decline further (USGS, 1999), potentially impacting both drinking 

water resource quantity and quality. For example, research from Steadman et al. (2015) in the 

Eagle Ford play shows that hydraulic fracturing groundwater consumption exceeds estimated 

recharge rates in the seven most active counties for drilling. 

Figure 4-8. Percentage of weeks in drought between 2000 and 2013 by county.

Drought for a given week is defined as any portion of a given U.S. county having a weekly classification of

moderate to exceptional drought (D1-D4 categorization) according to the National Drought Mitigation Center 

(http://droughtmonitor.unl.edu); number of weeks = 731.

A case study in the Eagle Ford play in southwestern Texas compared water demand for hydraulic

fracturing with water supplies at the scale of the play, county, and 1 mi2 (2.6 km2) (Scanlon et al.,

2014b). The authors observed generally adequate water supplies for hydraulic fracturing, except in

specific locations, where they found excessive drawdown of groundwater locally in ~6% of the play 

area, with estimated declines of ~100-200 ft (31-61 m) after hydraulic fracturing activity increased 

in 2009 (Text Box 4-3).
Chapter 4 – Water Acquisition

4-30 

Text Box 4-3. Case Study: Water Profile of the Eagle Ford Play, Texas.

Researchers from the University of Texas published a detailed case study of water supply and demand for 

hydraulic fracturing in the Eagle Ford play in southwestern Texas (Scanlon et al., 2014b). This effort 

assembled detailed information from state and local water authorities, and proprietary industry data on 

hydraulic fracturing, to develop a portrait of water resources in this 16-county area.

Scanlon et al. (2014b) compared water demand for hydraulic fracturing currently and over the projected play 

life (20 years) relative to water supply from groundwater recharge, groundwater storage (brackish and 

fresh), and stream flow. Using groundwater availability models developed by the Texas Water Development 

Board, they reported that water demand for hydraulic fracturing in 2013 was 30% of annual groundwater

recharge in the play area, and over the 20-year play lifespan it was projected to be 26% of groundwater

recharge, 5-8% of fresh groundwater storage, and 1% of brackish groundwater storage. The dominant water 

user in the play is irrigation (57 to 61% of water use, 62 to 65% of consumption), as compared with hydraulic 

fracturing (13% of water use and 16% of consumption). At the county level, projected water demand for 

hydraulic fracturing over the 20-year period was low relative to freshwater supply (ranging from 0.6-27% by

county, with an average of 7.3%). Similarly, projected total water demand from all uses was low relative to 

supply, excluding two counties with high irrigation demands (Frio, Zavala), and one county with no known 

groundwater supplies (Maverick).

Although supply was found to be sufficient even in this semi-arid region, there were important exceptions, 

especially at sub-county scales. The researchers found no water level declines over much of the play area 

assessed (69% of the play area), yet in some areas they estimated groundwater drawdowns of 50 ft (15 m) or 

more (19% of the play area), 100 ft (31 m) or more (6% of the play area), and 200 ft (60 m) or more 

(approximately 2% of the play area). This was corroborated with well monitoring data that showed a sharp 

decline in water levels in several groundwater monitoring wells after hydraulic fracturing activity increased 

in 2009. 

The researchers further concluded that shifting toward brackish groundwater is feasible, as evidenced by 

operators already doing so. This shift could further reduce impacts on fresh water resources and provide a 

large source of water for future hydraulic fracturing. In a 2011 estimate, approximately 20% of water used in 

the play came from brackish sources (Table 4-4), and anecdotal evidence suggests this practice has increased 

since then (Scanlon et al., 2014b). Projected hydraulic fracturing water use represents less than 1% of total 

brackish groundwater storage in the play area. By contrast, Scanlon et al. (2014b) concluded there is limited 

potential for reuse of wastewater in this play because of the small volumes that return to the surface during 

production (less than or equal to 5% of hydraulic fracturing water requirements). 

In contrast to southern and western Texas, the potential for water quantity and quality effects 

appears to be lower in the north-central and eastern parts of the state, in areas including the 

Barnett and Haynesville plays. Residents obtain water for domestic use—which includes use of 

water for drinking—from a mixture of groundwater and surface water sources (Appendix Table B6). Counties encompassing Dallas and Fort Worth rely mostly on publicly-supplied surface water 

(TWDB, 2012) (Appendix Table B-6). The Trinity aquifer in northeast Texas is projected to decline 

only slightly between 2010 and 2060 (TWDB, 2012). Nevertheless, Bene et al. (2007) estimate that 

hydraulic fracturing groundwater withdrawals will increase from 3% of total groundwater use in 

2005 to 7%–13% in 2025, suggesting the potential for localized aquifer drawdown. Groundwater 

quality degradation associated with aquifer drawdown has been documented in the Trinity and 

Woodbine aquifers overlying much of the Barnett play, with both aquifers showing high levels of 

salinization (Chaudhuri and Ale, 2013). 
Chapter 4 – Water Acquisition

4-31 

Overall, the potential for impacts appears higher in western and southern Texas, compared to the 

northeast part of the state. Groundwater withdrawals for hydraulic fracturing, along with irrigation 

and other uses, may contribute to water quality degradation associated with intensive aquifer 

pumping in western and southern Texas. Areas with numerous high-capacity wells and large 

amounts of sustained groundwater pumping are most likely to experience groundwater quality 

degradation associated with withdrawals (Gurdak et al., 2009; McMahon et al., 2007). Further, 

given that Texas is prone to drought conditions and groundwater recharge is limited, the already 

declining aquifers in southern and western Texas are especially vulnerable to further groundwater

depletion and resulting impacts to groundwater quantity and quality (Gurdak et al., 2009; Jackson 

et al., 2001). Impacts are likely to be localized drawdowns of groundwater, as shown by a detailed 

case study of the Eagle Ford play (Text Box 4-3). Scanlon et al. (2014b) suggested that a shift 

toward brackish water use could minimize potential future impacts to fresh water resources. This 

finding is consistent with our county level data (Text Box 4-2). 

4.5.2 Colorado and Wyoming 

Colorado had the second highest number of disclosures in the EPA FracFocus 1.0 project database, 

(13% of disclosures) (Figure 4-4 and Appendix Table B-5). We combine Colorado and Wyoming 

because of their shared geology of the Denver Basin (including the Niobrara play) and the Greater 

Green River Basin (Figure 4-9). There are three major basins reported for Colorado: the Denver 

Basin; the Uinta-Piceance Basin; and the Raton Basin. Together these basins contain 99% of 

reported wells in the state, although the bulk of the activity in Colorado is in the Denver Basin 

(Appendix Table B-5). Fewer wells (roughly 4% of disclosures in the EPA FracFocus 1.0 project 

database) are reported in Wyoming. There are two major basins reported for Wyoming (Greater 

Green River and Powder River) that together contain 86% of activity in the state (Appendix Table 

B-5). 

Figure 4-9. Major U.S. EIA shale plays and basins for Colorado and Wyoming.

Source: EIA (2015). 
Chapter 4 – Water Acquisition

4-32 

Types of water used: Water for hydraulic fracturing in Colorado and Wyoming comes from both 

groundwater and surface water, as well as reused wastewater (Colorado Division of Water 

Resources et al., 2014; BLM, 2013). Publicly available information on water sources for each state 

generally comes in the form of a list of potential sources, and detailed information on the types of 

water used for hydraulic fracturing is not readily accessible.1 In northwestern Colorado’s Garfield 

County (Uinta-Piceance Basin), the U.S. EPA (2015e) reports that any fresh water used for 

fracturing comes from surface water sources. In the Denver Basin (Niobrara play) of southeastern 

Wyoming, qualitative information suggests that groundwater supplies much of the water used for 

fracturing, although no data were available to characterize the ratio of groundwater to surface 

water withdrawals (AMEC Environment & Infrastructure, 2014; BLM, 2013; Tyrrell, 2012). 

Non-fresh water sources, including industrial and municipal wastewater, brackish groundwater, 

and reused hydraulic fracturing wastewater, are sometimes listed as potential alternatives to fresh 

water for fracturing in both Colorado and Wyoming (Colorado Division of Water Resources et al., 

2014; BLM, 2013); no data are available to show the extent to which these non-fresh water sources 

are used at the state or basin level. Based on discussions with industry, the U.S. EPA (2015e)

reports that fresh water is used solely for drilling and reused wastewater supplies nearly all the 

water for hydraulic fracturing in Colorado’s Garfield County. This estimate of reused wastewater as 

a percentage of injected volume is markedly higher than in other locations and likely results from 

the geologic characteristics of the Piceance tight sand formation, which has naturally high water 

content and produces large volumes of relatively high-quality wastewater (U.S. EPA, 2015e).

In contrast, a study by Goodwin et al. (2014) assumed no reuse of wastewater for hydraulic 

fracturing operations by Noble Energy in the Denver-Julesburg Basin of northeastern Colorado 

(Table 4-2). It is unclear whether this assumption is indicative of reuse practices of other 

companies in the Denver-Julesburg Basin. The difference in reused wastewater rates reported by

the U.S. EPA (2015e) and Goodwin et al. (2014) may indicate an east-west divide in Colorado (i.e., 

low reuse in the east versus high reuse in the west), due at least in part to differences in wastewater 

volumes available for reuse. However, further information is needed to adequately characterize 

reuse patterns in Colorado. 

Water use per well: Water use per well varies across Colorado, with median values of 1.8 million, 

400,000, and 96,000 gal (6.8 million, 1.5 million, and 360,000 L) in the Uinta-Piceance, Denver, and 

Raton Basins, respectively, according to the EPA FracFocus 1.0 project database (Appendix Table B5). Relatively low water volumes per well are reported in Wyoming (Appendix Table B-5). Low 

volumes reported for the Raton Basin of Colorado and the Powder River Basin of Wyoming are 

likely due to the prevalence of CBM extraction in these locations (U.S. EPA, 2015k; Sando et al., 

2014). 

More difficult to explain are the low volumes reported for the Denver Basin in the EPA FracFocus

1.0 project database. These values are lower than volumes reported in other non-CBM basins 

1 The Colorado Oil and Gas Conservation Commission collects information on the sources and quality of water used for 

hydraulic fracturing, including reused wastewater, with Form 5A, and has done so since June 2012; however, these data 

are in PDFs linked to individual wells and are not aggregated into a searchable database.
Chapter 4 – Water Acquisition

4-33 

included in Appendix Table B-5. Goodwin et al. (2014) report much higher water use per well in the 

Denver Basin from 2010 to 2013, with a median of 2.8 million gal (10.6 million L) (although only 

usage for the Wattenberg Field was reported). Indeed, the 10th−90th percentiles (2.4-3.8 million gal) 

(9.1-14.4 million L) from Goodwin et al. (2014) are almost completely above those from the EPA 

FracFocus 1.0 project database for the Denver Basin (Appendix Table B-5).1 However, it is difficult 

to draw clear conclusions because of differences in scale (i.e., field in Goodwin et al. (2014) versus 

basin in the EPA FracFocus 1.0 project database) and operators (i.e., Noble Energy in Goodwin et al. 

(2014) versus all in the EPA FracFocus 1.0 project database). 

Trends in water use per well are generally lacking for Colorado, with the exception of those 

reported by Goodwin et al. (2014). They found that water use per well is increasing with well 

length in the Denver Basin; however, they also observed that water intensity (gallons of water per 

unit energy extracted) did not change, since energy recovery increased along with water use. 

Water use/consumption at the county scale: Hydraulic fracturing operations in Colorado use billions 

of gallons of water, but this amount is a small percentage compared to total water used or 

consumed at the county scale. In both Garfield and Weld Counties, located in the Uinta-Piceance and 

Denver Basins, respectively, hydraulic fracturing used more than 1 billion gal (3.8 billion L) 

annually. Fracturing water use and consumption in these counties exceeded those in all other 

Colorado counties combined (Appendix Table B-2), but the water used for hydraulic fracturing in 

Garfield and Weld counties was less than 2% and 3% compared to 2010 total water use and 

consumption, respectively. In comparison, irrigated agriculture accounts for over 90% of the water 

used in both counties (Maupin et al., 2014). Overall, hydraulic fracturing accounts for less than 2% 

compared to 2010 total water use in all Colorado counties represented in the EPA FracFocus 1.0

project database (Appendix Table B-2). Water use estimates based on the EPA FracFocus 1.0 

project database may be low relative to literature and state estimates (Text Box 4-1), but even if 

estimates from the project database were doubled, hydraulic fracturing water use and consumption 

would still be less than 4% and 6% compared to 2010 total water use and consumption, 

respectively, in each Colorado county.

In Wyoming, reported water use for hydraulic fracturing is small compared to Colorado (Appendix 

Table B-1). Fracturing water use and consumption did not exceed 1% of 2010 total water use and 

consumption, respectively, in any county (Appendix Table B-2). Unlike Colorado, Wyoming did not 

require disclosure to FracFocus during the time period analyzed by the EPA (U.S. EPA, 2015b) 

(Appendix Table B-5).

Colorado Division of Water Resources et al. (2014) projected that annual water use for hydraulic 

fracturing in the state would increase by approximately 16% between 2012 and 2015, but demand 

in later years is unclear. Even with an increase of 16% or more, hydraulic fracturing would still 

remain a relatively small user of water at the county scale in Colorado. 

 

1 Different spatial extents might explain these differences, since Goodwin et al. (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 1.0 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. 
Chapter 4 – Water Acquisition

4-34 

Potential for impacts: The potential for water quantity and quality impacts due to hydraulic 

fracturing water withdrawals appears to be low at the county scale in Colorado and Wyoming

because fracturing accounts for a low percentage of total water use and consumption (Figure 

4-3a,b). This conclusion is also supported by the comparison of hydraulic fracturing water use to 

water availability at the county scale (Text Box 4-2; Figure 4-6a,b). However, counties in Colorado 

and Wyoming are large in their spatial extents, and any potential impacts will depend on sitespecific factors affecting the balance between water use and availability at the local scale (i.e., at a 

given withdrawal point). In a multi-scale case study in the Upper Colorado River Basin, the U.S. EPA 

(2015e) did not identify any locations where fracturing currently contributed to locally high water 

use intensity due to the high rates of wastewater reuse reported. They did conclude, however, that 

future effects may be possible (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.

The U.S. EPA (2015e) conducted a case study to explore the impact of hydraulic fracturing water demand on 

water availability at the river basin, county, and local scales in the semi-arid Upper Colorado River Basin 

(UCRB) of western Colorado. The study area overlies the Piceance geologic basin with natural gas in tight 

sands. Water withdrawal impacts were quantified using a water use intensity index (i.e., the ratio between 

the volume of water withdrawn at a site for hydraulic fracturing and the volume of available water). 

Researchers obtained detailed site-specific data on hydraulic fracturing water usage from state and regional 

authorities, and estimated available water supplies using observations at USGS gage stations and empirical 

and hydrologic modeling. 

They found that water supplies accessed for oil and gas demand were concentrated in Garfield County, and 

most fresh water withdrawals were concentrated within the Parachute Creek watershed (198 mi2). However, 

fresh water makes up a small proportion of the total water used for fracturing due to large quantities of highquality wastewater produced from the Piceance tight sands. Based on discussions with industry, the U.S. EPA 

(2015e) reports that fresh water is used solely for drilling and reused wastewater supplies nearly all the 

water for hydraulic fracturing in Garfield County. Due to the high reuse rate, the U.S. EPA (2015e) did not 

identify any locations in the Piceance play where fracturing contributed to locally high water use intensity. 

Scenario analyses demonstrated a pattern of increasing potential impact with decreasing watershed size in 

the UCRB. The U.S. EPA (2015e) examined hydraulic fracturing water use intensity under the current rates of 

both directional (S-shaped) and horizontal drilling. They showed that for the more water-intensive horizontal 

drilling, watersheds had to be larger to meet the same index of water use intensity (0.4) as that for directional 

drilling (100 mi2 for horizontal drilling, as compared to 30 mi2 for directional drilling). To date, most wells 

have been drilled directionally into the Piceance tight sands, although a trend toward horizontal drilling is 

expected to increase annual water use per well by about four times. Despite this increase, total hydraulic 

fracturing water use is expected to remain small relative to other users. Currently, irrigated agriculture is the 

largest water user in the UCRB.

Greater water demand could occur in the future if the water-intensive oil shale extraction industry becomes 

economically viable in the region. Projections for oil shale water demand indicate that the industry could 

increase water use for energy extraction in Garfield and Rio Blanco counties.
Chapter 4 – Water Acquisition

4-35 

East of the Rocky Mountains in the Denver Basin, the potential for localized impacts exists given the 

combination of high hydraulic fracturing activity and low water availability (e.g., Weld County, 

Colorado), but lack of available data and literature at the local scale limits our ability to assess the 

potential for impacts in this location. Ceres (2014) concludes that all fractured wells in the Denver 

Basin are in high or extremely high water-stressed areas. Furthermore, the development of the 

Niobrara Shale in southeast Wyoming occurs in areas already impacted by high agricultural water 

use from the Ogallala aquifer, including the state’s only three groundwater control areas, which 

were established as management districts in the southeast portion of the state in response to 

declining groundwater levels (AMEC Environment & Infrastructure, 2014; Wyoming State 

Engineer's Office, 2014; Tyrrell, 2012; Bartos and Hallberg, 2011). Groundwater withdrawals for 

hydraulic fracturing may have the potential to contribute to water quality degradation in these 

areas, depending on site-specific factors that may alter the balance between water use and 

availability. 

Overall, the potential for impacts appears low at the county scale in Colorado and Wyoming, but 

local effects are certainly possible particularly east of the Rocky Mountains in the Denver Basin. 

Lack of available data and literature at the local scale limits our ability to assess the potential for 

impacts in this location. 

4.5.3 Pennsylvania, West Virginia, and Ohio 

Pennsylvania had the third most disclosures in the EPA FracFocus 1.0 project database (6.5% of 

disclosures) (Appendix Table B-5; Figure 4-4). We combine West Virginia and Ohio with 

Pennsylvania because they share similar geology overlying the Appalachian Basin (including the 

Marcellus, Devonian, and Utica stacked plays) (Figure 4-10); however, much less activity is 

reported in these two states (Appendix Table B-5).

Figure 4-10. Major U.S. EIA shale plays and basins for Pennsylvania, West Virginia, and Ohio.

Source: EIA (2015). 
Chapter 4 – Water Acquisition

4-36 

Types of water used: Surface water is the primary water source for hydraulic fracturing in 

Pennsylvania, West Virginia, and Ohio (SRBC, 2016; Schmid and Yoxtheimer, 2015; West Virginia 

DEP, 2014; Mitchell et al., 2013a; West Virginia DEP, 2013; Ohio EPA, 2012b; STRONGER, 2011b) 

(Table 4-1). Further, the water used for hydraulic fracturing is most often fresh water in all three 

states. In both Pennsylvania’s Susquehanna River Basin and throughout West Virginia, most water 

for hydraulic fracturing is self-supplied via direct withdrawals from surface water and groundwater

(U.S. EPA, 2015e; West Virginia DEP, 2013). Operators also purchase water from public water 

systems, which may include a variety of commercial water brokers (West Virginia DEP, 2014; SRBC, 

2013; West Virginia DEP, 2013). Municipal supplies are also used, particularly in urban areas of 

Ohio (STRONGER, 2011b). 

Reused hydraulic fracturing wastewater as a percentage of total water used for fracturing was 19% 

in 2014 in Pennsylvania, and 15% in 2012 in West Virginia (Schmid and Yoxtheimer, 2015; West 

Virginia DEP, 2014) (Table 4-2). Available data indicate an increasing trend in reuse of wastewater 

over time in this region, likely due to the lack of nearby disposal options in Class II wells. Reused 

wastewater as a percentage of injected water volume ranged from approximately 2% to 19% in 

Pennsylvania (statewide) from 2009-2014 (Schmid and Yoxtheimer, 2015). This upward trend is 

also shown in Pennsylvania’s SRB, where reuse as a percentage of total water injected reached 22% 

in 2013; the average reuse rate for 2008-2013 in the SRB was 16% (SRBC, 2016) (Table 4-2). In 

West Virginia, reuse as a percentage of injected volume ranged from 6% to 15% from 2010-2012 

(West Virginia DEP, 2014). In Ohio’s Marcellus and Utica Shales, reuse of wastewater is reportedly 

uncommon (STRONGER, 2011b), likely due to the prevalence of disposal wells in Ohio. See Chapter 

8 for more information. 

Aside from reused hydraulic fracturing wastewater, other types of wastewaters reused for 

hydraulic fracturing may include wastewater treatment plant effluent, treated acid mine drainage, 

and rainwater collected at various well pads (West Virginia DEP, 2014; SRBC, 2013; West Virginia 

DEP, 2013; Ziemkiewicz et al., 2013; Ohio EPA, 2012b). No data are available on the frequency of 

use of these other wastewaters.

Water use per well: Operators in these three states reported the third, fourth, and fifth highest 

median water use per well of the states we considered from the EPA FracFocus 1.0 project 

database, with 5.0, 4.2, and 3.9 million gal (18.9, 15.9, and 14.8 million L) in West Virginia, 

Pennsylvania, and Ohio, respectively (Appendix Table B-5). Hansen et al. (2013) report similar

water use estimates for Pennsylvania and West Virginia for 2011 and 2012 (Appendix Table B-5). 

This correspondence is not surprising, as these estimates are also based on FracFocus data (via 

Skytruth). For 2011, the year overlapping with the time frame of the EPA FracFocus report (U.S. 

EPA, 2015b), Mitchell et al. (2013a) report an average of 2.3 million gal (8.7 million L) for vertical 

wells (54 wells) and 4.6 million gal (17.4 million L) for horizontal wells (612 wells) in the 

Pennsylvania portion of the Upper Ohio River Basin, based on records from PA DEP. The weighted 

average water use per well was 4.4 million gal (16.7 million L), similar to results based on the EPA 

FracFocus 1.0 project database listed above. In Pennsylvania’s SRB, the long-term average water 

use per well from 2008-2013 was 4.3 million gal (16.3 million L). In 2013, the average water use 

per well increased to approximately 5.1 to 6.5 million gal (19.3 to 24.6 million L) due to increasing 
Chapter 4 – Water Acquisition

4-37 

lengths of laterals in horizontal drilling (SRBC, 2016). Across the entire state of Pennsylvania, water 

use per well has increased over time, which may be explained by increasing horizontal well length, 

depth, and length of the completed interval (Schmid and Yoxtheimer, 2015). 

Water use/consumption at the county scale: In this tri-state region, the highest water use for 

hydraulic fracturing is in northeastern Pennsylvania counties. On average, operators in Bradford 

County reported over 1 billion gal (3.8 billion L) used annually in 2011 and 2012 for fracturing; 

operators in three other counties (Susquehanna, Lycoming, and Tioga Counties) reported 

500 million gal (1.9 billion L) or more used annually in each county (Table 4-3). On average, 

hydraulic fracturing water use is 3.2% compared to 2010 total water use for counties with 

disclosures in the EPA FracFocus 1.0 project database in these three states (Table 4-3; 

Appendix Table B-2). Susquehanna County in Pennsylvania has the highest percentages relative to 

2010 total water use (47%) and consumption (123%). 

Potential for impacts: Water availability is higher in Pennsylvania, West Virginia, and Ohio than in 

many western states, reducing the likelihood of impacts to drinking water resource quantity and 

quality. At the county scale, water supplies appear adequate to accommodate this use (Text Box 

4-2; Figure 4-6a,b). However, impacts could still occur at the local scale (i.e., specific withdrawal 

points) as high water availability in a region does not preclude water stress, particularly if water 

withdrawals occur during seasonal low-flow periods (Entrekin et al., 2015). Without management 

of the rate and timing of withdrawals, surface water withdrawals for hydraulic fracturing have the 

potential to affect both drinking water quantity and quality (Mitchell et al., 2013a). For instance, 

withdrawals may alter natural stream flow regimes, potentially decreasing a stream’s capacity to 

dilute contaminants (Gallegos et al., 2015; Mitchell et al., 2013a; Entrekin et al., 2011; NYSDEC, 

2011; van Vliet and Zwolsman, 2008; IPCC, 2007; Environment Canada, 2004; Murdoch et al., 

2000). 

In a second, multi-scale case study, EPA showed that the potential for water acquisition impacts to 

drinking water resource quantity and quality increases at finer temporal and spatial resolutions 

(U.S. EPA, 2015e). They concluded that individual streams in Pennsylvania’s SRB can be vulnerable 

to typical hydraulic fracturing water withdrawals depending on stream size, as defined by 

contributing basin area (U.S. EPA, 2015e) (Text Box 4-5). They observed infrequent (in less than 

1% of withdrawals) high ratios of hydraulic fracturing water consumption to stream flow (high 

consumption-to-stream flow events). Further research from Barth-Naftilan et al. (2015) in 

Pennsylvania’s Marcellus Shale (SRB and Ohio River Basin (ORB)) confirmed that stream flow 

alteration due to hydraulic fracturing surface water withdrawals increases at finer spatial scales 

(i.e., smaller watershed area). They showed that streams with drainage areas under 50 mi2 (130 

km2) are the most vulnerable to stress induced by flow alteration (Barth-Naftilan et al., 2015). 
Chapter 4 – Water Acquisition

4-38 

Text Box 4-5. Case Study: Impact of Water Acquisition for Hydraulic Fracturing on Local Water 

Availability in the Susquehanna River Basin.

The U.S. EPA (2015e) conducted a second case study analogous to that in the UCRB (Text Box 4-4), to explore 

the impact of hydraulic fracturing water demand on water availability at the river basin, county, and local 

scales in the SRB in northeastern Pennsylvania. The study area overlies the Marcellus Shale gas reservoir. 

Water withdrawal impacts were quantified using a water use intensity index (Text Box 4-4). Researchers 

obtained detailed site-specific data on hydraulic fracturing water usage from state and regional authorities, 

and estimated available water supplies using observations at USGS gage stations and empirical and 

hydrologic modeling. 

Most water for fracturing in the SRB is self-supplied by operators from rivers and streams with withdrawal 

points distributed throughout a wide geographic area. Public water systems provide a relatively small 

proportion of the water needed. Reuse of wastewater as a percentage of hydraulic fracturing fluid volume 

averaged 16% from 2008-2013, and has increased over time, reaching 22% in 2013 (SRBC, 2016) (Table 

4-2). The Susquehanna River Basin Commission (SRBC) regulates water acquisition for hydraulic fracturing 

and issues permits that set limits on the volume, rate, and timing of withdrawals at individual withdrawal 

points; passby flow thresholds (hereafter, passby flows) halt water withdrawals during low flows. 

The U.S. EPA (2015e) demonstrated that streams can be vulnerable from hydraulic fracturing water 

withdrawals depending on their size, as defined by contributing basin area. Small streams have the potential 

for impacts (i.e., high water use intensity) for all or most of the year. The U.S. EPA (2015e) showed an 

increased likelihood of impacts in small watersheds in the SRB (less than 10 mi2 or 26 km2). Furthermore, 

they showed that in the absence of passby flows, even larger watersheds (up to 600 mi2 or 1,554 km2) could 

be vulnerable during maximum withdrawal volumes and infrequent droughts. However, high water use 

intensity calculated from observed hydraulic fracturing withdrawals occurred at only a few withdrawal 

locations in small streams; local high water use intensity was not found at the majority of withdrawal points.

Detailed studies and state reports available throughout the Marcellus Shale region help provide an 

understanding of the potential impacts of hydraulic fracturing water withdrawals in both space and 

time at the local scale (SRBC, 2016; Barth-Naftilan et al., 2015; U.S. EPA, 2015e). In the SRB and 

ORB, water for hydraulic fracturing is taken from both large rivers and small headwater streams, 

with a considerable fraction of the water taken from small streams of small watersheds (BarthNaftilan et al., 2015). The SRBC reports that most natural gas development in the SRB is focused in 

rural, headwater areas, where withdrawals have the potential to alter natural stream flow regimes 

(SRBC, 2016). In an analysis of the effects of water withdrawals on twelve streams in the SRB, 

Shank and Stauffer (2015) found that the largest withdrawals relative to stream size were from 

headwater streams, where daily withdrawals averaged 6.8% of average daily flows. However, they 

found water management in the form of low flow protections helped limit the potential for impacts.

Compared to conventional energy extraction, hydraulic fracturing consumes more water in a highly 

concentrated period of time (Patterson et al., 2016); thus, the cumulative impact of multiple wells 

withdrawing water from small streams, particularly during drought or seasonal low flows, has the 

potential to impact the quantity and quality of drinking water resources (Patterson et al., 2016). For 

instance, in modeling the potential future impact of hydraulic fracturing in the Delaware River 

Basin (DRB), Habicht et al. (2015) showed that under maximum well development, hydraulic 

fracturing water withdrawals from small streams could remove up to 70% of water during periods 
Chapter 4 – Water Acquisition

4-39 

of low stream flow, and less than 3% during periods of normal stream flow.1 Unlike groundwater 

withdrawals, any impacts to drinking water resource quantity and quality associated with surface 

water withdrawals are likely to persist for a shorter time period since the rate of replenishing 

water removed from the system is greater in surface water than groundwater (Alley et al., 1999) 

(Section 4.5.1).

The potential for water acquisition impacts to drinking water resource quality in this region is also 

greatest in small, unregulated streams, particularly under drought conditions or during seasonal 

low flows (U.S. EPA, 2015e; Vengosh et al., 2014; Mitchell et al., 2013a; Vidic et al., 2013; Rahm and 

Riha, 2012; Rolls et al., 2012; Kargbo et al., 2010; McKay and King, 2006). Surface water quality 

impacts may be of concern if a pollution discharge point (e.g., sewage treatment plant, agricultural 

runoff, or chemical spill) is immediately downstream of a hydraulic fracturing withdrawal point 

(U.S. EPA, 2015e; NYSDEC, 2011).2 Potential water quality impacts associated with reduced water 

levels may also include possible interference with the efficiency of drinking water treatment plant 

operations, as increased contaminant concentrations in drinking water sources may necessitate 

additional treatment and ultimately impact drinking water quality (Water Research Foundation, 

2014; Benotti et al., 2010).3

Water management policies in place in this region can help reduce the potential for impacts 

associated with hydraulic fracturing water withdrawals, including excessive lowering of water 

levels, unreliable water supplies, and degradation of water quality (SRBC, 2016; Barth-Naftilan et 

al., 2015; U.S. EPA, 2015e) (Text Box 4-5). For instance, the SRBC manages the quantity, location, 

and timing of withdrawals, using site-specific information to set instantaneous and daily 

withdrawal limits for all approved surface water and groundwater withdrawals. They also set low 

flow protections, known as passby flows, for most approved surface water withdrawals that require 

withdrawals to cease when stream flow drops below a prescribed threshold level (SRBC, 2016). 

Passby flows can reduce the frequency of high consumption-to-stream flow events, particularly in 

the smallest streams (Shank and Stauffer, 2015; U.S. EPA, 2015e). 

Overall, there appears to be adequate surface water for hydraulic fracturing in Pennsylvania, West 

Virginia, and Ohio, but there is still the potential for impacts to both drinking water resource 

quantity and quality, particularly in small streams, if the rate and timing of withdrawals are not

managed (U.S. EPA, 2015e). These potential impacts are expected to be localized in space (i.e., 

 

1 Presently there is a moratorium on hydraulic fracturing in the DRB, which spans Pennsylvania, Delaware, New Jersey, 

and New York. Habicht et al. (2015) modeled the potential future environmental impact of hydraulic fracturing in the DRB 

should the moratorium be lifted, allowing hydraulic fracturing to expand into this region in the future. 

2 Aside from direct surface water withdrawals, unmanaged withdrawals from public water systems can cause crosscontamination 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). 

3 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 reacts with organic matter in the water being 

treated (Water Research Foundation, 2014). 
Chapter 4 – Water Acquisition

4-40 

occurring at specific withdrawal points), and time (e.g., low flow periods). Passby flows appear to 

be an effective water management tool for reducing the potential for impacts from surface water 

withdrawals.

4.5.4 North Dakota and Montana 

North Dakota was fourth in the number of disclosures in the EPA FracFocus 1.0 project database 

(5.9% of disclosures) (Appendix Table B-5; Figure 4-4). We combine Montana with North Dakota, 

because both overlie the Williston Basin (which contains the Bakken play, shown in Figure 4-11), 

although many fewer wells are reported for Montana (Appendix Table B-5). The Williston Basin is 

the only basin with significant activity reported for either state, though other basins are also 

present in Montana (e.g., the Powder River Basin).

Figure 4-11. Major U.S. EIA shale plays and basins for North Dakota and Montana.

Source: EIA (2015). 

Types of water used: Hydraulic fracturing in the Bakken play depends on both ground and surface 

water resources. Surface water from the Missouri River system provides the largest source of fresh 

water in the center of Bakken oil development (North Dakota State Water Commission, 2014; EERC, 

2011, 2010; North Dakota State Water Commission, 2010). Apart from the Missouri River system, 

regional surface waters (e.g., smaller streams) do not provide a consistent supply of water for the 

oil industry due to seasonal stream flow variations. Sufficient stream flows generally occur only in 

the spring after snowmelt (EERC, 2011). Groundwater from glacial and bedrock aquifer systems

has traditionally supplied much of the water needed for Bakken development, but concerns over 

limited groundwater supplies have led to limits on the number of new groundwater withdrawal 

permits issued (Ceres, 2014; Plummer et al., 2013; EERC, 2011, 2010; North Dakota State Water 

Commission, 2010). 

The water used for Bakken development is mostly fresh. The EPA FracFocus report shows that 

“fresh” was the only source of water listed in almost all disclosures reporting a source of water in 

North Dakota (U.S. EPA, 2015b).1 Reuse of Bakken wastewater is limited due to its high TDS, which 

1 Twenty-five percent of North Dakota disclosures included information related to water sources (U.S. EPA, 2015b). 
Chapter 4 – Water Acquisition

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presents challenges for treatment and reuse (Gadhamshetty et al., 2015). Industry is currently 

researching treatment technologies for reuse of this wastewater (Ceres, 2014; EERC, 2013, 2011). 

Water for hydraulic fracturing is commonly purchased from municipalities or other public water 

systems in the region. The water is often delivered to trucks at water depots or transported directly 

to well pads via pipelines (EERC, 2011). 

Water use per well: Water use per well is intermediate compared with other areas, with a median 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 

Montana, respectively, according to the EPA’s FracFocus 1.0 project database (Appendix Table B-5). 

The North Dakota State Water Commission reports similar volumes (2.2 million gal (8.3 million L) 

per well on average for North Dakota) in a summary fact sheet (North Dakota State Water 

Commission, 2014).1 Scanlon et al. (2016) show that average water use per well in the Bakken play 

has increased over time, from 580,000 gal (2.2 million L) in 2005 to 3.7 million gal (14.1 million L) 

in 2014, due in part to the increasing lengths of laterals in horizontal drilling.

In addition to water for hydraulic fracturing, Bakken wells may require “maintenance water”

(Scanlon et al., 2016; Scanlon et al., 2014a). This extra water is reportedly needed because of the 

relatively high salt content of Bakken brine, potentially leading to salt buildup, pumping problems, 

and restriction of oil flow. Based on estimates from the North Dakota Department of Mineral 

Resources, Scanlon et al. (2016) report that approximately 400 – 600 gal (1,500 – 2,300 L) per day 

per each well may be required for well maintenance. Assuming a 15-year lifetime for wells, this 

could add up to 3.3 million gal (12.5 million L) per well of additional water (Scanlon et al., 2016). 

Water use/consumption at the county scale: Water use for fracturing in this region is greatest in the 

northwestern corner of North Dakota (Gadhamshetty et al., 2015). Hydraulic fracturing water use 

in 2011 and 2012 averaged approximately 123 million gal (466 million L) per county in the twostate area, with use in McKenzie and Williams Counties in North Dakota exceeding 500 million gal 

(1.9 billion L) (Appendix Table B-2). There were four counties where 2011 and 2012 average 

hydraulic fracturing water use was 10% or more of 2010 total water use. Mountrail and Dunn 

Counties showed the highest percentages (36% and 29%, respectively). Outside of North Dakota’s 

northwest corner, hydraulic fracturing used much less water in the rest of the state and Montana 

(Table 4-3; Appendix Table B-2). 

Potential for impacts: In this region, there are concerns about over-pumping groundwater

resources, but the potential for impacts appears to be low provided the Missouri River is 

determined to be a sustainable and usable source. This finding of a low potential for impacts is also 

supported by the comparison of hydraulic fracturing water use to water availability at the county 

scale (Text Box 4-2; Figure 4-6a,b). This area is primarily rural, interspersed with small towns. 

Residents rely on a mixture of surface water and groundwater for domestic use depending on the 

county, with most water supplied by local municipalities (Appendix Table B-6).

1 The fact sheet is a stand-alone piece, and it is not accompanied by an underlying report. 
Chapter 4 – Water Acquisition

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The state of North Dakota and the U.S. Army Corps of Engineers concluded that groundwater

resources in western North Dakota are not sufficient to meet the needs of the oil and gas industry 

(U.S. Army Corps of Engineers, 2011; North Dakota State Water Commission, 2010). All users 

combined currently withdraw approximately 6.2 billion gal (23.5 billion L) of water annually in an 

11-county region in western North Dakota, already stressing groundwater supplies (U.S. Army 

Corps of Engineers, 2011). By comparison, the total needs of the oil and gas industry are projected 

to range from approximately 2.2 and 8.8 billion gal (8.3 and 33.3 billion L) annually by the year 

2020 (U.S. Army Corps of Engineers, 2011). 

Due to concerns for already stressed groundwater supplies, the state of North Dakota limits 

industrial groundwater withdrawals, particularly from the Fox Hills-Hell Creek aquifer (Ceres, 

2014; Plummer et al., 2013; EERC, 2011, 2010; North Dakota State Water Commission, 2010). 

Currently, the oil industry is the largest industrial user of water from the Fox Hills-Hell Creek 

aquifer (North Dakota State Water Commission, 2010). Many farms, ranches, and some 

communities in western North Dakota rely on flowing wells from this artesian aquifer, particularly 

in remote areas that lack electricity for pumping; however, low recharge rates and withdrawals 

throughout the last century have resulted in steady declines in the formation’s hydraulic pressure 

(North Dakota State Water Commission, 2010). Declines in hydraulic pressure do not appear to be 

associated with impacts to groundwater quality; rather, the state is concerned with maintaining 

flows for users (North Dakota State Water Commission, 2010). 

To reduce demand for groundwater, the state is encouraging the industry to seek surface water 

withdrawals from the Missouri River system. The North Dakota State Water Commission concluded 

the Missouri River and its dammed reservoir, Lake Sakakawea, are the only plentiful and 

dependable water supplies for the oil industry in western North Dakota (North Dakota State Water 

Commission, 2010). In 2011, North Dakota authorized the Western Area Supply Project, by which

Missouri River water (via the water treatment plant in Williston, North Dakota) will be supplied to 

help meet water demands, including for oil and gas development, of the state’s northwest counties

(WAWSA, 2011). In July 2012, the U.S. Army Corps of Engineers made available approximately 32.6 

billion gal (123 billion L) of water per year from Lake Sakakawea for municipal and industrial water 

demands over the next ten years (U.S. Army Corps of Engineers, 2011). The Army Corps estimated 

that the oil and gas industry could use up to 8.8 billion gal (33.3 billion L) annually during this time 

period in the 11-county surrounding area, and included this as part of the 32.6 billion gal total (123 

billion L) to be made available (U.S. Army Corps of Engineers, 2011). For context, annual water use 

for hydraulic fracturing in all North Dakota counties combined was approximately 2.2 billion gal 

(8.3 billion L) per year in 2011 and 2012 according to EPA’s FracFocus 1.0 project database 

(Appendix Table B-2). As such, Lake Sakakawea appears to be an adequate resource to meet the 

water demands of hydraulic fracturing in the region at least in the near term. 

4.5.5 Arkansas and Louisiana 

Arkansas and Louisiana were ranked seventh and tenth in the number of disclosures in the EPA 

FracFocus 1.0 project database, respectively (Appendix Table B-5). Hydraulic fracturing activity in 

Louisiana occurs primarily in the TX-LA-MS Salt Basin, which contains the Haynesville play; activity 

in Arkansas is dominated by the Arkoma Basin, which contains the Fayetteville play (Figure 4-12). 
Chapter 4 – Water Acquisition

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Figure 4-12. Major U.S. EIA shale plays and basins for Arkansas and Louisiana.

Source: EIA (2015). 

Types of water used: Surface water is reported as the primary source of water for hydraulic 

fracturing operations in both Arkansas and Louisiana (ANRC, 2014; LA Ground Water Resources 

Commission, 2012; STRONGER, 2012). Quantitative information is lacking for Arkansas on the 

proportion of water sourced from surface versus groundwater. However, data are available for 

Louisiana, where an estimated 87% of water for hydraulic fracturing in the Haynesville Shale is 

from surface water (LA Ground Water Resources Commission, 2012) (Table 4-1). In 2008, during 

the early stages of development, hydraulic fracturing in Louisiana relied heavily on groundwater

from the Carrizo-Wilcox aquifer, and concerns for the sustainability of groundwater resources 

prompted the state to encourage surface water withdrawals (LA Ground Water Resources 

Commission, 2012). 

The EPA FracFocus report suggests that significant reuse of wastewater may occur in Arkansas to 

offset total fresh water used for hydraulic fracturing; 70% of all disclosures reporting a water 

source indicated a blend of “recycled/surface,” whereas 3% of disclosures reporting a water source 

noted “fresh” as the exclusive water source (U.S. EPA, 2015b).1According to Veil (2011), Arkansas’ 

1 Ninety-three percent of Arkansas disclosures included information related to water sources (U.S. EPA, 2015b). 
Chapter 4 – Water Acquisition

4-44 

Fayetteville Shale wastewater is of relatively good quality (i.e., low TDS), facilitating reuse.1 Data 

are generally lacking on the extent to which hydraulic fracturing wastewater is reused in Louisiana.

Water use per well: Arkansas and Louisiana have the highest median water use per well of the states 

we considered from the EPA FracFocus 1.0 project database, at 5.3 million and 5.1 million gal (20.1 

million and 19.3 million L), respectively (Appendix Table B-5).2 

Water use/consumption at the county scale: On average, hydraulic fracturing uses 408 million gal 

(1.54 billion L) of water each year in Arkansas counties reporting activity, or 9.3% of 2010 total 

county water use (26.9% of total county consumption) (Appendix Table B-2). In 2011 and 2012, 

five counties dominated fracturing water use in Arkansas: Cleburne, Conway, Faulkner, Van Buren, 

and White Counties (Appendix Table B-2). Van Buren, which is sparsely populated and thus has 

relatively low total water use and consumption, is by far the Arkansas county highest in hydraulic 

fracturing water use and consumption relative to 2010 total water use and consumption (56% and 

168%, respectively) (Table 4-3).

In Louisiana, hydraulic fracturing water use is concentrated in six parishes in the far northwestern 

corner of the state, associated with the Haynesville play.3 On average in 2011 and 2012, hydraulic 

fracturing used 117 million gal (443 million L) of water annually per parish, representing 

approximately 3.6% and 10.8% of 2010 total water use and consumption, respectively (Appendix 

Table B-2). Operators in DeSoto Parish used the most water (over 1 billion gal (3.8 billion L) 

annually). Hydraulic fracturing water use and consumption was highest relative to 2010 total water 

use and consumption (35.5% and 83.2%, respectively) in Red River Parish (Table 4-3). These 

numbers may be low estimates, since Louisiana required disclosures to the state or FracFocus, and 

Arkansas required disclosures to the state but not FracFocus, during the time period analyzed (U.S. 

EPA, 2015b) (Appendix Table B-5).

Potential for impacts: Water availability is generally higher in Arkansas and Louisiana than in states 

farther west, reducing the potential for impacts to drinking water quantity and quality (Figure 4-6a, 

Figure 4-7a; Text Box 4-2). However, generally high water availability in this region does not 

preclude the potential for impacts at the local scale, particularly if surface water withdrawals occur 

during seasonal low flow periods. For instance, precipitation is highest in Arkansas in the late 

autumn and winter, with little rainfall occurring in the late spring and summer; thus, most small 

streams do not flow year round (Entrekin et al., 2015). Hydraulic fracturing surface water 

withdrawals from small streams during seasonal low flows have the potential to impact the 

quantity and quality of drinking water resources. 

Additionally, in northwestern Louisiana, there are concerns about over-pumping of groundwater

resources. Prior to 2008, most operators in the Louisiana portion of the Haynesville Shale used

groundwater, withdrawing from the Carrizo-Wilcox, Upland Terrace, and Red River Alluvial aquifer 

1 Veil (2011) reports a range of 20,000-25,000 ppm TDS for Fayetteville Shale wastewater.

2 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 to date. 

3 Louisiana is divided into parishes, which are similar to counties in other states.
Chapter 4 – Water Acquisition

4-45 

systems (LA Ground Water Resources Commission, 2012). To mitigate stress on groundwater, the 

state issued a water use advisory to the oil and gas industry that recommended Haynesville Shale 

operators seek alternative water sources to the Carrizo-Wilcox aquifer, which is predominantly 

used for public supply (LDEQ, 2008). Operators then transitioned to mostly surface water, with a 

smaller groundwater component (approximately 13% of all fracturing water used) (LA Ground 

Water Resources Commission, 2012). Of this groundwater component, the majority (approximately 

74%) still came from the Carrizo-Wilcox aquifer (LA Ground Water Resources Commission, 2012). 

Although the potential for hydraulic fracturing withdrawals to affect water supplies and water 

quality in the aquifer was reduced, it was not entirely eliminated. Despite Louisiana’s water use 

advisory, a combination of drought conditions and higher than normal withdrawals (for all uses, 

not solely hydraulic fracturing) from the Carrizo-Wilcox and Upland Terrace aquifers caused 

several water wells to go dry in July 2011 (LA Ground Water Resources Commission, 2012). In 

August 2011, a groundwater emergency was declared for southern Caddo Parrish (LA Ground 

Water Resources Commission, 2012). Hydraulic fracturing withdrawals contributed to these 

conditions, alongside other users of water and the lack of precipitation. 

4.6 Chapter Synthesis

In this chapter, we examined the potential for water acquisition for hydraulic fracturing to impact

the quantity and quality of drinking water resources, and identified factors affecting the frequency 

or severity of impacts. Whether impacts occur from water acquisition for hydraulic fracturing 

depends on the local balance between water withdrawals and availability, and this balance can be 

modified by a combination of site or regional-specific factors. For this reason, information is needed 

at the local scale to determine whether impacts actually occur, yet this information is not available 

in many locations where hydraulic fracturing takes place; see Section 4.6.3 on Uncertainties below.

Despite these limitations, our chapter used the scientific literature, county level assessments, and, 

where available, local case studies to point to areas with a higher potential for impacts; understand 

local dynamics, including example cases of impacts; and identify common factors that increase or 

decrease the frequency or severity of impacts. In this section, we summarize our major findings 

regarding hydraulic fracturing water acquisition activities, potential impacts, and these common 

factors (4.6.1 and 4.6.2). We then discuss uncertainities (4.6.3), and provide final conclusions 

(4.6.4). 

4.6.1 Major Findings

The first half of this chapter focused on water acquisition activities, providing an overview of the 

types of water used (including sources, quality, and provisioning), water use per well, and water 

use and consumption at the national, state, and county scale. The three major types of water used 

for hydraulic fracturing are surface water, groundwater, and reused hydraulic fracturing 

wastewater. Because trucking can be a major expense, operators tend to use water sources as close 

to the well pad as possible. Operators usually self-supply surface water or groundwater directly, 

but may also obtain water from public water systems or other suppliers. Hydraulic fracturing 

operations in the eastern United States rely predominantly on surface water, whereas operations in 
Chapter 4 – Water Acquisition

4-46 

more semi-arid to arid western states use either surface water or groundwater. There are areas of 

the country that rely entirely on groundwater supplies (e.g., western Texas). 

Reuse of wastewater reduces the demand on fresh water sources, which currently supply the vast 

majority of water used for hydraulic fracturing. The proportion of the water used in hydraulic 

fracturing that comes from reused hydraulic fracturing wastewater is generally low; in a survey of 

literature values from 10 states, basins, or plays, we found a median value of 5%, with this 

percentage varying by location (Table 4-2).1 Available data on reuse trends indicate increasing

reuse of wastewater over time in both Pennsylvania and West Virginia, likely due to the lack of 

nearby disposal options in Class II wells. Reuse as a percentage of water injected is typically lower 

in other areas of the United States, likely in part because of the availability of disposal wells; see 

Chapter 8 for more information. 

The median amount of water used nationally per hydraulically fractured well was approximately

1.5 million gal (5.7 million L) in 2011 through early 2013 based on the EPA analysis of FracFocus

disclosures (U.S. EPA, 2015b, c). This increased to approximately 2.7 million gal (10.2 million L) in 

2014, driven by a proportional increase in horizontal wells (estimated from data in Gallegos et al.,

2015). These national estimates represent a variety of fractured well types, including types

requiring much less water per well than horizontal shale gas wells. Thus, published estimates for

horizontal shale gas wells are typically higher (e.g., approximately 4 million gal (15 million L) per

well (Vengosh et al., 2014), and should not be applied to all fractured wells to derive national

estimates. There was also wide variation within and among states and basins in the median per

well water volumes reported in 2011 and 2012, from more than 5 million gal (19 million L) in 

Arkansas and Louisiana to less than 1 million gal (3.8 million L) in Colorado, Wyoming, Utah, New

Mexico, and California (U.S. EPA, 2015c). This variation can result from several factors, including

geologic formation, well length, and fracturing fluid formulation. 

Hydraulic fracturing uses billions of gallons of water every year at the national and state scales, and 

even in some counties. When expressed relative to total water use or consumption at these scales, 

however, hydraulic fracturing generally accounts for only a small percentage, usually less than 1%. 

These percentages are higher though in specific counties. Annual hydraulic fracturing water use 

was 10% or more compared to 2010 total water use in 6.5% of counties with FracFocus disclosures 

in 2011 and 2012 in the EPA FracFocus 1.0 project database, 30% or more in 2.2% of counties, and 

50% or more in 1.0% of counties (Appendix Table B-2). Consumption estimates follow the same 

pattern, with higher percentages in each category: hydraulic fracturing water consumption was 

10%, 30%, and 50% or more of 2010 total water consumption in 13.5%, 6.2%, and 4.0% of counties 

with FracFocus disclosures in the EPA FracFocus 1.0 project database (Appendix Table B-2). Thus, 

hydraulic fracturing represents a relatively large user and consumer of water in these counties.

Whether water quantity or quality impacts occur from water acquisition for hydraulic fracturing 

depends on the local balance between water withdrawals and availability. From our survey of the 

literature and our county level assessments, southern and western Texas appear to have the 

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 for more information. 
Chapter 4 – Water Acquisition

4-47 

highest potential for impacts of the areas assessed in this chapter, given the combination of high 

hydraulic fracturing water use, relatively low water availability, intense periods of drought, and 

reliance on declining groundwater resources; see Section 4.6.2 on Factors below. Importantly, our 

results do not preclude the possibility of local water impacts in areas with comparatively lower 

potential, nor do they necessarily mean impacts have occurred in the high potential areas. Our 

survey, however, provides an indicator of areas with higher potential for impacts, and could be used 

to target resources or future studies. 

In two example cases, local impacts to drinking water resources occurred in areas with increased 

hydraulic fracturing activity. In a detailed case study, Scanlon et al. (2014b) observed generally 

adequate water supplies for hydraulic fracturing in the Eagle Ford play in southern Texas, except in 

specific locations. They found excessive drawdown of groundwater locally, with estimated declines 

of ~100-200 ft (30-60 m) in a small proportion of the play (~6% of the area) after hydraulic 

fracturing activity increased in 2009. In 2011, drinking water wells in an area overlapping with the 

Haynesville Shale ran out of water due to higher than normal groundwater withdrawals and 

drought (LA Ground Water Resources Commission, 2012). Hydraulic fracturing water withdrawals

contributed to these conditions, along with other water users and the lack of precipitation. By 

contrast, two EPA case studies in the Upper Colorado and the Susquehanna River Basins found 

minimal impacts from hydraulic fracturing withdrawals currently (U.S. EPA, 2015e) (Sections 4.5.2, 

4.5.3). 

These site-specific findings emphasize the need to focus on regional and local dynamics when 

considering the impacts from hydraulic fracturing water withdrawals. The case studies and the 

scientific literature as a whole suggest some common factors that increase or decrease the 

frequency or severity of impacts. These are summarized in the section below.

4.6.2 Factors Affecting Frequency or Severity of Impacts

The potential for impacts depends on the combination of water withdrawals and water availability 

at a given withdrawal location. Where water withdrawals are relatively low compared to water 

availability, impacts are unlikely to occur. Where water withdrawals are relatively high compared 

to water availability, impacts are more likely. 

Areas reliant on declining groundwater are particularly vulnerable to more frequent and severe 

impacts from cumulative water withdrawals, including withdrawals for hydraulic fracturing. 

Groundwater recharge rates can be extremely low, and groundwater pumping is exceeding 

recharge rates in many areas of the country (Konikow, 2013). When pumping exceeds recharge, the 

cumulative effects of withdrawals are manifested in declining water levels. For this reason, water 

levels in many aquifers in the United States have declined substantially over the last century 

(Konikow, 2013). Cumulative drawdowns can affect surface water bodies since groundwater can be 

the source of base flow in streams (Winter et al., 1998), and alter groundwater quality by 

mobilizing chemicals from geologic sources, among other means (DeSimone et al., 2014; Alley et al., 

1999). Although in many of these areas (e.g., the Ogallala aquifer), irrigated agriculture is the 

dominant user of groundwater, hydraulic fracturing withdrawals now also contribute to declining 

groundwater levels. Hydraulic fracturing groundwater consumption, for example, exceeds 
Chapter 4 – Water Acquisition

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estimated recharge rates in the seven most active hydraulic fracturing counties in the Eagle Ford 

Shale in southern Texas (Steadman et al., 2015). When necessary, state and local governments have 

encouraged or mandated industry to use surface water over groundwater, as evidenced in both 

Louisiana and North Dakota. 

Among surface water sources, smaller streams, even in humid areas, are more vulnerable to 

frequent and severe impacts from withdrawals. A detailed EPA case study found that streams with 

the smallest contributing areas in northeastern Pennsylvania were particularly vulnerable to 

withdrawals (U.S. EPA, 2015e). Protecting smaller streams from excessive withdrawals is probably 

most important for aquatic life, but may also protect drinking water quantity and quality in certain 

instances. 

Seasonal or long-term drought can also make impacts more frequent and severe for surface water 

and groundwater sources. Hot, dry weather depletes surface water bodies and reduces or prevents 

groundwater recharge, while water demand often increases simultaneously (e.g., for irrigation). 

The EPA case study in Pennsylvania found that even large streams could be vulnerable to 

withdrawals during times of low flows (U.S. EPA, 2015e). Much of the western United States has 

experienced prolonged periods of drought over the last decade (Figure 4-8). This dynamic will 

likely be magnified by future climate change in certain locations (Meixner et al., 2016). 

By contrast to the above factors, consumption of water for hydraulic fracturing does not appear to 

substantially influence the frequency or severity of impacts. There are concerns that hydraulic 

fracturing permanently removes water from the hydrologic cycle, posing a threat to long-term 

water supplies. Since impacts occur locally and depend on the local water balance, impacts can 

occur regardless of whether the water is withdrawn and returned to the larger hydrologic cycle 

elsewhere or whether it is permanently sequestered underground. We acknowledge that whether 

the water is returned to the larger hydrologic cycle may make a difference for the water budget of a 

larger area, such as on the state, regional, or national scale. For example, water converted to steam 

during thermoelectric cooling in one location may condense and fall as precipitation in an adjacent 

state or region. At these larger scales, however, hydraulic fracturing water consumption is a very 

small fraction of total water availability.1 Plus, at these scales, there are other larger factors that can 

affect regional water budgets, but which are out of scope for this assessment.2 For these reasons, 

focusing on consumption distracts from the more salient issue that impacts depend upon the spatial 

and temporal balance between local water withdrawals and availability. 

 

1 For example, hydraulic fracturing used approximately 3.3 billion gal (12.5 billion L) of water on average annually in all 

Colorado counties with hydraulic fracturing activities combined according to FracFocus disclosures in 2011 and 2012 

(Appendix B-1). Using the consumption rate of 82.5% yields a consumption estimate of approximately 2.7 billion gal (10.2 

billion L). This would be approximately 0.1% of the fresh water and total water availability metrics used in Textbox 4-2 

for all of those same counties combined (approximately 2.6 trillion gal (9.8 trillion L) of fresh water and total water 

available). 

2 The combustion of methane produced by hydraulic fracturing, for example, adds water molecules to the environment, 

and at large scales, this may affect regional water budgets. However, quantifying this is outside the scope of this 

assessment. Similarly, there are other larger factors (e.g., water used for cooling thermoelectric power plants) that can 

affect regional water budgets, but these are also outside the scope of this assessment.
Chapter 4 – Water Acquisition

4-49 

There are also factors that can decrease the frequency and severity of any impacts from water 

withdrawals. The literature suggests that water management, particularly wastewater reuse, the 

use of brackish groundwater, the use of passby flows, and transitioning from limited groundwater 

sources to more abundant surface water sources can reduce impacts. Reuse is not a universal 

solution, since in many areas of the country wastewater volumes from one well are often a small 

percentage of the water needed to fracture the next well. In the Marcellus Shale, for instance, 100% 

reuse of the wastewater produced from one well means reducing fresh water demand by 10 or 30% 

for the next (Section 4.2.1; Chapter 7). Nevertheless, reuse can be an important local factor reducing 

fresh water demand. 

Switching to brackish water is another means by which fresh water demand can be—and is in some 

locations—reduced. This is a source of alternative water in western and southern Texas, for 

example. In these areas, use of brackish water is currently reducing impacts to fresh water sources, 

and could with continued use reduce future impacts (Scanlon et al., 2014b; Nicot et al., 2012). Our 

county level estimates suggest that brackish water could readily meet the volume demanded by 

hydraulic fracturing in Texas. 

Water management also includes passby flows, a low stream flow threshold below which 

withdrawals are not allowed. Evidence suggests passby flows can be effective in protecting streams 

from hydraulic fracturing water withdrawals (U.S. EPA, 2015e). Finally, as evidenced by examples 

in both North Dakota and Louisiana, water management may include transitioning from declining 

groundwater sources to surface water, if available. 

4.6.3 Uncertainties

There are several uncertainties inherent in our assessment of the potential impacts of water 

acquisition for hydraulic fracturing. The largest uncertainties stem from the lack of literature and 

data on this subject at local scales. Because impacts occur at a given withdrawal point, our 

assessment could assess the potential for impacts, but often could not determine if potential 

impacts were realized in the absence of local data. The exceptions were local case studies from the 

Eagle Ford play in Texas, the Upper Colorado River Basin in Colorado, and the Susquehanna River 

Basin in Pennsylvania. Moreover, it is also not clear if local impacts, for example a drinking water 

well going dry, are likely to be documented in the scientific literature. 

Other uncertainties arise from data limitations on the volume and types of water used or consumed 

for hydraulic fracturing, future water use projections, and water availability estimates. There are no 

nationally consistent data sources, and therefore, water use estimates must be based on multiple, 

individual pieces of information. For example, in their National Water Census, the USGS includes 

hydraulic fracturing in the broader category of “mining” water use, but hydraulic fracturing water 

use is not reported separately (Maupin et al., 2014). There are locations where average annual

hydraulic fracturing water use in 2011 and 2012 in the EPA FracFocus 1.0 project database 

exceeded total mining water use in 2010, and one county where it exceeded all water use (U.S. EPA, 

2015c; Maupin et al., 2014). This could be due to a rapid increase in hydraulic fracturing water use, 

differences in methodology between the two databases (i.e., the USGS 2010 National Water Census 

and the EPA FracFocus 1.0 project database), or both. 
Chapter 4 – Water Acquisition

4-50 

We used the EPA FracFocus 1.0 project database for water use estimates, which itself has 

limitations. Many states in the project database did not require disclosure to FracFocus during the 

time period analyzed (U.S. EPA, 2015b). We conclude that this likely does not change the overall 

hydraulic fracturing water use patterns observed across the United States (Text Box 4-1), but could 

affect particular county level estimates. Also, the database covered the time period of 2011 through 

early 2013. Thus, changes in the industry since then are not reflected in these data. 

Hydraulic fracturing water use data that are often provided as water use associated with a 

particular well. While this is valuable information, the potential impacts of water acquisition for 

hydraulic fracturing could be better assessed if data were also available at the withdrawal point. If 

the total volume, date, location, and type (i.e., surface water or groundwater; and fresh, brackish, or 

reused wastewater) of each water withdrawal were documented, effects on availability could be 

better estimated. For example, surface withdrawal points could be aggregated by watershed or 

aquifer to estimate effects on downstream flow, groundwater levels, and water quality. Some of this 

information is available in disparate forms, but the lack of nationally consistent data on water 

withdrawal locations, timing, and amounts―data that are publicly available, easy to access and 

analyze―limits our assessment of potential impacts. The Susquehanna River Basin Commission 

collects this type of detailed data on hydraulic fracturing water withdrawals, but this type of 

information is not widely available across the nation.

Future hydraulic fracturing water use is also a source of uncertainty. Because water withdrawals 

and potential impacts are concentrated in certain localized areas, water use projections need to 

match this scale. Projections are available for Texas at the county scale, but more information at the 

county or sub-county scale is needed in other states with hydraulic fracturing activity and water 

availability concerns (e.g., northwest North Dakota, eastern Colorado). Due to a lack of data, we 

generally could not assess future water use and the potential for impacts in most areas of the 

country, nor could we examine these in combination with other relevant factors (e.g., climate 

change or population growth). 

4.6.4 Conclusions

With notable exceptions, hydraulic fracturing uses and consumes a relatively small percentage of 

water when compared to total use, consumption, and availability at the national, state, and county 

scale. Despite this, impacts on drinking water resource quantity and quality from hydraulic 

fracturing water acquisition can occur at the local scale, because hydraulic fracturing water 

withdrawals are often concentrated in space and time, and impacts depend upon the local balance 

between withdrawals and availability. In two example cases, local impacts to drinking water 

resource quantity occurred in areas with increased hydraulic fracturing activity (e.g., in Texas’s 

Eagle Ford play, and in Louisiana’s Haynesville Shale). Declining groundwater resources, especially

in the western United States, are particularly vulnerable to withdrawals, as are smaller streams, 

even in the more humid East. Finally, there are factors that increase or decrease the frequency and 

severity of impacts—included in this are times of low water availability, such as during drought, 

which can increase the frequency and severity of impacts, or conversely water management 

practices (e.g., shifting to brackish water, or passby flows), which can help protect drinking water 

resources.
Chapter 5 – Chemical Mixing

5-1 

Chapter 5. Chemical Mixing 

Abstract 

This chapter provides an analysis of the potential impacts on drinking water resources during the

chemical mixing stage of the hydraulic fracturing water cycle and the factors governing the frequency 

and severity of these impacts. The chemical mixing stage includes the mixing of base fluid (90% to 97% 

by volume, typically water), proppant (2% to 10% by volume, typically sand), and additives (up to 2%

by volume) on the well pad to make hydraulic fracturing fluid. This fluid is engineered to create and

extend fractures in the targeted formation and to carry proppant into the fractures. Concentrated

additives are delivered to the well pad and stored on site, often in multiple, closed containers, and

moved around the well pad in hoses and tubing.

Changes in drinking water quality can occur if spilled fluids reach groundwater or surface water

resources. In this assessment, a spill is considered to be any release of fluids. The EPA’s analysis found

that spills and releases of chemicals and fluids have occurred during the chemical mixing stage and have

reached soil and surface water receptors. Spills of hydraulic fracturing fluids or additives included in the 

analysis had a median spill volume of 420 gal (1,590 L), with a range of 5 to 19,320 gal (9 to 72,130 L). 

Spills were caused most often by equipment failure or human error. The potential for spilled fluids to

reach, and therefore impact, groundwater or surface water resources depends on the composition of the

spilled fluid, spill characteristics, spill response activities, and the fate and transport of the spilled fluid.

The movement of spilled hydraulic fracturing fluids and chemicals through the environment is difficult

to predict, because spills are site- and chemical-specific, and because hydraulic fracturing-related spills 

are typically complex mixtures of chemicals. Physicochemical properties, which depend on the

molecular structure of a chemical, govern whether spilled chemicals volatilize, sorb, transform, and

travel. Spill prevention practices and spill response activities can prevent spilled fluids from reaching

ground or surface drinking water resources.

The severity of potential impacts on water quality from spills of additives or hydraulic fracturing fluids 

depends on the identity and amount of chemicals that reach ground or surface water resources, the

hazards associated with the chemicals, and the characteristics of the receiving water body. The lack of 

monitoring following spills, along with the lack of publicly available information on the composition of

additives and fracturing fluids, containment and mitigation measures in use, the proximity of chemical

mixing to drinking water resources, and the fate and transport of spilled fluids limits the EPA’s ability to

fully assess potential impacts on drinking water resources and their frequency and severity. This

chapter shows that spills of additives and hydraulic fracturing fluids during the chemical mixing stage of

the hydraulic fracturing water cycle have occurred and have reached and impacted drinking water

resources.
Chapter 5 – Chemical Mixing

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Chapter 5 – Chemical Mixing

5-3 

5. Chemical Mixing

5.1 Introduction 

This chapter provides an analysis of the potential impacts on drinking water resources during the 

chemical mixing stage of the hydraulic fracturing water cycle and the factors governing the 

frequency and severity of these impacts. Chemical mixing is a complex process that requires the use 

of specialized equipment and a range of different additives to produce the fluid that is injected into 

a well to fracture the formation. This fluid, the hydraulic fracturing fluid, generally consists of a 

base fluid (typically water), a proppant (typically sand), and additives (chemicals), although there is 

no standard or single composition of hydraulic fracturing fluid used. The number, type, and amount

of chemicals used to create the hydraulic fracturing fluid vary from well to well based on site- and 

operator-specific factors. Spills may occur at any point in the chemical mixing process.1 The 

potential for spilled fluids to reach, and therefore impact, ground or surface water resources 

depends on the composition of the spilled fluid, spill characteristics, spill response activities, and 

the fate and transport of the spilled fluid. This chapter is structured around these concepts. 

The chapter starts by discussing the characteristics of hydraulic fracturing fluids (Sections 5.2 to 

5.4). This includes an introductory overview of the chemical mixing process (Section 5.2), a 

description of the different components of the hydraulic fracturing fluid (Section 5.3), the range of 

different chemicals used and their classes, the most frequently used chemicals nationwide, and

volumes used (Section 5.4).2 (Appendix H provides a list of chemicals that the EPA identified as 

being used in hydraulic fracturing fluids.)

The chapter continues with a discussion on how chemicals are managed on the well pad, the 

characteristics of spills when they occur, and spill response activities (Sections 5.5 to 5.7). This 

includes a description on how potential impacts of a spill on drinking water resources depends 

upon chemical management practices, such as storage, on-site transfer, and equipment 

maintenance (Section 5.5). A summary analysis of reported spills and their common causes at 

hydraulic fracturing sites is then presented (Section 5.6). Then, there is a discussion on the different 

efforts of spill prevention, containment, and mitigation (Section 5.7). 

Next, the fate and transport of spilled chemicals is discussed (Section 5.8). This section includes 

how a chemical can move through the environment and transform, and what governs exposure 

concentrations of chemicals in the environment. Due to the complexities of the processes and the 

site-specific and chemical-specific nature of spills, it is difficult to develop a full assessment of their 

fate and transport. This section provides a general overview and discusses how the fate and 

transport of a chemical depends on site conditions, environmental conditions, physicochemical 

 

1 In this assessment, a spill is considered to be any release of fluids. Spills can result from accidents, fluid management 

practices, or illegal dumping.

2 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, alcohols, acids, and bases.
Chapter 5 – Chemical Mixing

5-4 

properties of the released chemicals, fluid composition, volume of the release, the proximity to a 

drinking water resource, and the characteristics of the drinking water resource that is the receptor. 

Next is an overview of on-going changes in chemical use in hydraulic fracturing, with an emphasis 

on industry efforts to reduce potential impacts from surface spills by using fewer and safer 

chemicals (Section 5.9). The chapter concludes by providing a synthesis, including a summary of 

findings, factors that affect frequency and severity of potential impacts, and a discussion of 

uncertainties and data gaps (Section 5.10).

Due to the limitations of available data and the scope of this assessment, it is not possible to provide 

a detailed analysis of all of the factors listed above. Data limitations preclude a quantitative analysis 

of the likelihood or severity of chemical spills or impacts. Spills that occur off-site, such as those 

during transportation of chemicals to the site or storage of chemicals in staging areas, are out of the 

scope of this assessment. This chapter qualitatively characterizes the potential for impacts on 

drinking water resources given the current understanding of overall operations and specific 

components of the chemical mixing process.

5.2 Chemical Mixing Process

Understanding the chemical mixing process is necessary to understand how, why, and when spills 

might occur. This section provides a general overview of the chemical mixing stage of the hydraulic 

fracturing water cycle (Carter et al., 2013; Knappe and Fireline, 2012; Spellman, 2012; Arthur et al., 

2008). Figure 5-1 shows a hydraulic fracturing site during the chemical mixing process. In our 

discussion, we focus on the types of additives used at each phase of the process. While similar 

processes are used to fracture horizontal and vertical wells, a horizontal well treatment is 

described here. Horizontal well treatments are likely to be more complex and therefore illustrative 

of the variety of practices that have become more prevalent over time with advances in technology

(Chapter 3). A water-based system is described, because water is the most commonly used base 

fluid, appearing in more than 93% of FracFocus 1.0 disclosures between January 1, 2011 and 

February 28, 2013 (U.S. EPA, 2015a).1 While the number and types of additives may vary widely, 

the basic chemical mixing process and the on-site layout of hydraulic fracturing equipment are

similar across sites (BJ Services Company, 2009). Equipment used in the chemical mixing process 

typically consists of chemical storage trucks, water supply tanks, proppant supply, slurry blenders, 

a number of high-pressure pumps, a manifold, surface lines and hoses, and a central control unit.

Detailed descriptions of specific additives and the equipment used in the process are provided in 

Sections 5.3 and 5.5, respectively. 

1 FracFocus (www.fracfocus.org) is a registry of information of water and chemical use in wells in which hydraulic 

fracturing is conducted. More details are provided in Text Box 5-1. 
Chapter 5 – Chemical Mixing

5-5 

Figure 5-1. Representative hydraulic fracturing site showing equipment used on-site during 

the chemical mixing process.

The frac well head is located in the center bottom (green), the manifold runs down the middle, and high pressure 

pumps lead into the manifold from either side. Source: Schlumberger.

At a newly-drilled production well, the chemical mixing process begins after the drilling, casing, and 

cementing processes are finished and hydraulic fracturing equipment has been set up and 

connected to the well. The process can generally be broken down into one or more sequential 

stages with specific chemicals added at different phases during each stage phase to achieve a 

specific purpose (Knappe and Fireline, 2012; Fink, 2003). The process for water-based hydraulic 

fracturing is described in Figure 5-2 below. 

The first phase is the cleaning and preparation of the well. The fluid used in this phase is often 

referred to as the pre-pad fluid, pre-pad volume, or spearhead. Acid is typically the first chemical 

introduced. Acid, with a concentration of 3% to 28% (by volume, typically hydrochloric acid, HCl), 

is used to clean any cement left inside the well from cementing the casing and dissolve any pieces of 

rock that may remain in the well that could block the perforations.1 Acid is typically pumped 

directly from acid storage tanks or tanker trucks, without being mixed with other additives. The 

first, or pre-pad, phase may also involve mixing and injection of additional chemicals to facilitate 

the flow of fracturing fluid introduced in the next phase of the process. These additives may include 

biocides, corrosion inhibitors, friction reducers, and scale inhibitors (Carter et al., 2013; King, 2012; 

Knappe and Fireline, 2012; Spellman, 2012; Arthur et al., 2008). 

1 Prior to the injection of the pad fluid, for wells that are cased in the production zone, 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 well 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 distance into the formation (Gupta and Valkó, 2007). 
Chapter 5 – Chemical Mixing

5-6 

Figure 5-2. 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 taken at the surface 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). 

In the second phase, a hydraulic fracturing fluid, typically referred to as the pad or pad volume, is 

mixed, blended, and pumped down the well under high pressure to create fractures in the 

formation.1 The pad is a mixture of base fluid, typically water, and additives and is designed to 

create, elongate, and enlarge fractures in the targeted geologic formation when injected under high 

pressure (Gupta and Valkó, 2007) (see Section 6.3 for additional information on fracture growth 

following injection). A typical pad consists of, at minimum, a mixture of water and friction reducer.

A typical pad consists of, at minimum, a mixture of water and friction reducer. Other additives (see 

U.S. EPA (2015a) and Table 5-1) may be used to facilitate flow and kill bacteria (Carter et al., 2013; 

King, 2012; Knappe and Fireline, 2012; Spellman, 2012; Arthur et al., 2008). The pad is pumped 

into the formation through perforations or sliding sleeves in the well casing. 

1 In terms of chemical mixing, “pad” is a term used to describe hydraulic fracturing fluid without solid at the start of the 

fracturing of the formation. In terms of the entire hydraulic fracturing process, the “well pad” or “pad” is the area of land

where drilling occurs. 
Chapter 5 – Chemical Mixing

5-7 

In the third phase, proppant, typically sand, is mixed into the hydraulic fracturing fluid. The 

proppant volume, as a proportion of the injected fluid, is increased gradually until the desired 

concentration in the fractures is achieved. Gelling agents, if used, are also mixed with the proppant 

and base fluid in this phase to increase the viscosity to help carry the proppant. Additional 

chemicals may be added to gelled fluids, initially to maintain viscosity and later to break down the 

gel and decrease viscosity, so the hydraulic fracturing fluid can more readily flow back out of the 

formation and through the well to facilitate production from the fractured formation (Carter et al., 

2013; King, 2012; Knappe and Fireline, 2012; Spellman, 2012; Arthur et al., 2008). 

A final flush or clean-up phase may be conducted after the stage is fractured, with the primary 

purpose of maximizing well productivity. The flush is a mixture of water and additives that work to 

aid the placement of the proppant, clean out the chemicals injected in previous phases, and prevent 

microbial growth in the fractures (Knappe and Fireline, 2012; Fink, 2003). 

The second, third, and fourth phases are repeated multiple times in a well with multi-stage 

hydraulic fracturing. For each stage, the well is typically perforated and fractured beginning at the 

end, or toe, of the well and proceeding backwards toward the bend or heel of the well, near the 

vertical section. In vertical wells, stages typically begin in deeper portions of the well and proceed 

shallower. Each fractured stage is isolated before the next stage is fractured. The number of stages 

sets how many times the chemical mixing process is repeated at the site surface (Figure 5-2). The 

number of stages increases with longer intervals of the well subjected to hydraulic fracturing 

(Carter et al., 2013; King, 2012; Knappe and Fireline, 2012; Spellman, 2012; Arthur et al., 2008). 

The number of stages per well can vary, with several sources suggesting between 10 and 20 stages 

is typical (GNB, 2015; Lowe et al., 2013).1 The full range reported in the literature is much wider, 

with one source documenting between 1 and 59 stages per well (Pearson et al., 2013) and others 

reporting values within this range (NETL, 2013; STO, 2013; Allison et al., 2009). The number of 

stages per well seems to have increased over time. One study reports that the average number of 

stages per horizontal well rose from approximately 10 in 2008 to 30 in 2012 (Pearson et al., 2013). 

As more stages are used, the total volume of hydraulic fracturing fluid and chemicals increase. This 

increases the potential, frequency, and severity of surface spills associated with chemical mixing 

and thus potential impacts on drinking water resources. 

In each of these phases, water is usually the primary component of the hydraulic fracturing fluid, 

though the exact composition of the fluid injected into the well changes over the duration of each 

stage. In water-based hydraulic fracturing, the composition, by volume, of a typical hydraulic 

fracturing fluid is 90% to 97% water, 2% to 10% proppant, and 2% or less additives (Carter et al., 

2013; Knappe and Fireline, 2012; SWN, 2011).2 

1 The number of stages has been reported to be 6 to 9 in the Huron in 2009 (Allison et al., 2009), 13 to 32 in the Marcellus 

(NETL, 2013), and up to 40 by STO (2013). 

2 This range is based on a compilation of sources. Sources present compositions as by mass, by volume, or without 

specificity. Because of non-additive volumes, the composition by volume can be different before and after mixing. By 

mass: 90% water, 8-9% proppant, 0.5 to 1.5% additives (Knappe and Fireline, 2012); 88% water, 11% proppant, <1% 
Chapter 5 – Chemical Mixing

5-8 

5.3 Overview of Hydraulic Fracturing Fluids 

Hydraulic fracturing fluids are formulated to perform specific functions: create and extend the 

fracture and transport and place the proppant in the fractures (Montgomery, 2013; Spellman, 2012; 

Gupta and Valkó, 2007).1 The hydraulic fracturing fluid generally consists of three parts: (1) the 

base fluid, which is the largest constituent by volume, (2) the additives, and (3) the proppant. 

Additives, which can be a single chemical or a mixture of chemicals, are chosen to serve a specific 

purpose in the hydraulic fracturing fluid (e.g., friction reducer, gelling agent, crosslinker, biocide) 

(Spellman, 2012). Throughout this chapter, “chemical” is used to refer to an individual chemical 

substance (e.g., methanol, petroleum distillates).2 Proppants are small particles, usually sand, mixed 

with fracturing fluid to hold fractures open so that the target hydrocarbons can flow from the 

formation through the fractures and up the wellbore. The combination of additives, and the mixing 

and injection process, varies based on a number of factors as discussed below. The additive

combination determines the amount and type of equipment required for storage and, therefore, 

contributes to the determination of the potential for spills and impacts of those spills.

The particular composition of a hydraulic fracturing fluid is designed based on empirical 

experience, the geology and geochemistry of the production zone, economics, goals of the fracturing 

process, availability of the desired chemicals, and preference of the service company or operator 

(Montgomery, 2013; ALL Consulting, 2012; Klein et al., 2012; Ely, 1989).3 No single set of specific 

chemicals is used at every site. Multiple types of fracturing fluids may be appropriate for a given 

site, and any given type of fluid may be appropriate at multiple sites. For the same type of fluid 

formulation, there can be differences in the additives, chemicals in those additives, and the 

concentrations selected. There are broad criteria for hydraulic fracturing fluid selection based on 

the targeted production zone temperature, pressure, water sensitivity, and permeability (Gupta and 

Valkó, 2007; Elbel and Britt, 2000). Figure 5-3 provides a general overview of the types of decisions 

to determine which fluid can be used for different situations. Similar fluids may be appropriate for 

different formations. For example, crosslinked fluids with 25% nitrogen foam (titanate or zirconate 

crosslink + 25% nitrogen) can be used in both gas and oil wells with high temperatures and

additive (as median maximum concentration) (U.S. EPA, 2015a), 94% water, 6% proppant, <1% additive (Sjolander et al., 

2011), 88% water, 11% proppant, <1% additive (OSHA, 2014a, b). By volume: 95% water, 5% proppant, <1% additive 

(before mixing), 97% water, 2% proppant, <1% additive (after mixing) (Sjolander et al., 2011), 90% water, 10% 

proppant, <1% additive (before mixing), 95% water, 5% proppant, <1% additive (after mixing) (OSHA, 2014a, b), 98-

99.5%, water and sand 0.5 to 2% additives (Spellman, 2012). Not specified: 99.9% water and sand, 0.1% chemicals (SWN, 

2011), 98-99% water and proppant, 1-2 % additives (Carter et al., 2013).

1 We use “hydraulic fracturing fluid” to refer to the fluid that is injected into the well and used to create and hold open

fractures the formation.

2 In this chapter, because of the way many chemicals are reported, we use the word “chemical” to refer to any individual 

chemical or chemical substance that has been assigned a CASRN (Chemical Abstracts Service Registry Number). A CASRN 

is a unique identifier for 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 C9 to 

C16 hydrocarbons). For simplicity, we refer to both pure chemicals and chemical substances that are mixtures, which 

have a single CASRN, as “chemicals.”

3 Empirical experience tends to provide better result as operators gain experience at a new site or geology increases. 

When an operator moves to a new basin geology, there may be less than optimal results. With experience and 

understanding of the geology increases, the empirical evidence will inform what hydraulic fracturing fluid composition 

works better than others.
Chapter 5 – Chemical Mixing

5-9 

Figure 5-3. Example hydraulic fracturing fluid decision tree for gas and oil wells.

This decision tree figure serves as an example of the factors that determine the type of hydraulic fracturing fluid chosen to fracture a given formation, depending on whether the 

well will produce oil or gas. Factors include water sensitivity, formation temperature, and pressure. HPG is hydroxypropylguar, guar derivatized with propylene oxide. 

Parameters are: kf, fracture permeability, w is the fracture width, and xf is the fracture half-length. This figure was chosen to represent the differences between oil and gas wells 

and the types of decisions involved with choosing a fluid. This is adapted from Elbel and Britt (2000) and, as such, is dated to that time period. Since then, slickwater has become 

increasingly popular due to its simplicity and cheaper cost, and slickwater has often replaced linear and crosslinked gelled fluids, especially in shales. Other decision tree figures 

may exist. © 2000 Schlumberger. First published by John Wiley & Sons Ltd. All rights reserved.
Chapter 5 – Chemical Mixing

5-10 

variation in water sensitivity.1,2 One of the most important properties in designing a hydraulic 

fracturing fluid is the viscosity (Montgomery, 2013).3

Table 5-1 provides a list of common types of additives, their functions, and the most frequently

used chemicals for each purpose based on the EPA’s analysis of disclosures to FracFocus 1.0 (U.S. 

EPA, 2015a, hereafter referred to as the EPA FracFocus 1.0 report), the EPA’s project database of 

disclosures to FracFocus 1.0 (U.S. EPA, 2015c, hereafter referred to as the EPA FracFocus 1.0

project database), and other literature sources.4 Additional information on more additives can be 

found in U.S. EPA (2015a).

A general description of typical hydraulic fracturing fluid formulations nationwide is difficult, 

because fracturing fluids vary from well to well. Based on the EPA FracFocus 1.0 report, the median 

number of chemicals reported for each disclosure was 14, with the 5th to 95th percentile ranging 

from four to 28 (see Appendix H for a list of hydraulic fracturing fluid chemicals). The median 

number of chemicals per disclosure was 16 for oil wells and 12 for gas wells (U.S. EPA, 2015a). 

Other sources have stated that between three and 12 additives and chemicals are used 

(Schlumberger, 2015; Carter et al., 2013; Spellman, 2012; GWPC and ALL Consulting, 2009).5 

Water, the most commonly used base fluid for hydraulic fracturing, is inferred to be used as a base 

fluid in more than 93% of EPA FracFocus 1.0 disclosures (U.S. EPA, 2015c). Alternatives to waterbased fluids, such as hydrocarbons and gases, including carbon dioxide and nitrogen-based foam, 

may also be used based on formation characteristics, cost, or preferences of the well operator or 

service company (ALL Consulting, 2012; GWPC and ALL Consulting, 2009). Non-aqueous base fluid 

ingredients were identified in 761 (2.2%) of EPA FracFocus 1.0 disclosures (U.S. EPA, 2015a). Gases 

and hydrocarbons may be used alone or blended with water; more than 96% of the disclosures 

identifying non-aqueous base fluids are blended (U.S. EPA, 2015a). There is no standard method to 

categorize the different fluid formulations (Patel et al., 2014; Montgomery, 2013; Spellman, 2012; 

Gupta and Valkó, 2007). Therefore, we broadly categorize the fluids as water-based or alternative 

fluids. 

1 A crosslinked fluid is a fluid that has polymers that have been linked together through a chemical bond. A crosslink 

chemical is added to have the polymer chains linked together to form larger chemical structures with higher viscosity. 

The increased fracturing fluid viscosity allows the fluid to carry more proppant into the fractures. The fracturing fluid 

remains viscous until a breaking agent is introduced to break the cross-linked polymer. 

2 Water sensitivity refers to when a formation’s physicochemical properties are affected in the presence of water. An 

example of a water sensitive formation would be one where the soil particles swell when water is added, reducing the 

permeability of the formation.

3 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 Valkó, 2007). In lowerviscosity 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 et al., 2008; Gupta and Valkó, 2007). 

4 A disclosure refers to all data submitted for a specific oil and gas production well for a specific fracture date.

5 Sources may differ based on whether they are referring to additives or chemicals.
Chapter 5 – Chemical Mixing

5-11 

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, c; Stringfellow et al., 2014; Montgomery, 2013; Vidic et al., 2013; Spellman, 2012; GWPC and ALL 

Consulting, 2009; Arthur et al., 2008; Gupta and Valkó, 2007; Gidley et al., 1989). The additive functions are based 

on information the EPA received from service companies (U.S. EPA, 2013a). 

Additives Function

Chemicals reported in 20% or more of 

disclosures in the EPA FracFocus 1.0 project 

database for given additivea,b

Acid Dissolves cement, minerals, and clays to 

reduce clogging of the pore space

Hydrochloric acid

Biocide Controls or eliminates bacterial growth, 

which can be present in the base fluid and 

may have detrimental effects on the long 

term well productivity

Glutaraldehyde; 

2,2-dibromo-3-nitrilopropionamide

Breaker Reduces the designed increase in viscosity 

of specialized treatment fluids such as gels 

and foams after the proppant has been 

placed and flowback commences to clean 

up the well

Peroxydisulfuric acid diammonium salt

Clay control Prevents the swelling and migration of 

formation clays that otherwise react to 

water-based fluids

Choline chloride

Corrosion 

inhibitor

Protects the iron and steel components in 

the wellbore and treating equipment from 

corrosive fluids

Methanol; propargyl alcohol; isopropanol

Crosslinker Increases the viscosity of base gel fluids by 

connecting polymer molecules

Ethylene glycol; potassium hydroxide; sodium 

hydroxide

Emulsifier Facilitates the dispersion of one immiscible 

fluid into another by reducing the interfacial 

tension between the two liquids to achieve 

stability

2-Butoxyethanol; 

polyoxyethylene(10)nonylphenyl ether; methanol; 

nonyl phenol ethoxylate

Foaming agent Generates and stabilizes foam fracturing 

fluids

2-Butoxyethanol; Nitrogen, liquid; isopropanol; 

methanol; ethanol

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

Guar gum; hydrotreated light petroleum distillates

Iron control 

agent

Controls the precipitation of iron 

compounds (e.g., Fe2O3) from solution

Citric acid
Chapter 5 – Chemical Mixing

5-12 

Additives Function

Chemicals reported in 20% or more of 

disclosures in the EPA FracFocus 1.0 project 

database for given additivea,b

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 emulsions1

Hydrochloric acid

a Chemicals (excluding water and quartz) listed in the EPA FracFocus 1.0 project database in more than 20% of disclosures for a 

given purpose when that purpose was listed as used on a disclosure (U.S. EPA, 2015c). 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). 

b Analysis considered 32,885 disclosures and 615,436 ingredient records that met selected quality assurance criteria, including: 

completely parsed (parsing is the process of analyzing a string of symbols to identify and separate various components); 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.

5.3.1 Water-Based Fracturing Fluids 

The advantages of water-based fracturing fluids are low cost, ease of mixing, and ability to recover 

and reuse the water. The disadvantages are that they have low viscosity, they create narrow 

fractures, and they may not provide optimal performance in water-sensitive formations 

(Montgomery, 2013; Gupta and Valkó, 2007) (Section 5.3.2). Water-based fluids can be as simple as 

water with a few additives to reduce friction, such as “slickwater,” or as complex as water with 

crosslinked polymers, clay control agents, biocides, and scale inhibitors (Spellman, 2012). (See 

Figure 5-4 for a slickwater example.)

Gels may be added to water-based fluids to increase viscosity, which assists with proppant 

transport and results in wider fractures. Gelling agents include natural polymers, such as guar, 

starches, and cellulose derivatives, which require the addition of biocide to minimize bacterial 

growth (Spellman, 2012; Gupta and Valkó, 2007). Gels may be linear or crosslinked. Crosslinking 

 

1 Wettability is the ability of a liquid to maintain contact with a solid surface. When wettability is high, a liquid droplet will 

lie flat across a surface, maximizing the area of contact between the liquid and the solid. When wettability is low, a liquid

droplet will approach a spherical shape, minimizing the area of contact between the liquid and solid.
Chapter 5 – Chemical Mixing

5-13 

increases viscosity without adding more gel. Gelled fluids require the addition of a breaker, which 

breaks down the gel after it carries in the proppant, to reduce fluid viscosity to facilitate fluid 

flowing back after treatment (Spellman, 2012; Gupta and Valkó, 2007). The presence of residual 

breakers may make it difficult to reuse recovered water (Montgomery, 2013). 

5.3.2 Alternative Fracturing Fluids

Alternative hydraulic fracturing fluids can be used for water sensitive formations (i.e., formations 

where permeability is reduced when water is added) or as dictated by production goals 

(Halliburton, 1988). Examples of alternative fracturing fluids include acid-based fluids; nonaqueous-based fluids; energized fluids, foams, or emulsions; viscoelastic surfactant fluids; gels; 

methanol; and other unconventional fluids (Montgomery, 2013; Saba et al., 2012; Gupta and Hlidek, 

2009; Gupta and Valkó, 2007; Halliburton, 1988). 

Acid fracturing is generally used in carbonate formations without the use of a proppant. Fractures 

are initiated with a hydraulic fracturing fluid, and acid (gelled, foamed, or emulsified) is added to 

irregularly etch the wall of the fracture. The etching serves to prop open the formation, for a highconductivity fracture (Spellman, 2012; Gupta and Valkó, 2007). 

Non-aqueous fluids, like petroleum distillates and propane, are used in water-sensitive formations. 

Non-aqueous fluids may also contain additives, such as gelling agents, to improve performance

(Gupta and Valkó, 2007). The use of non-aqueous fluids has decreased due to safety concerns, and 

because water-based and emulsion fluid technologies have improved (Montgomery, 2013; Gupta 

and Valkó, 2007). Methanol, for example, was previously used as a base fluid in water-sensitive 

reservoirs beginning in the early 1990s, but was discontinued in 2001 for safety concerns and cost

(Saba et al., 2012; Gupta and Hlidek, 2009; Gupta and Valkó, 2007). Methanol is still widely used as 

an additive or in additive mixtures in hydraulic fracturing fluid formulations. 

Energized fluids, foams, and emulsions minimize fluid leakoff in low pressure targeted geologic 

formations, have high proppant-carrying capacity, improve fluid recovery, and are sometimes used 

in water-sensitive formations (Barati and Liang, 2014; Gu and Mohanty, 2014; Spellman, 2012; 

Gupta and Valkó, 2007; Martin and Valko, 2007).1 However, these treatments tend to be expensive, 

can require high pressure, and pose potential health and safety concerns (Montgomery, 2013; 

Spellman, 2012; Gupta and Valkó, 2007). Energized fluids (see Figure 5-4 for an example of an 

energized fluid composition) are mixtures of liquid and gas (Patel et al., 2014; Montgomery, 2013). 

Nitrogen (N2) or carbon dioxide (CO2), the gases used, make up less than 53% of the fracturing fluid 

volume, typically ranging from 20% to 30% by volume (Montgomery, 2013; Gupta and Valkó, 2007; 

Mitchell, 1970). Energized foams are liquid-gas mixtures, with nitrogen or carbon dioxide gas 

comprising more than 53% of the fracturing fluid volume, with a typical range of 65% to 80% by 

volume (Montgomery, 2013; Mitchell, 1970). Emulsions are liquid-liquid mixtures, typically a 

 

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.
Chapter 5 – Chemical Mixing

5-14 

hydrocarbon (e.g., condensate or diesel) with water.1 Both water-based fluids, including gels, and 

non-aqueous fluids can be energized fluids or foams. 

Foams and emulsions break easily using gravity separation and are stabilized by using additives 

such as foaming agents (Gupta and Valkó, 2007). Emulsions may be used to stabilize active chemical 

ingredients or to delay chemical reactions, such as the use of carbon dioxide-miscible, non-aqueous

fracturing fluids to reduce fluid leakoff in water-sensitive formations (Taylor et al., 2006). 

Other types of fluids not addressed above include viscoelastic surfactant fluids, viscoelastic 

surfactant foams, crosslinked foams, liquid carbon dioxide-based fluid, and liquid carbon dioxidebased foam fluid, and hybrids of other fluids (King, 2010; Brannon et al., 2009; Curtice et al., 2009; 

Tudor et al., 2009; Gupta and Valkó, 2007; Coulter et al., 2006; Boyer et al., 2005; Fredd et al., 2004; 

MacDonald et al., 2003). 

5.3.3 Tracers 

Some chemicals are added to the fluid to act as tracers. Tracers are added to hydraulic fracturing 

fluid to assess the efficiency of fracturing and proppant placement. As an example, the efficiency of 

oil production from multistage fracturing was assessed by using 17 oil soluble tracers. Each tracer 

was used to assess production from a specific interval of the well (Catlett et al., 2013), although the 

specific compounds used were not identified (Table 5-2). Chemical classes of tracers and individual 

examples show a range of compounds employed including both inorganic and organic, and 

including radioactive elements, although only a few specific chemicals have been revealed. Of these, 

examples are proppant tracers and fluorocarbons. Although radioactive fluids have also been used 

for proppant tracing, a commonly-used approach has the short-half-life elements Antimony124, 

Iridium192, and Scandium46 bound to the proppants and gamma emissions are subsequently 

measured by a neutron-logging device (Sonnenfield et al., 2016; Odegard et al., 2015; Lowe et al., 

2013; Osborn and McIntosh, 2011; McDaniel et al., 2010).2,3 Of the organic tracers, 14 fluorinated 

organics have been identified through an analysis of FracFocus 2.0 disclosures (Konschnik and 

Dayalu, 2016). Three fluorinated tracers and Antimony124 were identified in produced water 

(Maguire-Boyle and Barron, 2014) (Appendix Table H-4). 

Table 5-2. Classes and specifically identified examples of tracers used in hydraulic fracturing 

fluids.

Class Specific Chemicala Reference

Thiocyanates (SCN-) ND Dugstad (2007)

Fluorobenzoic acids ND Dugstad (2007)

1 Diesel is a mixture typically of C8 to C21 hydrocarbons. The shorthand “C8” is used to represent a hydrocarbon with 8 

carbons. Thus “C21” represents a hydrocarbon with 21 carbons. Octane has 8 carbons and is thus a C8, and is a 

component of gasoline.

2 Antimony124: 60.2 days, Iridium192: 74 days, Scandium46: 83.8 days.

3 Gadolinium155 and Gadolinium157 have been suggested as bound proppant tracers because of their high-gamma-capture 

cross-sections (Liu et al., 2015). 
Chapter 5 – Chemical Mixing

5-15 

Class Specific Chemicala Reference

Radioactive tracers Tritiated Water Dugstad (2007)

Tritiated Methanol Dugstad (2007)

Antimony124 Silber et al. (2003)

Iridium192 Silber et al. (2003)

Scandium46 Silber et al. (2003)

Fluorocarbons 2,2,3,3,4,4,4-heptafluorobutyl undecylate Maguire-Boyle and Barron (2014)

2,3,4-Trifluorobenzoic acid Konschnik and Dayalu (2016)

2,4,5-Trifluorobenzoic acid Konschnik and Dayalu (2016)

2,4-Difluorobenzoic acid Konschnik and Dayalu (2016)

2,6-Difluorobenzoic acid Konschnik and Dayalu (2016)

2-Chloro-4-fluorobenzoic acid Konschnik and Dayalu (2016)

2-Fluorobenzoic acid Konschnik and Dayalu (2016)

2-Trifluoromethylbenzoic acid Konschnik and Dayalu (2016)

3-Trifluoromethylbenzoate Konschnik and Dayalu (2016)

4-(Trifluoromethyl)benzoic acid Konschnik and Dayalu (2016)

4-Chloro-2-fluorobenzoic acid Konschnik and Dayalu (2016)

4-fluoro-2-(trifluoromethyl)benzoic acid Konschnik and Dayalu (2016)

4-Fluoro-3-(trifluomethyl)benzoic acid Konschnik and Dayalu (2016)

Benzoic acid, 3,5-difluoro- Konschnik and Dayalu (2016)

cis-4-ethyl-5-octyl-2,2-bis(trifluoromethyl)-1,3 

dioxolane

Maguire-Boyle and Barron (2014)

p-Fluorobenzoic acid Konschnik and Dayalu (2016)

tri-fluoromethyl tetradeculate Maguire-Boyle and Barron (2014)

Oil soluble alkyl esters ND Deans (2007)

Unstable emulsions ND Catlett et al. (2013)

Controlled-release 

polymers and solid 

tracers

ND Salman et al. (2014) 

a ND = none disclosed. 
Chapter 5 – Chemical Mixing

5-16 

A different set of tracers have been proposed for identifying environmental impacts from hydraulic 

fracturing fluids (Kurose, 2014). These tracers are designed so that the fluids from individual wells 

are identifiable while having no environmental impact themselves. DNA and nanoparticles with 

magnetic properties made specifically for each well have been proposed for this purpose (Kurose, 

2014). 

5.3.4 Proppants

Proppants are small particles carried down the well and into fractures by hydraulic fracturing fluid. 

They hold the fractures open after the injection pressure has been released and the hydraulic 

fracturing fluid has been removed (Brannon and Pearson, 2007). The propped fractures provide a 

path for the hydrocarbon to flow from the reservoir. The EPA’s analysis of FracFocus 1.0 data 

showed that 98% of disclosures reported sand as the proppant, making sand (i.e., quartz) the most 

commonly reported proppant (U.S. EPA, 2015a). Other proppants include man-made or specially 

engineered particles, such as high-strength ceramic materials or sintered bauxite (Schlumberger, 

2014; Brannon and Pearson, 2007). Proppant types can be used individually or in combinations.

5.3.5 Example Hydraulic Fracturing Fluids

There is no standard composition of hydraulic fracturing fluid used across the United States, and 

the literature does not present any typical hydraulic fluid composition. In Figure 5-4, we present 

two examples of hydraulic fracturing fluid mixtures based on analyses conducted on the EPA 

FracFocus 1.0 project database (U.S. EPA, 2015c). These examples represent two different types of 

fluids used at two different wells. The first is a slickwater, and the second is an energized fluid.1

Details of each fluid are presented in the figure along with pie charts of their composition, as given 

by maximum percent by mass of the total hydraulic fracturing fluid. 

The first hydraulic fracturing fluid (Figure 5-4a), the slickwater, is composed of 87% water, 13% 

sand, and 0.05% chemicals, by mass. The fluid is 71% fresh water and 16% reused produced water, 

with a total water volume of 4,763,000 gal (18,030,000 L). The chemical composition consists of six 

different additive types (acid, friction reducer, biocide, scale inhibitor iron control, and corrosion 

inhibitor) and a total of 13 chemicals. 

The second hydraulic fracturing fluid (Figure 5-4b), the energized fluid, is more complex and 

consists of 58% water, 28% nitrogen gas, 13% sand, and 1.5% additives, by mass, with a total water 

volume of 105,000 gal (397,000 L). The hydraulic fracturing fluid composition consists of 10 

additives (acid, surfactant, foamer, corrosion inhibitor, biocide, friction reducer, breaker, scale 

inhibitor, iron control, and clay stabilizer) and a total of 28 chemicals.

1 A slickwater is a hydraulic fracturing fluid designed to have a low viscosity to allow pumping at high rates. The critical 

additive in a slickwater is the friction reducer, which makes the fluid “slick.”
Chapter 5 – Chemical Mixing

5-17 

Figure 5-4. Example hydraulic fracturing fluids. 

Example compositions of (a) slickwater and (b) energized fluid. The base fluid and proppants are on the left, and 

the additive breakdown is on the right. The number in parentheses represents the number of chemicals in that 

additive. See Table 5-1 for the function of different additives and the most common chemicals in those additives 

reported as based on the analysis of the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). 

These two examples give an idea of the difference in the compositions of two example hydraulic 

fracturing fluids. These compositions are the final mixture as if the entire fluid were mixed at once; 

they are generally not the actual composition at any given point in time. These compositions 

provide the potential composition of a spilled hydraulic fracturing fluid during the chemical mixing 

stage. Any of these ingredients (e.g., biocide) could be released by itself or mixed with the base fluid 

with other additives. The variability of hydraulic fracturing fluids from well to well and site to site 

makes it difficult to assess the potential of hydraulic fracturing additive or fluid release. 

5.4 Frequency and Volume of Hydraulic Fracturing Chemical Use

This section highlights the different chemicals used in hydraulic fracturing fluids and discusses the 

frequency and volume of use. Using the EPA FracFocus 1.0 project database (Text Box 5-1), we 

focus our analysis on the individual chemicals that are used as ingredients in additive formulations, 

rather than on the complete mixture of chemicals that may be present in a hydraulic fracturing 

fluid. Operators can report information about well location, date of operations, and water and 

chemical use to the FracFocus registry. Chemicals are reported in FracFocus by using the chemical 
Chapter 5 – Chemical Mixing

5-18 

name and the Chemical Abstract Services Registration Number (CASRN), which is a unique number 

identifier for every chemical.1 The information on specific chemicals, particularly those most 

commonly used, can be used to assess potential impacts on drinking water resources. The volume 

of chemicals stored on-site provides information on the potential volume of a chemical spill. 

Text Box 5-1. 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 and water they use during hydraulic fracturing. 

As part of the EPA’s Study of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water 

Resources, the EPA published the report titled Analysis of Hydraulic Fracturing Fluid Data from the FracFocus 

Chemical Disclosure Record Registry 1.0 (U.S. EPA, 2015a). For this report, the EPA accessed data from 

FracFocus 1.0 from January 1, 2011 to February 28, 2013, which included more than 39,000 disclosures 

(records of well data) in 20 states that had been submitted by operators prior to March 1, 2013.

Accompanying the U.S. EPA (2015a) report is the published EPA FracFocus 1.0 project database, which. It 

supported analyses of FracFocus chemical and water use data (U.S. EPA, 2015c), and a report describing the 

details of data management for development of the project database (U.S. EPA, 2015b). 

Submission to FracFocus was initially voluntary and varied from state to state. During the timeframe covered 

in the EPA FracFocus 1.0 report (January 2011 to February 2013), six of the 20 states with data submitted to 

FracFocus and included in the EPA FracFocus 1.0 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.

The EPA’s analysis may or may not be nationally representative. 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. 

A disclosure reports the total water volume (in gallons) and the chemicals used in the fluid (as maximum 

ingredient concentration by mass both in the additive and in the hydraulic fracturing fluid). The actual mass 

of the chemicals used in the fluid are not reported. The fluid composition reported in the disclosure does not 

necessarily reflect the actual composition of the fluid at any time. Rather, the disclosure represents what the 

total composition of the fluid would be if all chemicals used were mixed together at their maximum reported 

concentration. 

The EPA summarized information on the locations of the wells in the disclosures, water volumes used, and 

the frequency of use and maximum ingredient concentrations of the chemicals in the additives and the 

hydraulic fracturing fluid. Additional information can be found in the EPA FracFocus 1.0 report (U.S. EPA, 

2015a) and in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). 

 

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 C9 to C16 hydrocarbons). For simplicity, we refer to both pure chemicals and 

chemical substances that are mixtures, which have a single CASRN, as “chemicals.”
Chapter 5 – Chemical Mixing

5-19 

The EPA compiled a list of 1,084 chemicals with unique CASRNs reported as used in the hydraulic

fracturing process between 2005 and 2013 (full list, methodology, and details on sources in 

Appendix H).1 These chemicals fall into different chemical classes and include 455 organic 

chemicals, 258 inorganic chemicals, and 361 organic mixtures or polymers. The chemical classes of 

commonly used hydraulic fracturing chemicals include but are not limited to:

• Acids (e.g., hydrochloric acid, peroxydisulfuric acid, acetic acid, citric acid); 

• Alcohols (e.g., methanol, isopropanol, ethylene glycol, propargyl alcohol, ethanol); 

• Aromatic hydrocarbons (e.g., benzene, naphthalene, heavy aromatic petroleum solvent 

naphtha); 

• Bases (e.g., sodium hydroxide, potassium hydroxide); 

• Hydrocarbon mixtures (e.g., petroleum distillates); 

• Polysaccharides (e.g., guar gum); 

• Surfactants (e.g., poly(oxy-1,2-ethanediyl)-nonylphenyl-hydroxy, 2-butoxyethanol); and

• Salts (e.g., sodium chlorite, dipotassium carbonate).

Further details on these chemicals and their associated hazards are presented in Chapter 9.

All of the sources of information used to compile the list of chemicals found in hydraulic fracturing 

fluids (Appendix H) relied on reported use of those chemicals. In some cases, analysis of produced 

water samples by advanced analytical methods could provide information on suspected hydraulic 

fracturing additives, but other sources for the chemicals need careful consideration (Hoelzer et al., 

2016). These sources include chemicals originating from components of the well, lab 

contamination, or subsurface reaction. We limit our discussion of hydraulic fracturing fluid 

chemicals to those directly reported as used.

An additional complication in providing an assessment on the use of chemicals in hydraulic 

fracturing is that companies can withhold reporting chemicals to the FracFocus registry by claiming 

that a chemical is Confidential Business Information (CBI). The use of CBI is to protect proprietary 

information, such as trade secrets. Details on CBI are provided in Text Box 5-2.

 

1 The EPA used eight different sources to identify chemicals used in hydraulic fracturing fluids. This included the EPA 

FracFocus report (U.S. EPA, 2015a) and seven other sources (U.S. EPA, 2013a; Colborn et al., 2011; House of 

Representatives, 2011; NYSDEC, 2011; PA DEP, 2010a; U.S. EPA, 2004a; Material Safety Data Sheets). 
Chapter 5 – Chemical Mixing

5-20 

Text Box 5-2. Confidential Business Information (CBI). 

This assessment relies in large part upon information provided to the EPA or to other organizations. The 

submitters (e.g., businesses that operate wells or perform hydraulic fracturing services) may view some of 

the information as confidential business information (CBI) and accordingly asserted CBI claims to protect it. 

Information deemed to be CBI may include 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. The FOIA and 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. In practical terms, when a well operator claims CBI for a 

specific chemical, they do not report the name or CASRN for that chemical in the disclosure submitted to the 

FracFocus registry (see Text Box 5-1 for information on FracFocus). 

The EPA evaluated data from FracFocus, a national hydraulic fracturing chemical registry used and relied 

upon by some states, industry groups, and non-governmental organizations, as described in Text Box 5-1. A 

company submitting a disclosure to FracFocus may choose to not report the identity of a chemical it 

considers CBI. More than 70% of disclosures contained at least one chemical claimed as CBI and 11% of all 

chemicals were claimed as CBI. Of the disclosures containing CBI chemicals, there were an average of five CBI 

chemicals per disclosure (U.S. EPA, 2015a). Rates of withholding chemical information (designating a 

chemical as CBI) have increased from 11% in the 2011 to early 2013 time period of the EPA report, to 16.5% 

across the 2011 to early 2015 time period in another study using FracFocus data, with 92% of FracFocus 2.0 

disclosures including at least one chemical claimed as CBI (Konschnik and Dayalu, 2016). When a chemical is 

claimed as CBI, there is no public means of accessing information on these chemicals (e.g., CASRN, name). 

Sometimes a CBI entry will provide the chemical family (Appendix H). 

Consistent with the EPA’s Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water 

Resources (U.S. EPA, 2011d), data were submitted by nine service companies to the EPA regarding chemicals 

used in hydraulic fracturing from 2005 to 2009. These data were separate from the EPA FracFocus 1.0 project 

database. The data were submitted directly to the EPA, with 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). Of these 381 chemicals, some companies only provided a 

generic chemical name and no CASRN, some provided neither a chemical name or CASRN, while others 

provided a CASRN and a specific chemical name. This resulted in 80 CASRNs/chemical names on this CBI list. 

Table H-3 lists generic chemical names, which may have been designed to mask CBI chemical names given to

the EPA. The EPA does not know if the 381 chemicals represent 381 unique chemicals or if there are 

duplicates on this list.

The prevalence of CBI claims in the EPA FracFocus 1.0 project database limits completeness of the data set

and introduces uncertainty. Ideally, all data would be available on all chemicals to do a full assessment.

5.4.1 National Frequency of Use of Hydraulic Fracturing Chemicals

A total of 692 chemicals were identified in the EPA FracFocus 1.0 project database that were 

reported as used in hydraulic fracturing from January 1, 2011, to February 28, 2013. This 

information comes from a total of 35,957 disclosures with chemical data in the database (U.S. EPA, 

2015a).1

 

1 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). 
Chapter 5 – Chemical Mixing

5-21 

Table 5-3 presents the 35 chemicals (5% of all chemicals identified in the EPA’s study) that were 

reported as ingredients in additives in at least 10% of the EPA FracFocus 1.0 project database 

disclosures for all states reporting to FracFocus 1.0 during this time (U.S. EPA, 2015c). This table 

also includes the top four additives in which the given chemical was reported as an ingredient. 

Table 5-3. Chemicals identified in the EPA FracFocus 1.0 project database in 10% or more 

disclosures, with the percent of disclosures for which each chemical is reported as an 

ingredient in an additive and the top four reported additives for which the chemical is used.

If a chemical is reported to be used in less than four additives, the table presents all additives (U.S. EPA, 2015c). 

No. Chemical namea CASRN

Percent of 

disclosuresb

Additives in which chemical is used 

(four most common, EPA FracFocus 1.0 

project database)c

1 Methanol 67-56-1 72% Corrosion inhibitors, surfactants, nonemulsifiers, scale control

2 Hydrotreated light 

petroleum distillatesd

64742-47-8 65% Friction reducers, gelling agents and gel 

stabilizers, crosslinkers and related additives, 

viscosifiers

3 Hydrochloric acid 7647-01-0 65% Acids, solvents, scale control, clean 

perforations

4 Watere 7732-18-5 48% Acids, biocides, clay control, scale control

5 Isopropanol 67-63-0 47% Corrosion inhibitors, non-emulsifiers, 

surfactants, biocides

6 Ethylene glycol 107-21-1 46% Crosslinkers and related additives, scale 

control, corrosion inhibitors, friction reducers

7 Peroxydisulfuric acid, 

diammonium salt

7727-54-0 44% Breakers and breaker catalysts, oxidizer, 

stabilizers, clean perforations

8 Sodium hydroxide 1310-73-2 39% Crosslinkers and related additives, biocides, pH 

control, scale control

9 Guar gum 9000-30-0 37% Gelling agents and gel stabilizers, viscosifiers, 

clean perforations, breakers and breaker 

catalysts

10 Quartze 14808-60-7 36% Breakers and breaker catalysts, gelling agents 

and gel stabilizers, scale control, crosslinkers 

and related additives

11 Glutaraldehyde 111-30-8 34% Biocides, surfactants, crosslinkers and related 

additives, sealers

12 Propargyl alcohol 107-19-7 33% Corrosion inhibitors, inhibitors, acid inhibitors, 

base fluid

13 Potassium hydroxide 1310-58-3 29% Crosslinkers and related additives, pH control, 

friction reducers, gelling agents and gel 

stabilizers
Chapter 5 – Chemical Mixing

5-22 

No. Chemical namea CASRN

Percent of 

disclosuresb

Additives in which chemical is used 

(four most common, EPA FracFocus 1.0 

project database)c

14 Ethanol 64-17-5 29% Surfactants, biocides, corrosion inhibitors, fluid 

foaming agents and energizers

15 Acetic acid 64-19-7 24% pH control, iron control agents, acids, gelling 

agents and stabilizers

16 Citric acid 77-92-9 24% Iron control agents, scale control, gelling 

agents and gel stabilizers, pH control

17 2-Butoxyethanol 111-76-2 21% Surfactants, corrosion inhibitors, nonemulsifiers, fluid foaming agents and 

energizers

18 Sodium chloride 7647-14-5 21% Breakers/breaker catalysts, friction reducers, 

scale control, clay control

19 Solvent naphtha, 

petroleum, heavy arom.f

64742-94-5 21% Surfactants, non-emulsifiers, inhibitors, 

corrosion inhibitors

20 Naphthalene 91-20-3 19% Surfactants, non-emulsifiers, corrosion 

inhibitors, inhibitors

21 2,2-Dibromo-3-

nitrilopropionamide

10222-01-2 16% Biocides, clean perforations, breakers and 

breaker catalysts, non-emulsifiers

22 Phenolic resin 9003-35-4 14% Proppants, biocides, clean perforations, base 

fluid

23 Choline chloride 67-48-1 14% Clay control, clean perforations, base fluid, 

biocides

24 Methenamine 100-97-0 14% Proppants, crosslinkers and related additives, 

biocides, base fluid

25 Carbonic acid, 

dipotassium salt

584-08-7 13% pH control, proppants, acids, surfactants

26 1,2,4-Trimethylbenzene 95-63-6 13% Surfactants, non-emulsifiers, corrosion 

inhibitors, inhibitors

27 Quaternary ammonium 

compounds, benzyl-C12-

16-alkyldimethyl, 

chloridesg

68424-85-1 12% Biocides, non-emulsifiers, corrosion inhibitors, 

scale control

28 Poly(oxy-1,2-ethanediyl)-

nonylphenyl-hydroxy 

(mixture)h

127087-87-0 12% Surfactants, friction reducers, non-emulsifiers, 

inhibitors

29 Formic acid 64-18-6 12% Corrosion inhibitors, acids, inhibitors, pH 

control
Chapter 5 – Chemical Mixing

5-23 

No. Chemical namea CASRN

Percent of 

disclosuresb

Additives in which chemical is used 

(four most common, EPA FracFocus 1.0 

project database)c

30 Sodium chlorite 7758-19-2 11% Breakers/breaker catalysts, biocides, oxidizer, 

proppants

31 Nonyl phenol ethoxylate 9016-45-9 11% Non-emulsifiers, resin curing agents, 

activators, friction reducers

32 Tetrakis(hydroxymethyl)

phosphonium sulfate

55566-30-8 11% biocides, scale control, clay control

33 Polyethylene glycol 25322-68-3 11% Biocides, non-emulsifiers, surfactants, clay 

control

34 Ammonium chloride 12125-02-9 10% Friction reducers, crosslinkers and related 

additives, scale control, clay control

35 Sodium persulfate 7775-27-1 10% 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). Chemical names are sometimes different between FracFocus 1.0 and 

Appendix H, though they will have the same CASRN.

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.

d 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, and water were also reported as an ingredient in other 

additives (U.S. EPA, 2015a). 

f Heavy aromatic solvent naphtha (petroleum) (CASRN 64742-94-5) is mixture of aromatic hydrocarbons in the C9 to C16 range.

g 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.

h Poly(oxy-1,2-ethanediyl)-nonylphenyl-hydroxy (mixture) (CASRN 127087-87-0) is mixture with varying length ethoxy links.

There is no single chemical used in all hydraulic fracturing fluids across the United States. Methanol 

is the most commonly used chemical, reported at 72.1% of wells in the EPA FracFocus 1.0 project 

database and is associated with 33 types of additives, including corrosion inhibitors, surfactants, 

non-emulsifiers, and scale control (U.S. EPA, 2015c).1 Table 5-3 also shows the variability in 

different chemicals included in the EPA FracFocus 1.0 project database. The percentage of 

disclosures reporting a given chemical suggests the likelihood of that chemical’s use at a site. Only 

three chemicals (methanol, hydrotreated light petroleum distillates, and hydrochloric acid) were 

used at more than half of the sites nationwide, and only 12 were used at more than one-third. 

 

1 The number of additives may be an overestimate due to parsing issues. The true number of additives may be smaller.
Chapter 5 – Chemical Mixing

5-24 

In addition to providing information on frequency of use, the EPA FracFocus 1.0 project database 

provides the maximum concentration by mass of a given chemical in an additive. For example, 

methanol is the most frequently reported chemical. The median value for the maximum mass 

concentration reported for an additive in FracFocus disclosures is 30%, with a range of 0.44% to 

100% (5th to 95th percentile).1 Thus, methanol is generally used as part of a mixture of chemicals in 

the hydraulic fracturing fluid (typically at a concentration around 30% by mass). Other times, 

methanol is used as an additive in its pure form (concentration 100%). Therefore, methanol will 

sometimes be stored on-site in a mixture of chemicals and other times as pure methanol. This wide 

range of possible concentrations of methanol further complicates assessing the potential impact of 

spills, as the properties of the fluid will depend on the different chemicals present and on their 

concentrations. For all chemicals, spills of a highly concentrated chemical can have different 

potential impacts than spills of dilute mixtures. For more discussion on fluid and additive chemical 

composition, see Section 5.4.5.

A more recent study of FracFocus 2.0 data evaluated disclosures dating from March 9, 2011 to April 

13, 2015 (96,449 disclosures) and reported 981 unique chemicals used in hydraulic fracturing 

(Dayalu and Konschnik, 2016; Konschnik and Dayalu, 2016). The earlier, EPA study (covering the 

2011 to early 2013 time period) found 692 chemicals (U.S. EPA, 2015a). Konschnik and Dayalu

(2016) identified 263 new CASRNs in addition to the 1,084 identified by the EPA (Appendix H), 

increasing the number of chemicals by approximately 24%. Of the new CASRNs, the only chemical 

reported in more than 1% of all disclosures was Alcohols, C9-11-iso-,C10-rich, ethoxylated 

propoxylated (CASRN 154518-36-2). 

The 20 most common chemicals reported in Konschnik and Dayalu (2016) are similar to those 

listed in Table 5-3. There are three chemicals reported on their 20 most common list that are not 

included in Table 5-3. These chemicals are: sorbitan, mono-(9Z)-9-octadecenoate (CASRN 1338-43-

8, reported in 29.6% disclosures (Konschnik and Dayalu, 2016) vs. 4% (U.S. EPA, 2015c), 

ethoxylated C12-16 alcohols (CASRN 68551-12-2, 27.9% vs. 4%), and thiourea polymer (CASRN 

68527-49-1, 24.8% vs. 8%). Ammonium chloride was on each list, but disclosures increased from 

10% to 30.5%. Four chemicals in Table 5-3 were not on their 20 most frequently used list: solvent 

naphtha, petroleum, heavy arom. (CASRN 64742-94-5), naphthalene (CASRN 91-20-3), 2,2-

Dibromo-3-nitrilopropionamide (CASRN 10222-01-2), and phenolic resin (CASRN 9003-35-4).

5.4.2 Nationwide Oil versus Gas 

Analyses based on the EPA FracFocus 1.0 project database also can elucidate the differences 

between the chemicals used during hydraulic fracturing for oil production and those used for gas 

production, providing a better understanding of potential spill impacts from each. Appendix Tables 

C-1 and C-2 present the chemicals reported in at least 10% of all gas (34 chemicals) and oil (39

chemicals) disclosures nationwide. 

 

1 For more information on how chemicals are reported to FracFocus see www.fracfocus.org and U.S. EPA (2015a). 
Chapter 5 – Chemical Mixing

5-25 

Many of the same chemicals are used for oil and gas, but some chemicals are used more frequently 

in oil production and others more frequently in gas.1 For example, hydrochloric acid is the most 

commonly reported chemical for gas wells (73% of disclosures); it is the fifth most frequently 

reported chemical for oil wells (58% of disclosures). However, both oil and gas operators each 

reports using methanol in 72% of disclosures. Methanol is the most common chemical used in 

hydraulic fracturing fluids at oil wells and the second most common chemical in hydraulic 

fracturing fluids at gas wells. 

5.4.3 State-by-State Frequency of Use of Hydraulic Fracturing Chemicals 

The composition of hydraulic fracturing fluids varies from site to site. Since the impacts of hydraulic 

fracturing occur locally, the potential impact depends on the chemicals used locally. We 

investigated geographic variation of chemical use based on the frequency of chemicals reported to 

FracFocus and included in the EPA FracFocus 1.0 project database by state (U.S. EPA, 2015c). 

Appendix Table C-3 presents and ranks chemicals reported most frequently for each state (U.S. EPA, 

2015c). The list of the 20 most frequently reported chemicals used in each state together include 94 

unique chemicals. A total of 94 chemicals indicates some level of similarity in chemical usage among 

states.2

Methanol is reported in 19 of the 20 states (95%). Alaska is the only state in which methanol is not 

reported (based on the state’s 20 disclosures). The percentage of disclosures reporting use of 

methanol ranges from 38% (Wyoming) to 100% (Alabama, Arkansas). 

Ten chemicals (excluding water) are among the 20 most frequently reported in 14 of the 20 states. 

These chemicals are: methanol; hydrotreated light petroleum distillates; ethylene glycol; 

isopropanol; quartz; sodium hydroxide; ethanol; guar gum; hydrochloric acid; and peroxydisulfuric 

acid, diammonium salt.3 These 10 chemicals are also the most frequently reported chemicals 

nationwide. 

This state analysis showed that methanol is used across the contiguous U.S. (not Alaska). There are 

9 other chemicals that are frequently used across the United States. Beyond those, however, there 

are a number of different chemicals that are used in one state more commonly than others, and

many chemicals may not be used at all in other states. 

 

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. There is no nationwide criterion to distinguish oil wells from gas wells. Production wells often produce some of 

both. A well identified as gas-producing in one place might be identified as oil-producing in another. This could affect the 

distribution of chemical use among these wells.

2 The range of possible number of chemicals is from 20 to 400. If every state used the same 20 chemicals, there would be 

20 different chemicals. If all 20 states each used 20 different chemicals, then there would be a total of 400 chemicals used.

3 Quartz was the most commonly reported proppant and also reported as an ingredient in other additives (U.S. EPA, 

2015a). 
Chapter 5 – Chemical Mixing

5-26 

5.4.4 Volume of Chemical Use

Understanding the volume of chemicals used at each site is important for understanding potential 

impacts of chemicals as well as potential severity of impacts on drinking water resources. The 

chemical volume governs how much will be stored on-site, the types of containers required, the 

total amount that could spill, and how much could end up in a drinking water resource. While the 

on-site hydraulic fracturing service company has precise knowledge of the composition and volume 

of chemicals stored on-site, this information is not generally publicly available. We conducted a 

comprehensive review of publicly available sources and found two sources (OSHA, 2014a, b; 

Sjolander et al., 2011) that identify specific chemicals used at a hydraulic fracturing site and 

provide information on volumes. These are presented in Table 5-4. The volume of chemicals totaled 

7,500 gal (28,000 L) and 14,700 gal (55,600 L) for the two sources, with a mean volume for an 

individual chemical of 1,900 gal (7,200 L) and 1,225 gal (4,637 L), respectively. The range of 

volumes for each chemical used is 30 to 3,690 gal (114 to 14,000 L). 

Table 5-4. Example list of chemicals and chemical volumes used in hydraulic fracturing. 

Volumes are for wells with an unknown number of stages and at least one perforation zone. Every well and fluid 

formulation is unique. Blank cells are data not reported. 

Sjolander et al. (2011)a OSHA (2014a, 2014b)b

Ingredient Examples

Volume (gal) 

or mass (lb)

Percent 

overallc

Volume 

(gal)

Percent by 

volume

Water 4,000,000 gal 94.62 2,700,000 gal 90

Proppant Sand ~ 1,500,000 lbd 5.26 285,300 gal 9.51

Acid Hydrochloric acid 

or muriatic acid

1,338 gal 0.03 3,690 gal 0.123

Friction reducer Polyacrylamide, 

mineral oil

2,040 gal 0.05 2,640 gal 0.088

Surfactant Isopropanol 2,550 gal 0.085

Potassium 

chloride

1,800 0.06

Gelling agent Guar gum or 

hydroxymethyl 

cellulose

-

e -e 1,680 0.056

Scale inhibitor Ethylene glycol, 

alcohol, and 

sodium 

hydroxide

2,040 gal 0.05 1,290 0.043

pH buffer Carbonate 330 0.011

Preservative Ammonium 

persulfate

300 0.01
Chapter 5 – Chemical Mixing

5-27 

Sjolander et al. (2011)a OSHA (2014a, 2014b)b

Ingredient Examples

Volume (gal) 

or mass (lb)

Percent 

overallc

Volume 

(gal)

Percent by 

volume

Crosslinker Borate salts -

e -e 210 0.007

Iron control Citric acid -

e -e 120 0.004

Corrosion 

inhibitor

n,n-Dimethyl 

formamide

-

e -e 60 0.002

Biocide / 

antimicrobial 

agent

Glutaraldehyde, 

ethanol, 

methanol

2,040 gal 0.05 30 0.001

Gel-breaker Ammonium 

persulfate

-

e -e

Total volume of all chemicals 7,458 gal 0.18 14,700 0.49

Individual chemical volume: mean 

(full range)

1,864.5 gal 

(1,338 – 2,040 gal)

1,225 

(30 – 3,690)

a Adapted from Penn State “Water Facts” publication entitled Introduction to Hydrofracturing (Sjolander 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.

b Adapted from a table generated by the Occupational Safety and Health Administration (OSHA) for use in a training module 

(OSHA, 2014a, b). 

c As presented in Sjolander et al. (2011); does not explicitly state percent by mass or by volume.

d Sjolander et al. (2011) presents proppant in pounds instead of gallons. 

e Listed as an ingredient, but no information on volume or percentage.

Because of the limited information on chemical volumes publicly available, we estimated chemical 

volumes used across the nation based on the information provided in the EPA FracFocus 1.0 project 

database. Figure 5-5 plots median estimated chemical volumes, ranked from high to low, with the 

range of 5th to 95th percentiles. Estimated volumes used are presented for the 74 chemicals that 

were reported in at least 100 disclosures in the EPA FracFocus 1.0 project database and for which 

density data were available. The estimated median volumes vary widely among the different 

chemicals, covering a range of near zero to 27,000 gal (98,000 L).The mean of the estimated 

median volumes was 650 gal (2,500 L), and the mean of the estimated median mass was 3,200 lb 

(1,500 kg) (U.S. EPA, 2015c). Mass, volume, and density data are presented in Appendix C along 

with the estimation methodology and assumptions used.

With the median chemical volume, we can estimate total chemical volume for all chemicals used. 

Based on the above mean of median chemical volumes of 650 gal (2,500 L) per chemical, and given 

that the median number of chemicals used at a site is 14 (U.S. EPA, 2015a), an estimated 9,100 gal

(34,000 L) of chemicals may be used per well. Given that the number of chemicals per well ranges 

from 4 to 28 (U.S. EPA, 2015a), the total volume of chemicals per well may range from 2,600 to 

18,000 gal (9,800 to 69,000 L). 
Chapter 5 – Chemical Mixing

5-28 

Another way to estimate total volume of chemicals per well is to use the estimated median volume 

of 1.5 million gal (5.7 million L) of fluid used to fracture a well (U.S. EPA, 2015a) (Chapter 4) and

assume that up to 2% of that volume consists of chemicals added to base fluid (Carter et al., 2013; 

Knappe and Fireline, 2012), resulting in up to 30,000 gal (114,000 L) of chemicals used per well. 

Using the estimated volume per chemical of 650 gal (2,500 L), we can also estimate volume per 

additive and extrapolate to estimate on-site chemical storage. If we assume three to five chemicals 

per additive, then total volume per additive stored on-site would be approximately 1,900 to 3,200 

gal (7,400 to 12,000 L). On-site containers generally store 20% to 100% more additive volume than 

ultimately used (Houston et al., 2009; Malone and Ely, 2007). This would suggest that 2,300 to 

6,500 gal (8,800 to 25,000 L) per additive are stored on site. 

Figure 5-5. Estimated median volumes for 74 chemicals reported in at least 100 disclosures in 

the FracFocus 1.0 project database for use in hydraulic fracturing from January 1, 2011 to 

February 28, 2013. 

Chemicals are plotted in order of largest to smallest median volume. Shaded area represents the zone of 5% and 

95% confidence limits. Derived from U.S. EPA (2015c). 

5.4.5 Chemical Composition of Hydraulic Fracturing Fluids and Additives

As the hydraulic fracturing process proceeds, the composition of the fluid injected changes over 

time. The overall composition of additives and hydraulic fracturing fluid may be reported by well 
Chapter 5 – Chemical Mixing

5-29 

operators to the FracFocus national registry, depending on the local disclosure requirements and 

operator preference. For each chemical that is injected into a well (excluding CBI chemicals), the 

maximum concentration in the resulting overall fluid and in each additive is given as maximum 

percent by mass. Based on this information, we calculated the median chemical composition 

reported in at least 10% of the disclosures in the EPA FracFocus 1.0 project database (Table 5-3) 

and a range based on the 5th and 95th percentile. Table 5-5 shows that some chemicals may be used 

in their pure form (100% of mass in a given additive). These chemicals include: methanol, 

hydrochloric acid, water, isopropanol, guar gum, citric acid, 2,2-Dibromo-3-nitrilopropionamide, 

tetrakis(hydroxymethyl) phosphonium sulfate, and sodium persulfate. 

Chemicals may be stored in their concentrated, pure form, resulting in the potential for spills of 

concentrated volumes of these chemicals, which may increase the severity of impacts if they reach a 

drinking water resource. Once chemicals are mixed with the base fluid to form the hydraulic 

fracturing fluid, the chemical is diluted to much lower concentrations, which has the potential for a 

less severe impact. However, a larger volume of spill could occur with smaller concentrations. The 

larger volume may increase the potential for a spill reaching a drinking water resource, albeit at a 

lower concentration. There is the further complication of the hazard of the associated chemicals, 

since a smaller mass of a more hazardous chemical may be of more concern than a larger mass of a 

less hazardous chemical (as discussed in Chapter 9). It is therefore impossible to make a general 

statement without more detail on the spill characteristics, including the hazard, concentration, and 

volume.

Appendix Table C-6 provides mean, median, 5th and 95th percentile mass (kg) estimates for all 

reported chemicals in 100 or more disclosures in the EPA FracFocus 1.0 project database where 

density information was available.

Table 5-5. Fluid and additive composition by maximum mass percent.

Median, 5th and 95th percentile maximum concentration in hydraulic fracturing fluid and in additive (percent by 

mass) for the chemicals identified in the EPA FracFocus 1.0 project database in 10% or more disclosures. See Table 

5-3 for percentage of disclosures and the common additives for which these chemicals are used. 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.

Maximum concentration in

hydraulic fracturing fluid 

(percent by mass)

Maximum concentration in

additive (percent by mass)

EPA-standardized 

chemical name

5th 

Percentile

95th 

Percentile

5th 

Percentile

95th 

CASRN Median Median Percentile

Methanol 67-56-1 0.0092 0.00011 0.12 30 0.44 100

Distillates, petroleum, 

hydrotreated light 64742-47-8 0.025 0.0013 0.35 30 0.70 70

Hydrochloric acid 7647-01-0 0.15 0.0083 1.3 15 2.8 60
Chapter 5 – Chemical Mixing

5-30 

Maximum concentration in

hydraulic fracturing fluid 

(percent by mass)

Maximum concentration in

additive (percent by mass)

EPA-standardized 

chemical name

5th 

Percentile

95th 

Percentile

5th 

Percentile

95th 

CASRN Median Median Percentile

Water 7732-18-5 0.53 0.00065 82 65 5.0 100

Isopropanol 67-63-0 0.0038 0.000020 0.15 20 0.30 100

Ethylene glycol 107-21-1 0.016 0.00027 0.11 30 0.59 60

Peroxydisulfuric acid, 

diammonium salt 7727-54-0 0.0069 0.00010 0.064 100 0.11 100

Sodium hydroxide 1310-73-2 0.0092 0.000040 0.077 10 0.085 52

Guar gum 9000-30-0 0.16 0.0019 0.42 50 1.6 100

Quartz 14808-60-7 0.0033 0.000030 12 2.0 0.10 97

Glutaraldehyde 111-30-8 0.0072 0.00039 0.023 27 0.040 60

Propargyl alcohol 107-19-7 0.00015 0.000010 0.0028 8.0 0.0032 30

Potassium hydroxide 1310-58-3 0.0070 0 0.053 15 0.14 50

Ethanol 64-17-5 0.0034 0.000060 0.098 30 1.0 60

Acetic acid 64-19-7 0.0033 0 0.037 50 1.0 90

Citric acid 77-92-9 0.0027 0.000060 0.017 60 7.0 100

2-Butoxyethanol 111-76-2 0.0047 0 0.14 10 0.29 60

Sodium chloride 7647-14-5 0.0083 0 0.14 30 0.020 50

Solvent naphtha, 

petroleum, heavy arom. 64742-94-5 0.0051 0.000020 0.035 10 0.00052 30

Naphthalene 91-20-3 0.0014 0 0.0055 5.0 0.0023 5.0

2,2-Dibromo-3-

nitrilopropionamide 10222-01-2 0.0018 0.000010 0.022 98 10 100

Phenolic resin 9003-35-4 0.12 0.0046 1.1 5.0 0.80 20

Choline chloride 67-48-1 0.062 0.00068 0.14 75 0.75 80

Methenamine 100-97-0 0.010 0 0.21 1.0 0 2.0

Carbonic acid, 

dipotassium salt 584-08-7 0.039 0 0.15 60 30 60

1,2,4-Trimethylbenzene 95-63-6 0.00067 0 0.0068 1.0 0.010 20
Chapter 5 – Chemical Mixing

5-31 

Maximum concentration in

hydraulic fracturing fluid 

(percent by mass)

Maximum concentration in

additive (percent by mass)

EPA-standardized 

chemical name

5th 

Percentile

95th 

Percentile

5th 

Percentile

95th 

CASRN Median Median Percentile

Quaternary ammonium 

compounds, benzylC12-16-alkyldimethyl, 

chlorides

68424-85-1 0.0019 0 0.0041 7.0 3.0 10

Poly(oxy-1,2-

ethanediyl)-

nonylphenyl-hydroxy 

(mixture)

127087-87-0 0.0025 0.000010 0.0089 5.0 5.0 10

Formic acid 64-18-6 0.0021 0 0.030 60 0.11 98

Sodium chlorite 7758-19-2 0.0040 0.00018 0.037 10 5.0 30

Nonyl phenol 

ethoxylate 9016-45-9 0.0088 0.000030 0.085 10 5.0 54

Tetrakis(hydroxymethyl) 

phosphonium sulfate 55566-30-8 0.011 0.00025 0.065 60 0.029 100

Polyethylene glycol 25322-68-3 0.0035 0.000010 0.038 20 0.0071 70

Ammonium chloride 12125-02-9 0.0025 0.00029 0.022 10 1.5 30

Sodium persulfate 7775-27-1 0.0017 0.000020 0.022 100 100 100

5.5 Chemical Management and Spill Potential

This section provides a description of the primary equipment used in the chemical mixing and well 

injection processes, along with a discussion of the spill vulnerabilities specific to each piece of 

equipment. Equipment breakdown or failure can trigger a spill itself, and it can also lead to a 

suspension of activity and the disconnection and reconnection of various pipes, hoses, and 

containers. Each manipulation of equipment poses additional potential for a spill. The EPA found 

that 31% of chemical spills on or near the well pad related to hydraulic fracturing resulted from 

equipment failure (U.S. EPA, 2015m). When possible, we describe documented spills, associated 

with or attributed to specific pieces of equipment, in text boxes in the relevant subsections. 

Equipment used in hydraulic fracturing operations typically consists of chemical storage trucks, oil 

storage tanks/tanker trucks; a slurry blender; one or more high-pressure, high-volume fracturing 

pumps; the main manifold; surface lines and hoses; and a central control unit (Table 5-6). There are 

many potential sources for leaks and spills in this interconnected system. Furthermore, hydraulic 

fracturing operations are mobile and must be assembled at each well site, and each assembly and 

disassembly presents a potential for spills. 
Chapter 5 – Chemical Mixing

5-32 

Equipment varies in age and technological advancement depending upon service company 

standards and costs associated with purchase and maintenance. Older equipment may have 

experienced wear and tear, which may be a factor in spills caused by equipment failure. New 

equipment may be more automated, potentially reducing opportunities for human error. 

Information detailing the extent of technological and age differences in fracturing equipment across 

sites and operators is limited. 

Table 5-6. Examples of typical hydraulic fracturing equipment and its function.

Equipment Function

Acid transport truck Transports acids to job sites; the truck has separate compartments for 

multiple acids or additives. 

Chemical storage truck Transports chemicals to the site in separate containment units or totes. 

Chemicals are typically stored on and pumped from the chemical storage 

truck.

Base fluid tanks Stores the required volume of base fluid to be used in the hydraulic 

fracturing process.

Proppant storage units Holds proppant and feeds it to the blender via a large conveyor belt.

Blender 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

High-pressure fracturing pumps Pressurizes mixed fluids received from the blender and injected into the well.

Manifold trailer with hoses and 

pipes

Serves as 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.

Fracturing wellhead or frac head Allows fracture equipment to be attached to the well; located at the 

wellhead.

Central control unit or frac van Monitors the hydraulic fracturing job using pressure and rate data supplied 

from around the job site.

While the primary equipment and layout are generally the same across well sites, the type, size, and 

number of pieces of equipment may vary depending on a number of factors (Malone and Ely, 2007): 

• Size and type of the fracture treatment;

o Length of well and number of stages;

o Number of wells drilled per well pad;

o Geographic location;

o Depth below surface;

o Length of the fractures; 
Chapter 5 – Chemical Mixing

5-33 

• Volumes and types of additives, proppants, and fluids used; and 

• Operating procedures of the well operator and service company (e.g., some companies 

require backup systems in case of mechanical failure, while others do not).

Figure 5-6 provides a schematic diagram of a typical layout of hydraulic fracturing equipment. 

Figure 5-6. Typical hydraulic fracturing equipment layout. 

This illustration shows how the various components of a typical hydraulic fracturing site fit together. The 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

This section provides an overview of publicly available information on storage and containment of 

chemicals used in the hydraulic fracturing process. Most public sources provide general 

information on the types and sizes of containment units. While operators maintain a precise 

inventory of volumes of chemicals stored and used for each site, this information is typically not 

made public.

The volumes of each chemical used are based on the size and site-specific characteristics of each 

fracture treatment. Sites often store an excess of the design volume of chemicals for contingency 

purposes, typically 20% to 100% beyond what is necessary (Houston et al., 2009; Malone and Ely, 

2007). See Text Box 5-3 for documented spills from storage units.
Chapter 5 – Chemical Mixing

5-34 

Text Box 5-3. Spills from Storage Units. 

Of the 151 spills of chemicals, additives, or fracturing fluid discussed and evaluated in (U.S. EPA, 2015m) (see 

Text Box 5-10 for more information), 54 spills were from storage units. Storage units include totes or tanks 

used for storing individual chemicals or additives and larger tanks containing hydraulic 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 importance of 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

Base fluids used in hydraulic fracturing are typically stored on-site in large volume tanks. Nonwater-based fluids may be stored in specialized containment units designed to prevent or minimize 

releases. For example, nitrogen and carbon dioxide must be stored in compressed gas or cryogenic 

liquid cylinders, as required by U.S. Department of Transportation (DOT) and OSHA regulations.

Due to the large volume of base fluid storage tanks (about 21,000 gal or 80,000 L) (Halliburton, 

1988), uncontrolled spills could damage other storage units and equipment, which could result in 

additional spills. Fresh water used as a base fluid is generally not a source of concern for spills. 

Reused wastewater, brine, and non-aqueous base fluids have the potential to adversely impact 

drinking water resources in the event of a spill. Chapter 7 discusses reusing hydraulic fracturing 

wastewater as a base fluid and the spill/release potential on-site from pits and impoundments.

5.5.1.2 Additive Storage

Additives are typically stored on-site in the containers in which they were transported and 

delivered. The additive trailer typically consists of a flatbed truck or van enclosure that holds a 

number of chemical totes, described below, and is equipped with metering pumps that feed 

chemicals to the blender. Depending on the size and type of the fracturing operation, there may be 

one or more additive trailers per site (NYSDEC, 2015; ALL Consulting, 2012). While additives 

constitute a relatively small portion of fluids used in a hydraulic fracturing fluid, additive volumes

can range from the tens to tens of thousands of gallons.

The storage totes generally remain on the transportation trailers, but they also may be unloaded 

from the trailers and transferred to alternative storage areas before use. Our investigation did not 

find much information on how often, when, or why these transfers occur. Additional transfers and 

movement can increase the likelihood of a spill. See Text Box 5-4 for a documented spill from an 

additive storage unit. 

Text Box 5-4. Spill from Additive (Crosslinker) Storage Tote. 

On Sept 19, 2009, during a tote transfer in Pennsylvania, a tote of crosslinker fell off a forklift spilling 

approximately 15 – 20 gal (60 – 80 L) onto the well pad. The area was scraped clean with a backhoe, and the 

waste was placed in a lined containment area (PA DEP, 2012, ID# 1845178). 
Chapter 5 – Chemical Mixing

5-35 

The most commonly used chemical totes are 200 – 375 gal (760 – 1,420 L) capacity polyethylene 

containers that may be reinforced with steel or aluminum mesh (NYSDEC, 2015). Metal containers 

may also be used. The totes are typically equipped with bottom release ports, which enable direct 

feed of the additives to the blending equipment (NYSDEC, 2015). Spills may occur if lines are 

improperly connected to these ports or if the connection equipment is faulty. 

Figure 5-7. Metal and high-density polyethylene (HDPE) additive units. 

The image on the left depicts metal totes (industry source). The image on the right depicts plastic totes. Source:

NYSDEC (2011). 

Certain additives require specialized containment units with added spill prevention measures. For 

example, additives containing methanol may be subject to federal safety standards, and industry 

has developed guidance on methanol’s safe storage and handling (Methanol Institute, 2013). 

Dry additives are typically transported and stored on flatbed trucks in 50 or 55 lb (23 or 25 kg) 

bags, which are set on pallets containing 40 bags each (NYSDEC, 2015; UWS, 2008; Halliburton, 

1988). Proppants are stored on-site in large tanks or bins with typical capacities of 350,000 to 

450,000 lb (150,000 to 200,000 kg) (ALL Consulting, 2012; BJ Services Company, 2009; 

Halliburton, 1988). 

5.5.1.3 Acid Storage

Acids are generally stored on-site in the containment units in which they are transported and 

delivered. A typical acid transport truck holds up to 5,000 gal (19,000 L) of acid and can have

multiple compartments to hold different kinds of acid (Arthur et al., 2009b). Acids such as 

hydrochloric acid and formic acid are corrosive and can be extremely hazardous in concentrated 

form. Therefore, acid transport trailers and fracture tanks must be lined with chemical-resistant 

coating designed to prevent leakage and must meet applicable DOT regulatory standards (pursuant 

to 40 Code of Federal Regulations (CFR) 173) designed to prevent or minimize spills. 

Acid fracture treatments may use thousands of gallons of acid per treatment (Spellman, 2012). 

Given the large volumes used, failure of containment vessels during storage or failure of 

connections and hoses during pumping could result in high-volume acid spills. Details of a 

documented acid spill are presented in Text Box 5-5.
Chapter 5 – Chemical Mixing

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Text Box 5-5. Spill of Acid from Storage Container.

In July 2014, in Oklahoma, 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, 2014). There is no information on how much leached into soils or if the spill 

reached drinking water resources. 

5.5.1.4 Gel Storage

Gels can be added to hydraulic fracturing fluid using either batch or continuous (also called “on-thefly”) mixing systems. Gelling agents and gel slurries are stored differently on-site and can pose 

different potential spill scenarios depending on whether the site is using batch or continuous 

mixing processes (BJ Services Company, 2009). 

In a typical batch mixing process, powdered gelling agents and related additives (e.g., buffers, 

surfactants, biocides) are mixed on-site with base fluid water and proppant in large tanks, typically 

20,000 gal (80,000 L)(BJ Services Company, 2009; Halliburton, 1988). The number of gel slurry 

tanks used varies based on site-specific conditions and the size of the fracture job. These tanks can

be subject to leaks or overflow during the batch mixing process and during storage prior to 

injection. One of the disadvantages of batch mixing is the need for multiple suction hoses to draw 

pre-gelled fluids from storage tanks into the blender, if used, which can increase the potential for 

spills. Yeager and Bailey (2013) state that a drawback of batch mixing is the “fluid spillage and 

location mess encountered when pre-mixing tanks,” suggesting that small spills are not uncommon 

during batch mixing. Details of a documented gel slurry spill are presented in Text Box 5-6. Details 

of a documented gel slurry spill are presented in Text Box 5-6. 

Text Box 5-6. Spill of Gel Slurry during Mixing.

On April 9, 2010, in Louisiana, 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

(LDEQ, 2013). 

In continuous mixing operations, powdered gels are typically replaced with liquid gel concentrates

(Allen, 2013; BJ Services Company, 2009). Operators prepare dilute gelling agents as needed using 

specialized hydration units (BJ Services Company, 2009). Liquid gel concentrates may be stored onsite in single-purpose tanker trucks (Harms and Yeager, 1987) but are more often stored in 

specialized mixing and hydration units (Ayala et al., 2006). Continuous mixing requires less 

preparation than batch mixing but typically requires more equipment (BJ Services Company, 2009; 

Browne and Lukocs, 1999). This can increase the possibility for spills resulting from equipment 

malfunctions or human error.
Chapter 5 – Chemical Mixing

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5.5.2 Hoses and Lines

High- and low-pressure hoses and lines are used to transfer hydraulic fracturing fluids from storage 

units to specialized mixing and pumping equipment and ultimately to the wellhead. A discussion of 

the different types of hoses and lines and possible points of failure is provided below. Figure 5-8

shows an example of hoses and lines at a hydraulic fracturing site. 

Figure 5-8. Hoses and lines at a site in Arkansas.

Photo credit: Christopher Knightes (U.S. EPA).

Suction pumps and hoses move large volumes of base fluid to the blender. Incomplete or damaged 

seals in inlet or outlet connections can cause fluid leaks at the connection points. Improperly fitted 

seals also severely limit or eliminate suction lift, which can impair the suction pump and increase 

spill potential. Suction hoses themselves are susceptible to leaks due to wear and tear. Equipment 

providers recommend hoses be closely inspected to ensure they are in good operating condition 

prior to use (Upstream Pumping, 2015; BJ Services Company, 2009; Malone and Ely, 2007). 

Discharge hoses transfer additives from containment vessels or totes to the blender. Given the 

potential for concentrated chemicals to spill during transfer from storage totes to the blender, it is 

particularly important that these hoses are in good condition and that connector seals or washers 
Chapter 5 – Chemical Mixing

5-38 

fit properly and are undamaged. Discharge hoses are also used to carry fracturing fluid pumped 

from the blender via the low-pressure manifold to the high-pressure pumps. Proppant-heavy fluids 

are pumped through discharge hoses at relatively low rates. If a sufficient flow rate is not 

maintained, proppant may settle out, damaging pumps and creating a potential for spills and leaks

(Upstream Pumping, 2015; BJ Services Company, 2009; Malone and Ely, 2007). 

High-pressure flow lines convey pressurized fluids from the high-pressure pumps into the highpressure manifold and from the manifold into the wellbore. High-pressure flow lines are subject to 

erosion caused by the high-velocity movement of abrasive, proppant-laden fluid. Curved sections of 

flow lines (e.g., swivel joints) where abrasive fluids are forced to turn corners are particularly 

subject to erosion and are more likely to develop stress cracks or other defects that can result in a 

leak or spill. Safety restraints are typically used to prevent movement of flow lines such as in the 

event of failure and to help control spills. High-pressure flow lines are pressure-tested to detect 

fatigue or stress cracks prior to the fracturing treatment (OSHA, 2015; BJ Services Company, 2009; 

Arthur et al., 2008; Malone and Ely, 2007; Halliburton, 1988). 

Nineteen spills of chemicals or fracturing fluids associated with leaks from hoses or lines had a total 

spill volume of 12,756 gal (48,287 L), with a median volume of 420 gal (1,600 L) (U.S. EPA, 2015m). 

5.5.3 Blender

The blender is the central piece of equipment used to create the fracturing fluid for injection. It 

moves, meters, and mixes precise amounts of the base fluid, additives, and proppant and pumps the 

mixed slurry to high-pressure pumping equipment (BJ Services Company, 2009; Malone and Ely, 

2007; Halliburton, 1988) (Figure 5-6). A typical blender consists of a centrifugal suction pump for 

pulling base fluid, one or more chemical metering pumps to apportion the additives, one or more 

proportioners to measure and feed proppant, and a central agitator tank where fluid components 

are mixed together. 

The blending process is monitored to ensure that a uniform mixture is maintained regardless of 

injection rates and volumes. Excessive or reduced rates of flow during treatment can cause the 

blender to malfunction or to shut down, which can result in spills (Malone and Ely, 2007; 

Halliburton, 1988). For aqueous hydraulic fracturing fluid blends, spills that occur downstream of 

the blender will be a dilute mixture (less than or equal to 2%) of chemicals. Details of a spill from a 

blender are presented in Text Box 5-7. 

Text Box 5-7. Spill of Hydraulic Fracturing Fluid from Blender.

In May 2006, a blender malfunctioned during a fracture job in Oklahoma. Approximately 294 gal (1,110 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 (OCC, 2013, ID#137000). 
Chapter 5 – Chemical Mixing

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5.5.4 Manifold

A trailer-mounted manifold and pump system functions as a central transfer station for all fluids 

used in the hydraulic fracturing operation. The manifold is a collection of low- and high-pressure 

pipes equipped with multiple fittings for connector hoses. Fluids are pumped from the blender 

through the low-pressure manifold hoses, which distribute fluids to high-pressure pump trucks. 

Pressurized slurry is sent from the pump trucks through high-pressure manifold lines and into 

additional high pressure lines that lead to the wellhead (Malone and Ely, 2007). 

Manifold and pump system components require varying amounts of manual assembly and undergo

varying amounts of pre-testing (Malone and Ely, 2007). Improperly tested parts may be more likely 

to break or lose functionality, leading to a spill. In manifolds requiring more manual assembly, there 

may be more opportunities for human error. 

5.5.5 High-Pressure Fracturing Pumps

High-pressure fracturing pumps take the fracturing fluid mixture from the blender, pressurize it, 

and propel it down the well. Typically, multiple high-pressure, high-volume fracturing pumps are 

needed for hydraulic fracturing (Upstream Pumping, 2015). Such pumps come in a variety of sizes.

Bigger pumps move greater volumes of fluid at higher pressures; therefore, spills from these pumps 

can be larger. Smaller pumps can require more operators and more maintenance (BJ Services 

Company, 2009), and therefore have the potential for an increased frequency of spills. 

The “fluid ends” of hydraulic fracturing pumps are the pump components through which fluids are 

moved and pressurized. Pump fluid ends must withstand high pressure and move a large volume of 

abrasive fluid high in solids content. These pumps have multiple parts (e.g., seals, valves, seats and 

springs, plungers, stay rods, studs) that can wear out under the stress of high-pressure pumping

(Upstream Pumping, 2015). Given the sustained pressures involved, careful maintenance of fluid 

ends is necessary to prevent equipment failure (Upstream Pumping, 2015; API, 2011). Details of a 

documented spill from a fracture pump are presented in Text Box 5-8. 

Text Box 5-8. Spill of Fluid from Fracture Pump. 

On December 19, 2011, in Arkansas, 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 neutralized and taken to a landfill at the end of the job, after removal of the equipment (Arkansas 

DEQ, 2012, ID#063012). 

5.5.6 Surface Wellhead for Fracture Stimulation

A wellhead assembly, often referred to as a frac head or frac stack, is temporarily installed on the 

wellhead during the fracture treatment. The frac head assembly allows high volumes of highpressure proppant-laden fluid to be injected into the formation (OSHA, 2015; Halliburton, 2014; 

Stinger Wellhead Protection, 2010). The temporary frac head is equipped with specialized isolation 

tools so that the wellhead is protected from the effects of pressure and abrasion. 
Chapter 5 – Chemical Mixing

5-40 

Figure 5-9. Multiple fracture heads. 

Source: DOE/NETL.

As with all components of hydraulic fracturing operations, repeated and prolonged stress from 

highly pressurized, abrasive fluids may lead to equipment damage. The presence of minute holes or 

cracks in the frac head may result in leaks when pressurized fluids are pumped. In addition, surface 

blowouts or uncontrolled fluid releases may occur at the frac head because of valve failure or 

failure of other components of the assembly.1 Details of a documented frac head failure are 

presented in Text Box 5-9. 

Text Box 5-9. Spill from Frac Head Failure. 

On March 2, 2011, in Colorado, a frac head failed during fracturing operations. Approximately 8,400 gal 

(32,000 L) of slickwater fracturing fluid leaked. The majority of the spill was contained on-site, though a small 

amount ran off into a nearby cornrow. There were 5,460 gal (20,700 L) of the fluid recovered, and saturated 

soils were scraped and stockpiled on the well pad. There was a net loss of 2,940 gal (11,100 L) (COGCC, 2012, 

ID#2524586). 

 

1 A well blowout is when there is uncontrolled flow of fluids out of a well. 
Chapter 5 – Chemical Mixing

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5.6 Overview of Chemical Spills Data

Spills of hydraulic fracturing fluids have occurred across the country and have affected the quality 

of drinking water resources (U.S. EPA, 2015m; Brantley et al., 2014; COGCC, 2014; Gradient, 2013).1

Spills may infiltrate drinking water resources by reaching surface water or by leaching into the 

groundwater. Potential impacts depend upon a variety of factors including the chemical spilled, 

environmental conditions, and actions taken in response to the spill. 

5.6.1 EPA Analysis of Spills Associated with Hydraulic Fracturing

The EPA used data gathered from state and industry sources to characterize hydraulic fracturingrelated spills between January 2006 and April 2012 (2015m) (see Text Box 5-10 for additional 

information). In this study, the sources had data on over 36,000 spills. Of these spills, the EPA 

identified 457 spills that occurred on or near the well pad and definitively related to hydraulic 

fracturing. Of these 457 spills, 151 were related to the chemical mixing process – spills that 

consisted of chemicals, additives, or fracturing fluids. Information in the spill reports included: spill 

causes (e.g., human error, equipment failure), sources (e.g., storage tank, hose or line), volumes, and 

environmental receptors. Spill reports contain little information on chemical-specific spill 

composition. Spilled fluids were often described by their additive type (e.g., acids, biocides, friction 

reducers, cross-linkers, gels,) or as a blended hydraulic fracturing fluid. Specific chemicals 

mentioned in spill reports included hydrochloric acid and potassium chloride.

Text Box 5-10. EPA Review of State and Industry Spill Data: Characterization of Hydraulic 

Fracturing-Related Spills. 

As part of the EPA’s Study of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water 

Resources, the EPA published the report titled Review of State and Industry Spill Data: Characterization of 

Hydraulic Fracturing-Related Spills (U.S. EPA, 2015m). In this document, hereafter referred to as the EPA 

spills report, the EPA used data gathered from 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 

defined 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 groundwater 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. 

Data on spills that occurred between January 2006 and April 2012 were obtained from nine state agencies

with online spill databases or other data sources, nine hydraulic fracturing service companies, and nine oil 

and gas production well operators. The data sources used in this study contained over 36,000 spills. The EPA 

searched each spill report for keywords related to hydraulic fracturing (e.g., frac, glycol, flowback). Spill 

records from approximately 12,000 spills (33 percent of the total number of spills reviewed) contained 

insufficient information to determine whether the event was related to hydraulic fracturing. 

(Text Box 5-10 is continued on the following page.)

 

1 In this assessment, a spill is considered to be any release of fluids. Spills can result from accidents, fluid management 

practices, or illegal dumping.
Chapter 5 – Chemical Mixing

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Text Box 5-10 (continued). EPA Review of State and Industry Spill Data: Characterization of 

Hydraulic Fracturing-Related Spills.

Of the spills with sufficient information, the EPA identified approximately 24,000 spills (66%) as not related 

to hydraulic fracturing on or near the well pad. The remaining 457 spills (approximately 1%) occurred on or 

near the well pad and were definitively related to hydraulic fracturing. These 457 spills occurred in 11 

different states over six years (January 2006 to April 2012). Of these 457 spills, 151 spills were chemical 

mixing-related and included spills of chemicals, additives, and hydraulic fracturing fluid, and 225 releases 

were of produced water (Chapter 7). 

The EPA categorized spills according to the following causes: equipment failure, human error, 

failure of container integrity, other (e.g., well communication, weather, vandalism), and unknown.1

Figure 5-10 presents the percent distribution of causes of hydraulic fracturing-related spills and for 

spills associated specifically with chemicals or fracturing fluid. The distributions for causes of 

hydraulic fracturing- and chemical mixing-related spills are similar.2

Spills in the EPA spills report were also categorized by the following sources: storage, equipment, 

well or wellhead, hose or line, and unknown. Figure 5-11 presents the percent distribution for all 

hydraulic fracturing- and chemical mixing-related spills associated with each source. 

Figure 5-10. Percent distribution of the causes of spills. 

Percent distribution by spill type for (a) 457 hydraulic fracturing-related spills (all spills) and (b) 151 chemical 

mixing-related spills. Data from U.S. EPA (2015m). Legend shows categories in clockwise order, from the top left of 

each pie chart.

 

1 Well communication is when hydraulic fracturing fluids or displaced subsurface fluids move through newly created 

fractures into an offset well or its fracture network (See Section 6.3.2.3 for more details),

2 Hydraulic fracturing-related spills are spills that occur at any phase within the hydraulic fracturing water cycle. These 

include chemicals, additives, hydraulic fracturing fluids (chemical mixing phase); produced water; and wastewater.
Chapter 5 – Chemical Mixing

5-43 

Figure 5-11. Percent distribution of the sources of spills. 

Percent distribution of spill source of (a) 457 hydraulic fracturing-related spills (all spills) and (b) 151 chemical 

mixing-related spills. Data from U.S. EPA (2015m). Legend shows categories in clockwise order, from the top left of 

each pie chart.

Figure 5-12 presents the distribution of the number of spills for different volumes for hydraulic 

fracturing- and chemical mixing-related spills. The spills associated with chemical mixing ranged in 

volume from 5 to 19,320 gal (19 to 73,130 L), with a median volume of 420 gal (1,600 L). The 

source of largest spills was storage containers, which released approximately 83,000 gal (314,000 

L) of spilled fluid (Figure 5-13b). Spills from wells or wellheads are often associated with high spill 

volumes. There were no reported chemical mixing-related spills greater than 100,000 gal (380,000 

L) (Figure 5-15b).

Figure 5-12. Distribution of the number of spills for different ranges of spill volumes. 

Number of spills due to Hydraulic Fracturing related activities and distribution of spill volumes for (a) 457 hydraulic 

fracturing-related spills (all spills) and (b) 151 chemical mixing-related spills. A value of 0% means that there were 

no spills in that category. Data from U.S. EPA (2015m). 
Chapter 5 – Chemical Mixing

5-44 

Figure 5-13 presents the total volume of spills for different sources for all hydraulic fracturingrelated activity and those associated with chemicals and fracturing fluid. The reported total volume

of 125 of 151 chemical or hydraulic fracturing fluid spills was approximately 184,000 gal

(697,000 L). The volume was unknown for 26 of these spills. 

Figure 5-13. Total volume of fluids spilled from different sources. 

Total volume of fluids spilled for (a) 457 hydraulic fracturing-related spills (all spills) and (b) 151 chemical mixingrelated spills. Data from U.S. EPA (2015m).

Figure 5-14 presents the number of spills that reached environmental receptors, by receptor type, 

for all hydraulic fracturing-related activity (Figure 5-14a) and those associated with chemicals and 

fracturing fluid (Figure 5-14b). Environmental receptors (i.e., surface water, groundwater, soil)

were identified in 101 of the 151 chemical mixing-related spills, or 67% of all chemical and 

fracturing fluid spills in the EPA’s analysis (U.S. EPA, 2015m). Soil was by far the dominant 

environmental receptor, with 97 spills reaching soil; reported spill volumes ranged from 5 gal to 

8,300 gal (19 L to 31,000 L). Thirteen spill reports indicated that the spilled fluid had reached 

surface water; reported spill volumes ranged from 28 gal to 7,350 gal (105 L to 27,800 L). Nine spill 

reports identified both soil and surface water as a receptor; spill volumes ranged from 28 gal to 

2,856 gal (106 L to 10,800 L). Groundwater was not identified as a receptor from spills of chemicals 

or hydraulic fracturing fluid in any of the spill reports. Due to the lack of observations, it is often 

unclear if there was impact on groundwater. Movement through the subsurface is generally slow.1

It may take years for a spilled fluid to reach groundwater or to reach a drinking water well. Thus, 

even if there is a pre-drilling characterization of groundwater chemistry in private/public wells, the 

time period of transport to actually detect a release at these private/public wells for contaminants 

that are transported at the rates of groundwater flow (see Section 5.8 for discussion on fate and 

transport of spilled chemicals).

 

1 For example, a groundwater flow rate of 1 foot per day (not uncommon) would mean it could take approximately 1,000 

days (~3 years) to travel 1,000 ft (305 m) from the well pad. Likewise, for a groundwater travel rate of 0.1 ft (0.03m) per 

day, impact would not be observed for at least 10,000 days (~27 years). For a travel rate of 10 ft (3 m) per day, the time 

for impact would be at least 100 days (~0.3 years). 
Chapter 5 – Chemical Mixing

5-45 

Figure 5-14. Number of spills by environmental receptor. 

Number of hydraulic fracturing-related spills and chemical mixing-related spills that reported whether an 

environmental receptor was reached for (a) 457 hydraulic fracturing-related spills (all spills) and (b) 151 chemical 

mixing related spills. “Yes” means that the spill was reported to reach this receptor. “Unknown” refers to hydraulic 

fracturing related spill events for which environmental receptors were specified as unknown or not identified 

(positively or negatively). “No” means the spill was reported to not meet this receptor. Data from U.S. EPA 

(2015m).

Storage units were the predominant sources of spills that reached an environmental receptor. Six 

spills from storage containers reached a surface water receptor. Thirty-eight of the spills from 

storage units reached a soil receptor. If a spill was confined to a lined well pad, for example, it might

not have reached the soil, but most incident reports did not include whether the well pad was lined 

or unlined. Regarding spills of hydraulic fluids and chemicals from storage containers, 16 spills 

were due to failure of container integrity, which includes holes and cracks in containers, and 

overflowing containers as a result of human error or equipment malfunctions.

5.6.2 Estimated Spill Rate and Other Spill Reports and Data

The rate of reported spills during the hydraulic fracturing water cycle is estimated to range from 

0.4 to 12.2 reported spills for every 100 wells, based on spills data from Brantley et al. (2014), 

Gradient (2013), Rahm et al. (2015), U.S. EPA (2013a), and North Dakota Department of Health 

(2015) (Appendix E) with a median rate of 2.6 reported spills for every 100 wells. (See Appendix 

Section C.4 and Appendix Table C-8 for details.) The estimated rates provide an approximate 

estimate of the potential frequency of the number of spills at a site. It is uncertain how 

representative these rates are of national spill rates or rates in other states. These numbers are not 

specific to the chemical mixing stage.

There are an estimated 2.6 reported spills of injected fluids and chemicals per 100 wells 

hydraulically fractured in North Dakota, based on an analysis of the North Dakota spills database 

for 2015, separate from the EPA spills report. The median spill volume of injection fluid was 1750 

gal (6620 L), with a range of 2.9 to 17,600 gal (11 to 66,600 L). The median spill volume of injection 

chemical was 44 gal (167 L), with a range of 2.1 to 126 gal (7.9 to 477 L) (see Appendix E for more 

information). 
Chapter 5 – Chemical Mixing

5-46 

A study of spills reported to the Colorado Oil and Gas Conservation Commission identified 125 

spills during well stimulation (i.e., a part of the life of an oil and gas well that often, but not always, 

includes hydraulic fracturing) between January 2010 and August 2013. Of these spills, 51% were 

caused by human error and 46% were due to equipment failure (COGCC, 2014). 

Considine et al. (2012) identified spills related to oil and gas development in the Marcellus Shale 

that occurred between January 2008 and August 2011 from Notices of Violations issued by the 

Pennsylvania Department of Environmental Protection. The authors identified spills greater than 

400 gal (1,500 L) and spills less than 400 gal (1,500 L). Among these spills, spilled fluids included 

hydrochloric acid, gel friction reducer, and blended hydraulic fracturing fluid. Brantley et al. (2014)

identified fewer than 10 instances of spills of additives and/or hydraulic fracturing fluids greater 

than 400 gal (1,500 L) that reached surface waters in Pennsylvania between January 2008 and 

September 2013. Reported spill volumes, among these spills, ranged from 3,400 gal to 227,000 gal

(13,000 L to 859,000 L). 

Surface spills related to hydraulic fracturing activities are not well documented in the scientific 

literature. There is some evidence of spills and impacts on environmental media (e.g., U.S. EPA, 

2015i; Brantley et al., 2014; Gross et al., 2013; Papoulias and Velasco, 2013). Papoulias and Velasco 

(2013) stated that fluid overflowed a retention pit into surface water and likely contributed to the 

distress and deaths of threatened blackside dace fish in Kentucky. A variety of chemicals entered 

the creek and significantly reduced the stream’s pH and increased stream conductivity. Using data 

from post-spill sampling reports in Colorado, Gross et al. (2013) identified concentrations of 

benzene, toluene, ethylbenzene, and xylene (BTEX) in groundwater samples. They attributed this to 

numerous hydraulic fracturing-related spills, although not necessarily specifically related to the 

chemical mixing process. This work, however, demonstrate that surface spills impacted 

groundwater, with a frequency of < 0.5% of active wells. Drollette et al. (2015) reported that 

organic compounds detected in shallow aquifers were consistent with surface spills, and that diesel 

range compounds had elevated concentrations compared to gasoline range compounds, further 

suggesting evidence of feasible groundwater impact. 

5.7 Spill Prevention, Containment, and Mitigation

Spill prevention, containment, and mitigation affect the frequency and severity of the impacts of 

spills. Several factors influence spill prevention, containment, and mitigation, including federal, 

state, and local regulations and company practices. State regulations governing spill prevention, 

containment, and mitigation at hydraulic fracturing facilities vary in scope and stringency (Powell, 

2013; GWPC, 2009). Employee training and equipment maintenance are also factors in effective 

spill prevention, containment, and mitigation. Analysis of these factors was outside the scope of this 

assessment. 

The province of New Brunswick, Canada released rules for industry on responsible environmental 

management of oil and natural gas activities (GNB, 2013). Hydraulic fracturing service companies 

themselves may develop and implement spill prevention and containment procedures. It was 

beyond the scope of this assessment to evaluate the efficacy of these practices or the extent to 

which they are implemented.
Chapter 5 – Chemical Mixing

5-47 

Spill containment systems include primary, secondary, and emergency containment systems. 

Primary containment systems are the storage units, such as tanks or totes, in which fluids are 

intentionally kept. Secondary containment systems, such as liners and berms installed during site 

set-up, are intended to contain spilled fluids until they can be cleaned up. Emergency containment 

systems, such as berms, dikes, and booms, can be implemented temporarily in response to a spill. 

The EPA investigated spill containment and mitigation measures in an analysis of spills related to 

hydraulic fracturing activities (U.S. EPA, 2015m). Of the approximately 25% of reports that 

included information on containment, the most common types of containment systems referenced 

in the hydraulic fracturing-related spill records included berms, booms, dikes, liners, and pits, 

though many of the spill reports did not indicate specific containment measures. Some spills were 

reported to breach the secondary containment systems. Breaches of berms and dikes were most 

commonly reported. 

In cases where secondary containment systems were not present or were inadequate, operators 

sometimes built emergency containment systems. The most common were berms, dikes, and 

booms, but there were also instances where ditches, pits, or absorbent materials were used to 

contain the spilled fluid. Absorbent materials were generally used when small volumes (10 – 200 

gal or 40 – 800 L) of additives or chemicals were spilled (U.S. EPA, 2015m). There was not enough 

information to detail the use of emergency containment systems or their effectiveness.

Remediation is the action taken to clean up a spill and its affected environmental media. The most 

commonly reported remediation activity, mentioned in approximately half of the hydraulic 

fracturing-related spill records evaluated by the EPA, was removal of spilled fluid and/or affected 

media, typically soil. Other remediation methods reported in U.S. EPA (2015m) included the use of 

absorbent material, vacuum trucks, flushing the affected area with water, and neutralizing the 

spilled material. Removal activities were found to occur in various combinations. For example, a 

spill of approximately 4,200 gal (16,000 L) of acid was cleaned up by first spreading soda ash to 

neutralize the acid and then removing the affected soil (U.S. EPA, 2015m). 

5.8 Fate and Transport of Spilled Chemicals

The fate and transport of chemicals in the environment is complex. Due to the complexities of the 

processes and the site-specific and chemical-specific nature of spills, it is difficult to develop a full 

assessment of their fate and transport. The potential for hydraulic fracturing chemicals and fluids to 

reach drinking water resources is further complicated by the fact that these chemicals are typically 

present as mixtures, and unlike many organic contaminant mixtures (e.g., gasoline, diesels, PCBs, 

PAHs), hydraulic fracturing fluid chemicals are present as complex mixtures of chemicals covering a 

range of chemical classes with varying properties, often in aqueous solutions. 

In this section, we provide a general overview of fate and transport of hydraulic fracturing-related 

chemicals spilled in the environment to give the reader a general understanding of the potential 

pathways and processes with which these chemicals can impact drinking water resources (Figure 

5-15). We also include a discussion of the physicochemical properties of the organic chemicals used 
Chapter 5 – Chemical Mixing

5-48 

in hydraulic fracturing fluids, because these properties directly affect the transport of chemicals in 

the environment. This presentation is not meant to be exhaustive. 

A chemical spill has the potential to migrate to and have an impact on drinking water resources.

Once spilled, there are different paths that chemicals can travel and different processes they can 

undergo. Chemicals can react and transform into other chemicals, volatilize, travel to surface water, 

leach into and partition to soils, and/or reach groundwater. The potential path and the severity of 

the impact of a spill depend on different factors, including site conditions; the length of the path to a 

drinking water resource; the type and characteristics of the drinking water resource (stream, lake, 

aquifer); environmental conditions; climate; weather; chemical properties, constituents, and 

concentrations; and the volume of the release. The point in the chemical mixing stage where the 

spill occurs affects potential impact. If the spill occurs before chemicals are mixed into the base 

fluid, the chemicals will be in a more concentrated form. If the hydraulic fracturing fluid spills, then 

the chemicals will be diluted by the base fluid and can feasibly be present in lower concentrations. 

There can also be effects on persistence and mobility due to interactions among the chemicals 

present. The total mass of spilled chemical can therefore be dependent on what stage in the process 

a spill occurs.

Figure 5-15. Fate and transport schematic for a spilled hydraulic fracturing fluid. 

Schematic shows the potential paths and governing processes by which spilled chemicals can lead to potential 

impacts on drinking water resources.
Chapter 5 – Chemical Mixing

5-49 

For inorganic chemicals, the properties and processes governing fate and transport depend on pH, 

oxidation state, presence of iron oxides, soil organic matter, cation exchange capacity, and major ion 

chemistry (U.S. EPA, 1996).1 Transport of these chemicals into groundwater depends on the nature 

of groundwater flow and flow through the unsaturated zone above the water table.2 Potential 

transformations of inorganic chemicals differ from those of organic chemicals. Some inorganic 

anions (i.e., nitrate, chloride, and bromide) move with their carrier liquid and are affected mostly by 

physical transport mechanisms. For many inorganic chemicals, transport is driven by the physical 

flow processes (advection and dispersion), sorption, and precipitation. The relative role of each of 

these depends on both chemical and environmental characteristics.3,4

Determining the fate and transport of organic chemicals and mixtures is a complex problem, 

because of the many processes and different environmental media (air, soil, water). Unlike 

inorganic chemicals, organic chemicals degrade, which can affect their movement and potential 

impact. Schwarzenbach et al. (2002) formalized a general framework for organic chemical 

transport, where transport and transformation depend on both the nature of the chemical and the 

properties of the environment. The fate and transport of organic chemicals in soils has been 

presented in the literature (e.g., Bouchard et al., 2011; Rivett et al., 2011; Abriola and Pinder, 1985a, 

b) and in textbooks (e.g., Domenico and Schwartz, 1997; Schnoor, 1996; Freeze and Cherry, 1979b). 

5.8.1 Potential Paths 

Chemicals and hydraulic fracturing fluids that are released into the environment may travel along 

different potential paths, as detailed in Figure 5-15. Liquids can flow overland to nearby surface 

water or infiltrate the subsurface, where they may eventually reach the underlying groundwater or 

travel laterally to reach surface water. Movement can occur quickly or be delayed and have a later 

or longer-term impact. Surface and groundwater gain or lose flow to each other (Chapter 2), and 

can transport chemicals in the process. A dry chemical (e.g., gelling agents, biocides, friction 

reducers) released to the environment can remain where it is spilled. Any spill that is not removed 

could act as a long-term source of contamination. Wind could cause the chemical to disperse and 

rain could mobilize soluble chemicals. Dissolved chemicals can infiltrate into soil or flow overland. 

Insoluble chemicals and those sorbed to soil particles could be mobilized by rain events via runoff 

and erosion. 

5.8.1.1 Movement across the Land Surface

In low permeability soils, there may be little infiltration and greater overland flow. Higher 

permeability soils will allow fluid to penetrate into the soil layer. In either case, some of the 

 

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.

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.
Chapter 5 – Chemical Mixing

5-50 

chemicals in the fluid can sorb to the soil particles and the vegetation, and then these chemicals can 

be mobilized during precipitation, runoff, or erosion. As precipitation percolates through the soil, it 

can dissolve stored chemicals, which can then migrate toward groundwater. The type of release is 

also important. If the spill is a slow leak, then the liquid may pond and the affected area will expand 

slowly with greater potential for infiltration. If a more rapid release occurs, like a blowout or tank 

failure, then momentum can result in greater overland movement and less soil infiltration during 

the event, with greater potential to reach a nearby surface water. 

5.8.1.2 Movement through the Subsurface 

The unsaturated and saturated zones are the two zones of soils below the ground surface. 

Movement through the unsaturated zone is driven by the depth of ponding of the spilled fluid, 

gravity, and capillary properties of the subsurface.1 In fractured rock or highly permeable soils, 

fluids can move quickly through the subsurface. In low permeability soil, the movement of the fluid 

may be slower. However, the presence of preferential pathways (e.g., fractures, heterogeneities, 

root holes, and burrows) can result in faster movement than the overall permeability would 

suggest. 

As chemicals pass through the subsurface, some can sorb to soil or remain in the open spaces 

between soil particles, effectively slowing their movement. Chemicals can be mobilized during 

future precipitation events, resulting in infiltration towards groundwater or movement through the 

unsaturated zone towards surface water. 

Fluids that move through the subsurface into the saturated zone will move in the direction of the 

flowing groundwater. Generally, fluids travel farther in systems with high groundwater flow rates 

and high recharge (e.g., sandy aquifers in humid climates) than in systems with low flow and low 

recharge. Chemicals can sorb to suspended soil particles, complex with naturally occurring 

chemicals (e.g., dissolved organic carbon), or associate with colloids and be transported with the 

flowing water.2 These mechanisms can mobilize sparingly soluble chemicals that would otherwise 

be immobile. 

5.8.2 Physicochemical Properties of Organic Hydraulic Fracturing Chemicals

Three physicochemical properties are useful to describe the movement of organic chemicals in the 

environment: (1) Kow, the octanol-water partition coefficient, (2) the aqueous solubility, and (3) the 

Henry’s law constant.3 These properties describe whether a chemical will sorb to soil and organic 

 

1 Capillarity occurs because of the forces of attraction of water molecules to themselves (cohesion) and to other solid 

substances such as soils (adhesion).

2 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 solubilizing the other.

3 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.
Chapter 5 – Chemical Mixing

5-51 

matter or stay in water (Kow), how much of a chemical may dissolve in water (aqueous solubility), 

and whether a chemical will tend to remain in the water or volatilize (Henry’s law constant).1 

The Kow measures the relative hydrophobicity (chemicals that prefer to be in oil, log Kow >0) and 

hydrophilicity (chemicals that prefer to be in water, log Kow <0) of a chemical. Aqueous solubility is 

the maximum amount of a chemical that will dissolve in water in the presence of a pure chemical; 

solubility generally serves as an upper bound on possible concentrations. The Henry’s law constant 

is the ratio of the concentration of a chemical in air (or vapor pressure) to the concentration of that 

chemical in water. 

Estimates and measured values for physicochemical properties were obtained by using the 

Estimation Program Interface (EPI) Suite 4.1, as described in Appendix C.2 Of the 1,084 chemicals

the EPA listed as used in hydraulic fracturing (Appendix H), EPI SuiteTM has estimated properties for 

455 organic chemicals (42% of all chemicals) with structures that are considered suitably 

representative of the substance to compute properties within the constraints of EPI SuiteTM 

software. Only uniquely defined organic desalted structures were submitted for property 

calculation. Figure 5-16 presents histograms of all 455 of the organic chemicals, sorted by four 

physicochemical parameters: measured log Kow (n = 195), estimated log Kow (n=455), estimated log

of the aqueous solubility (n = 455), and estimated log of Henry’s law constant (at 77°F or 25°C, 

n = 449). Property estimation methods are limited in their ability to predict physicochemical 

properties. Chemicals that are different than the chemicals used to develop the estimation 

techniques may have more error associated with their predictions. These figures enable 

comparison of physicochemical properties across the organic chemicals for which we have values. 

These figures show how the physicochemical properties are distributed and which chemicals have 

higher values compared to others with lower values. Limitations in knowing what chemicals are 

present (e.g., CBI) further hinders our ability to know the physicochemical properties of these 

chemicals and their potential to move through the environment and impact drinking water 

resources. These estimates are solely for the organic chemicals for which EPI SuiteTM could be used. 

This does not provide information on the 258 inorganic chemicals or the 361 organic mixtures or 

polymers. This limits our ability to make a full assessment on the physicochemical properties of all 

chemicals, yet provides insight into the properties of the organic chemicals used.

 

1 We present the physicochemical parameter values using log10 because of the wide range of values that these parameters 

cover.

2 EPI SuiteTM, version 4.1, http://www.epa.gov/opptintr/exposure/pubs/episuite.htm (U.S. EPA, 2012c). The EPI 

(Estimation Programs Interface) SuiteTM 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 SuiteTM provides estimates of physicochemical properties for organic chemicals and has a database of measured values 

for physicochemical properties when available. EPI SuiteTM cannot estimate parameters for inorganic chemicals.
Chapter 5 – Chemical Mixing

5-52 

Figure 5-16. Histograms of physicochemical properties of organic chemicals used in the 

hydraulic fracturing process. 

Physicochemical properties as given by EPI SuiteTM (a) measured values of log Kow, (b) estimated log Kow, (c) 

estimated log Solubility, and (d) estimated log Henry’s law constant.

We used EPI SuiteTM to determine the physicochemical properties for 19 CBI chemicals used in 

hydraulic fracturing fluids. These chemicals were submitted to the EPA by nine service companies 

from 2005 to 2009 (see Text Box 5-3 for discussion on CBI).1 The CBI chemical physicochemical 

properties are plotted as histograms in Appendix Figure C-1. The values of the physicochemical 

properties of known and CBI chemicals are similar, covering similar ranges and centered on similar 

values, suggesting that even though these chemicals are not publicly known, their physicochemical 

properties are not appreciably different from the known chemicals. This suggests that their fate and 

transport would not be appreciably different than the chemicals that are publicly known. 

5.8.3 Mobility of Organic Hydraulic Fracturing Chemicals

Figure 5-16 shows the distribution of log Kow, solubility, and Henry’s Law constant for organic 

chemicals used in hydraulic fracturing fluids. These figures suggest that the organic chemicals used 

in hydraulic fracturing cover a wide range of physicochemical properties. For example, many

chemicals are centered around log Kow = 0, which indicates that these chemicals are likely to 

associate roughly equally with organic or aqueous phases. Many chemicals have log Kow > 0,

indicating less mobility, which may cause these chemicals to serve as later-term or long-term 

sources of impact on drinking water. Solubilities range from fully miscible to sparingly soluble. 

Many chemicals have log Henry’s law constants less than 0, indicating that most are not highly 

volatile. Volatilization may not serve as a dominant loss process for hydraulic fracturing chemicals.

 

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 the EPA by nine service companies.
Chapter 5 – Chemical Mixing

5-53 

The 20 chemicals with the smallest Kow (most mobile) may have greater potential to cause 

immediate impacts on drinking water resources (Appendix Table C-10). Most of these chemicals 

were infrequently reported in disclosures (≤2% of wells) in the EPA FracFocus 1.0 project database 

(U.S. EPA, 2015a). Choline chloride (14% of wells), used for clay control, and 

tetrakis(hydroxymethyl)-phosphonium sulfate (11% of wells), a biocide, were more commonly 

reported. The 20 chemicals with the largest Kow (least mobile) may have a greater potential to serve 

as long-term sources of contamination (Appendix Table C-11). The estimated aqueous solubilities 

for some of these chemicals are extremely low, with highest solubilities of less than 10 μg/L. Seven

low mobility chemicals were reported in disclosures in the EPA FracFocus 1.0 project database (U.S. 

EPA, 2015c). Five were reported infrequently (<1% of wells). Tri-n-butyltetradecylphosphonium 

chloride (6% of wells), used as a biocide, and C>10-alpha-alkenes (8% of wells), a mixture of alphaolefins with carbon numbers greater than 10 used as a corrosion inhibitor, were more commonly 

reported. Sorbitan, tri-(9Z)-9-octadecenoate, a mineral oil co-emulsifier (0.05% of wells) had the 

highest estimated log Kow of 22.56.1

Table 5-7 shows the EPI SuiteTM estimated physicochemical property values of the 20 chemicals 

most frequently reported nationwide in disclosures along with estimated mean and median 

volumes based on disclosures in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). Most 

have log Kow < 1, meaning that they are generally hydrophilic and will associate with water. These 

chemicals also have very high solubilities, so they will be mobile in the environment, transport with 

water, and can occur at high concentrations. These chemicals have the potential for faster impacts 

on drinking water resources. 

Naphthalene (CASRN 91-20-3) has a measured log Kow = 3.3 with an estimated solubility of 142.1 

mg/L, which means it will be less mobile in the environment. Naphthalene will sorb to particles and 

move slowly through the environment and has the potential to act as a long-term source of 

contamination.2 All of these chemicals have low Henry’s law constants, so they tend not to 

volatilize. We also include ranges of similar physicochemical properties for two chemicals that are 

organic mixtures: distillates, petroleum, hydrotreated light (CASRN 64742-47-8) and solvent 

naphtha, petroleum, heavy arom. (CASRN 64742-94-5). Both of these are complex organic mixtures, 

and thus EPI SuiteTM cannot estimate their properties. However, the Total Petroleum Hydrocarbon 

Work Group has provided regressions to relate physicochemical properties to the number of 

carbons for aliphatic and aromatic hydrocarbons (Gustafson et al., 1997), which shows that they 

have low solubilities and large log Kow. 

 

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). 

2 Chemicals can have the potential to be long-term sources of contamination when 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 certain conditions, for example, naphthalene is 

biodegradable, which can reduce or remove it from the environment, and thus may not be a long-term source of 

contamination.
Chapter 5 – Chemical Mixing

5-54 

Table 5-7. The 20 chemicals reported most frequently nationwide for hydraulic fracturing based on the EPA FracFocus 1.0 project 

database, with EPI SuiteTM physicochemical parameters where available, and estimated mean and median volumes of those 

chemicals where density was available. 

Excludes water, sodium chloride, and quartz. NA means that the physicochemical parameter is not provided by EPI SuiteTM or the volume could not be 

estimated due to missing data. For organic salts, parameters are estimated using the desalted form. 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.

 

Log Kow (unitless) 

 

 

Henry's Law Constant 

(atm m3/mole @ 25oC) 

Estimated 

volume, per 

disclosure (gal) 

 

Rank Chemical name CASRN

 

Number of 

wells using 

chemical 

(% of wells)

Water solubility 

estimate from 

log Kow 

(mg/L @ 25o Estimated Measured C) 

Estimated, 

bond method 

Estimated, 

group method 

25 Measured Mean Median 

1 Methanol 67-56-1 24,753 (72%) -0.63 -0.77 1.00 × 106 4.27 × 10-6 3.62 × 10-6 4.55 × 10-6 1,218 110

2 Distillates, petroleum, 

hydrotreated lighta,b 64742-47-8 22,463 (65%) log Koc = 4.5 to 6.7 NA 0.00035 to 0.12 55 to 69 cm3/cm3 NA NA NA NA

3 Hydrochloric acid 7647-01-0 22,380 (65%) NA NA NA NA NA NA 28,320 3,110

4 Isopropanol 67-63-0 16,039 (47%) 0.28 0.05 4.024 × 105 7.52 × 10-6 1.14 × 10-5 8.10 × 10-6 2,095 55

5 Ethylene glycol 107-21-1 15,800 (46%) -1.2 -1.36 1.00 × 106 1.31 × 10-7 5.60 × 10-11 6.00 × 10-8 614 184

6 Peroxydisulfuric acid, 

diammonium salt 7727-54-0 14,968 (44%) NA NA NA NA NA NA NA NA

7 Sodium hydroxide 1310-73-2 13,265 (39%) NA NA NA NA NA NA 551 38

8 Guar gum 9000-30-0 12,696 (37%) NA NA NA NA NA NA NA NA

9 Glutaraldehyde 111-30-8 11,562 (34%) -0.18 NA 1.672 × 105 1.10 × 10-7 2.39 × 10-8 NA 1,313 122

10 Propargyl alcohol 107-19-7 11,410 (33%) -0.42 -0.38 9.355 × 105 5.88 × 10-7 NA 1.15 × 10-6 183 2

11 Potassium hydroxide 1310-58-3 10,049 (29%) NA NA NA NA NA NA NA NA

12 Ethanol 64-17-5 9,861 (29%) -0.14 -0.31 7.921 × 105 5.67 × 10-6 4.88 × 10-6 5.00E-06 831 121

13 Acetic acid 64-19-7 8,186 (24%) 0.09 -0.17 4.759 × 105 5.48 × 10-7 2.94 × 10-7 1.00 × 10-7 646 47

14 Citric acid 77-92-9 8,142 (24%) -1.67 -1.64 1.00 × 106 8.33 × 10-18 NA 4.33 × 10-14 163 20
Chapter 5 – Chemical Mixing

5-55 

 

Log Kow (unitless) 

 

 

Henry's Law Constant 

(atm m3/mole @ 25oC) 

Estimated 

volume, per 

disclosure (gal) 

 

Rank Chemical name CASRN

 

Number of 

wells using 

chemical 

(% of wells)

Water solubility 

estimate from 

log Kow 

(mg/L @ 25o Estimated Measured C) 

Estimated, 

bond method 

Estimated, 

group method 

25 Measured Mean Median 

15 2-Butoxyethanol 111-76-2 7,347 (21%) 0.57 0.83 6.447 × 104 9.79 × 10-8 2.08 × 10-8 1.60 × 10-6 385 26

16

Solvent naphtha, 

petroleum, heavy 

arom.b,c

64742-94-5 7,108 (21%) log Koc = 3.2 

to 2.7 NA 5.8 to 65 0.028 to 0.39 cm3/cm3 NA NA NA NA

17 Naphthalene 91-20-3 6,354 (19%) 3.17 3.3 1.421 × 102 5.26 × 10-4 3.7 × 10-4 4.4 × 10-4 72 12

18 2,2-Dibromo-3-

nitrilopropionamide 10222-01-2 5,656 (16%) 1.01 0.82 2.841 × 103 6.16 × 10-14 NA 1.91 × 10-8 183 5

19 Phenolic resin 9003-35-4 4,961 (14%) NA NA NA NA NA NA NA NA

20 Choline chloride 67-48-1 4,741 (14%) -5.16 NA 1.00 × 106 2.03 × 10-16 NA NA 2,131 290

a Hydrotreated light petroleum distillates (CASRN 64742-47-8) is a mixture of hydrocarbons in the C9 to C16 range. 

b Physicochemical parameters are estimated using Gustafson et al. (1997). Parameters are presented as log Koc (soil organic carbon-water partition coefficient), solubility (mg/L), 

and Henry’s Law Constant (cm3/cm3). 

c Heavy aromatic solvent naphtha (petroleum) (CASRN 64742-94-5) is mixture of aromatic hydrocarbons in the C9 to C16 range.
Chapter 5 – Chemical Mixing

5-56 

For the top 20 chemicals, many chemicals have high solubilities and negative or almost zero log Kow

(e.g., methanol, isopropanol, ethylene glycol). These chemicals are likely to travel quickly through 

the environment and could result in an immediate impact. Three chemicals, with larger log Kow and 

smaller solubilities (distillates, petroleum, hydrotreated light; solvent naphtha, petroleum, heavy 

arom.; and naphthalene) may result in more severe impacts. These chemicals could associate with 

the soil particles, releasing into the groundwater at low concentrations slowly over time, and thus 

serve as long-term sources of contamination.

Mobility of a chemical is complex, and these numbers solely represent how a chemical behaves in 

an infinitely dilute aqueous solution, a simplifying approximation of the real world. Many factors 

can affect the fate and transport of a chemical, such as the transformation process (e.g., 

biodegradation), the presence of other chemicals, and site and environmental conditions. We 

discuss these factors in the next sections.

5.8.4 Transformation Processes

Once a chemical is released into the environment, it can transform or degrade. Understanding the 

processes governing these reactions in the environment is important to assessing potential impacts. 

The transformation of a chemical may reduce its concentration over time. Chemicals may 

completely degrade before reaching a drinking water resource. Transformation processes can be 

biotic or abiotic and may transform a chemical into a less or more harmful chemical. 

One important transformation process is biodegradation. Biodegradation is a biotic process where 

microorganisms transform a chemical from its original form into another chemical. For example, 

the general biodegradation pathway of methanol is CH3OH CH2O  CHOOH  CO2 or 

methanol  formaldehyde  formic acid  carbon dioxide (Methanol Institute, 2013).1 This 

pathway shows how the original chemical transforms through a series of steps until it becomes the 

final product, carbon dioxide. Some chemicals are readily biodegraded, while others break down 

slowly over time. Biodegradation is a highly site-specific process, requiring nutrients, a carbon 

source, water, and an energy source. A highly biodegradable chemical could be persistent if the 

conditions for biodegradability are not met. Conversely, a chemical could biodegrade quickly under 

the right conditions, affecting its potential to impact a drinking water resource. The relationship 

between mobility and biodegradability is complex, and a variety of factors can influence a 

particular chemical’s movement through the environment. 

Abiotic processes, such as oxidation, reduction, photochemical reactions, and hydrolysis, can 

transform or break apart chemicals. The typical results are products that are more polar than the 

 

1 In methanol biodegradation, PQQ (pyrroloquinoline quinone) is a redox cofactor that goes from PQQ to PQQH2 removing 

two hydrogen from methanol in the first step to form formaldehyde. Water is added to formaldehyde to provide the 

second oxygen to form formic acid. Nicotinamide adenine dinucleotide (NAD) is a coenzyme that takes up a hydrogen, 

going from NAD to NADH+. This removes the hydrogen in the second and third steps, to result in carbon dioxide.
Chapter 5 – Chemical Mixing

5-57 

original compounds, and thus have different physicochemical properties (Schwarzenbach et al., 

2002).1

5.8.5 Fate and Transport of Chemical Mixtures

Spills during the chemical mixing stage are often present as mixtures of chemicals. Additives are 

often mixtures of a few to several chemicals, possibly highly concentrated, and hydraulic fracturing 

fluids are often dilute mixtures of several additives. Chemical mixtures can act differently in the 

environment than individual chemicals. Individual chemicals can affect the fate and transport of 

other chemicals in a mixture primarily by changing their physicochemical properties and 

transformation rates.

Chemical mixtures can be more mobile than individual chemicals due to cosolvency, which

increases solubility in the aqueous phase. Methanol and ethanol are examples of cosolvent alcohols

used frequently in hydraulic fracturing fluids (U.S. EPA, 2015a). The presence of either greatly 

increases BTEX solubility (Rasa et al., 2013; Corseuil et al., 2011; Heermann and Powers, 1998).2 By 

increasing solubility, ethanol can affect the fate and transport of other compounds. For example,

BTEX has been observed to travel farther in the subsurface in the presence of ethanol (Rasa et al.,

2013; Corseuil et al., 2011; Corseuil et al., 2004; Powers et al., 2001; Heermann and Powers, 1998). 

The presence of surfactants lowers fluid surface tension and increases solubility of organic 

chemicals. Surfactants can mobilize less soluble/less mobile organic chemicals. Two common 

surfactants reported in disclosures in the EPA FracFocus 1.0 project database were 2-

butoxyethanol (CASRN 111-76-2, 21% of disclosures) and poly(oxy-1,2-ethanediyl)-nonylphenylhydroxy (mixture) (CASRN 127087-87-0, 20% of disclosures). Additionally, surfactants can 

mobilize bacteria in the subsurface, which can increase the impact of pathogens on drinking water 

resources (Brown and Jaffé, 2001). 

When chemicals are present as mixtures, one chemical can decrease or enhance the 

biodegradability of another through inhibition or co-metabolism. The process of inhibition can slow 

biodegradation of each of the chemicals present. For example, the biodegradation of ethanol and 

methanol can slow the biodegradation rate of BTEX or other organic chemicals present (Rasa et al., 

2013; Powers et al., 2001). Co-metabolism can increase the biodegradation rate of other chemicals. 

For example, when methane or propane is present with tetrachloroethylene, the enzyme produced 

by bacteria to degrade methane also degrades tetrachloroethylene (e.g., Alvarez-Cohen and Speitel, 

2001 and references therein). For the purposes of chemicals used in hydraulic fracturing, the 

presence of other chemicals in additives and hydraulic fracturing fluids could result in increased or

decreased biodegradation if the chemicals are spilled.

1 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, H2O, 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.
Chapter 5 – Chemical Mixing

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5.8.6 Site and Environmental Conditions

Environmental conditions at and around the spill site affect the movement and transformation of 

chemicals. This section discusses the following: site conditions (e.g., proximity, land cover, and 

slope), soil conditions (e.g., permeability and porosity), and weather and climate. 

The proximity of a spill to a drinking water resource, either laterally in the case of a surface water 

body or downward for groundwater, affects the potential for impact and its severity. Land cover 

will affect how readily a fluid moves over land. For example, more rugged land cover such as forest 

can impede flow, and an asphalt road can facilitate flow. A spill that occurs on or near a sloped site 

can move overland faster, increasing the potential to reach nearby surface water. Flatter surfaces 

result in a greater chance for infiltration to the subsurface, which could increase the potential for 

groundwater impact.

Soil characteristics that affect the transport and transformation of spill chemicals include soil 

texture (e.g., clay, silt, sand), permeability, porosity, and organic content.1,2 Fluids will move more 

quickly through permeable soil (e.g., sand) than through less permeable soil (e.g., clay). A soil with a 

high porosity provides more volume to hold water and spilled chemicals. Another important factor 

for a site is the organic content, of which there are two competing types: soil organic carbon and 

dissolved organic carbon. Each type of carbon acts as a strong substance for chemicals to associate 

with. Soil organic carbon present in a solid phase, such as dead and decaying leaves and roots, is not 

mobile and slows the movement of chemicals through the soil. Dissolved organic carbon (DOC) 

moves with the water and can act as a shuttling mechanism to mobilize less soluble chemicals 

across the surface and through the subsurface. Chemicals may also associate and move with 

particulates and colloids.

Weather and climate conditions affect the fate and transport of a spilled chemical. After a spilled 

chemical stops moving, precipitation can remobilize the chemical. The amount, frequency, and 

intensity of precipitation will impact the volume, distance, and speed of chemical movement. 

Precipitation can carry chemicals downward or overland, and it can cause erosion, which can move 

sorbed chemicals overland.

5.8.7 Peer-Reviewed Literature on the Fate and Transport of Hydraulic Fracturing Fluid Spills

There has been limited peer-reviewed research investigating the fate and transport of chemicals 

spilled at hydraulic fracturing sites. Aminto and Olson (2012) modeled a hypothetical spill of 

1,000 gal (3,800 L) of hydraulic fracturing fluid using equilibrium partitioning. The authors

evaluated how 12 chemicals typically used for hydraulic fracturing in the Marcellus Shale would 

partition among different phases: air, water, soil, and biota.3 They presented a ranking of 

 

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.

2 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.

3 The chemicals they investigated included: sodium hydroxide, ethylene glycol, 4,4-dimethyl oxazolidine, 3,4,4-trimethyl 

oxazolodine, 2-amino-2-methyl-1-propanol, formamide, glutaraldehyde, benzalkonium chloride, ethanol, hydrochloric 

acid, methanol, and propargyl alcohol.
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concentrations for each phase. In water, they showed that sodium hydroxide (a pH buffer), 4,4-

dimethyl oxazolidine (a biocide), hydrochloric acid (a perforation clean-up additive), and 3,4,4-

trimethyl oxazolidine (a biocide) had the highest simulated water concentrations; however, these 

concentrations depended on the chemicals included in the simulated mixture and the 

concentrations of each. Their analysis suggested that after a spill, a large fraction of the spill would 

volatilize and leave the soil; however, some constituents would be left behind in the water, soil, and 

biota compartments, which could act as long-term contamination sources. Aminto and Olson 

(2012) only studied this one scenario. Other scenarios could be constructed with different 

chemicals in different concentrations. These scenarios may result in different outcomes and 

impacts. Any spill would require site- and spill-specific modeling on a case-by-case basis. For this 

reason, we cannot make any general statement about fate and transport of hydraulic fracturing 

chemicals and fluids. For this reason, we cannot make any general statement about fate and 

transport of hydraulic fracturing chemicals and fluids.

Drollette et al. (2015) suggested a link between surface spills and groundwater contamination, 

possibly from hydraulic fracturing activity, because the chemicals detected were hydraulic 

fracturing additives. This work demonstrates the pathway for surface spills to impact groundwater 

sources. They detected low levels of gasoline related organic chemicals with elevated diesel range 

organic chemicals, which suggests that the former were degraded or volatilized, while the latter 

were more persistent and penetrated into the subsurface and into groundwater.

5.8.8 Potential and Documented Fate and Transport of Documented Spills

There is limited information on the fate and transport of hydraulic fracturing fluids and chemicals. 

This section highlights both potential and documented impacts for three reported spills (U.S. EPA, 

2015m). In each case, we provide the documented and potential paths (surface, subsurface, or 

combination) and the associated fate and transport governing processes by which the spill has been 

documented or has the potential to have an impact on drinking water resources. The three cases 

involve a tank overflow with a reported surface water impact, a human error blender spill with a 

reported soil impact, and an equipment failure that had no reported impact. We specifically chose 

these three spills to highlight three different cases. One demonstrates a documented impact with a 

demonstrated pathway that had an observed effect on a nearby drinking water resource. The 

second case shows how a release can impact an environmental receptor with a pathway for 

potential impact on a drinking water resource, but there was no observed impact. The third 

example is a spill that was contained and cleaned up resulting in likely no impact. None of these 

chemical releases have any documented pre- or post-sampling. No information on the specific 

chemicals spilled or the concentrations or total mass of any chemical is provided. We cannot 

provide any quantitative assessment from these observed cases. 

In the first documented spill, shown in Figure 5-17, a tank overflowed twice, releasing a total of 

7,350 gal (980 ft3, 28 m3, or 27,800 L) of friction reducer and gel (PA DEP, 2012, ID#1830163).1 The 

spill traveled across the land surface, crossed a road, and then continued to a nearby stream. The 

 

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 (28,000 L) might travel.
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spill affected wetlands and a stream, where fish were reported to have been killed. The fish kill 

indicates an observable impact. This represents a good example for how environmental conditions 

can affect the severity and timing of impact, due to the slope of the lands surface, the permeability 

of the soil, and the proximity to surface water. We are not aware of any measurements performed 

for soils, groundwater, surface water, sediments, or fish tissue. Based on the publicly available 

information, we do not know what chemicals were in the friction reducer and gel, which limits 

further assessment.

Figure 5-17. Fate and Transport Spill Example: Case 1. 

Spills information from PA DEP (2012, ID#1830163). 

For this first spill, the documented path was overland flow from the tank to the stream with a 

documented, immediate impact. There are also other potential paths for potential impacts on 

drinking water resources. The spilled chemicals could have penetrated into the soils or sorbed to 

soils and vegetation as the fluid moved across the ground towards the stream. Chemicals could then 

be mobilized during later precipitation, runoff, or erosion events. Chemicals that infiltrated the 

subsurface could serve as long-term sources, travel laterally across the unsaturated zone, or 

continue downwards to groundwater. Some chemicals could be lost to transformation processes. 

The absence of reported soil or groundwater sampling data prevents the ability to know if these 

potential paths occurred or not. 

The second documented spill, shown in Figure 5-18, occurred when a cap was left off the blender, 

and 504 gal (70 ft3 or 2 m3) of biocide and hydraulic fracturing fluid were released (COGCC, 2012, 
Chapter 5 – Chemical Mixing

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ID#2608900). In addition, 294 gal (39 ft3 or 1.1 m3) were retained by a dike with a lined secondary 

containment measure, demonstrating the partial effectiveness of this containment mechanism. The 

remaining 210 gal (28 ft3 or 0.8 m3) of fluid (biocide and water) ran off-site. Of this, 126 gal were 

vacuumed, leaving 84 gal. There was no documented impact on surface or groundwater. However, 

potential impacts potentially could have occurred.

Figure 5-18. Fate and Transport Spill Example: Case 2. 

Spills information from COGCC (2012, ID#2608900). 

In this second case, the uncontained 84 gal could have infiltrated the subsurface, creating a 

potential path to groundwater. Highly mobile chemicals could have penetrated the soil more 

quickly than less mobile chemicals, which would have sorbed to soil particles. As the chemicals 

penetrated into the soil, some could have moved laterally in the unsaturated zone, or traveled 

downward to the groundwater table and moved with direction of groundwater flow. These 

chemicals could have served as a long-term contamination source. The chemicals also could have 

transformed into other chemicals with different physicochemical properties, and any volatile 

chemicals could have moved to the air as a loss process. As in the first case, there was no reported 

sampling of soil or groundwater, so there is no way to know if chemicals did or did not follow any of 

these pathways. We do not have any more information on the types of chemicals present or the 

concentrations with which they were present, which limits further assessment.

In the third documented spill, shown in Figure 5-19, 630 gal (84 ft3 or 2.4 m3) of crosslinker spilled 

onto the well pad when a hose wore off at the cuff (COGCC, 2012, ID#1395827). The spill was 
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contained in the berm and an on-site vacuum truck was used to clean up the spill. No impact on soil 

or water was reported. 

Figure 5-19 Fate and Transport Spill Example: Case 3. 

The pad may or may not have had a liner. Spills information from COGCC (2012, ID#1395827). 

For this third case, we do not have any information on whether the well pad was lined or not. If the 

site had a liner, the spill could have been fully contained and cleaned up. Without a liner or if the 

integrity of the liner was compromised (e.g., had a tear), any residual chemical that was not 

effectively cleaned up could have remained in the soil. This would create potential paths similar to 

those above in the second case, where the chemicals could have sorbed to the soils and penetrated 

into the subsurface and possibly reach groundwater. There was no reported sampling of soil or 

groundwater to determine whether or not chemicals migrated into the soil, and we do know the 

types of chemicals or the concentrations of the released chemicals. 

5.8.9 Challenges with Unmonitored and Undetected Chemicals

One of the challenges confronting a thorough assessment of the fate and transport of spilled 

hydraulic fracturing chemicals lies in the lack of documented observations. It is difficult to prove 

absence of impact, and absence of observations does not necessarily imply lack of impact. Also, we 

know there are over 1,000 different chemicals reported used in hydraulic fracturing (Section 5.4), 

and this number is increasing. For many chemicals, there is not an analytical technique available to 

detect them in samples taken to a laboratory. Due to the lack of information on the chemicals used 
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on site (some of which are claimed as CBI), one would not know what chemicals to include in the 

lab analysis. Hydraulic fracturing chemicals are typically present as complex mixtures, which also 

complicates sample analysis. Chemicals can transform upon release, which can result in different 

chemicals in the environment than those originally released. Even if chemicals are detected on-site, 

it can be difficult to demonstrate a direct linkage to hydraulic fracturing operations, since many of 

the chemicals used in hydraulic fracturing are also used for other purposes (such as gasoline or 

diesel from vehicles). Since there are currently no requirements for a detection–monitoring 

network to assess the occurrence and extent of chemical releases from the well pad, it is not 

possible to conclusively assess the frequency and impact of fluid releases during the chemical 

mixing process. 

5.9 Trends in the Use of Hydraulic Fracturing Chemicals

Hydraulic fracturing science and engineering continues to advance. A part of this research includes 

using different chemicals. This section provides an overview of the changes in chemical use, with an 

emphasis on efforts to reduce potential impacts from surface spills by using fewer and safer 

chemicals. Reasons for changing the types of chemicals used can include: improving the fracturing 

process, using greener/safer chemicals, and reducing overall cost. 

Representatives from oil and gas companies, chemical companies, and non-profits are working on 

strategies to reduce the number and volume of chemicals used and to identify safer chemicals 

(Waldron, 2014). Southwestern Energy Company, for example, is developing an internal chemical 

ranking tool (SWN, 2014), and Baker Hughes is working on a hazard ranking system designed for 

wide-scale external use (Baker Hughes, 2014; Brannon et al., 2012; Daulton et al., 2012; Brannon et 

al., 2011). Environmental groups, such as the Environmental Defense Fund, are also developing 

hazard rating systems (Penttila et al., 2013). Typical criteria used to rank chemicals include 

mobility, persistence, biodegradation, bioaccumulation, toxicity, and hazard characteristics. In this 

assessment, toxicity and a methodology to rank chemical hazards of hydraulic fracturing chemicals 

is discussed in Chapter 9. 

Given that human error is the cause of 25% of chemical mixing related spills and spill prevention 

can never be 100% effective, changes to the types of chemicals used could reduce the frequency or 

the severity of potential impacts. Using chemicals with specific physicochemical properties that 

affect the fate and transport of chemicals could reduce their potential impacts. Less mobile 

chemicals could make cleanup of spills easier. For example, using dry chemicals that are hydrated 

on-site could minimize impacts if there were a container failure. Using chemicals with lower 

persistence and higher biodegradability, if spill prevention and cleanup are not fully effective, 

would lessen the severity of potential impact. Use of less hazardous chemicals could lessen impact 

in cases where a spill reaches a drinking water resource. 

The EPA has not conducted a comprehensive review of efforts to develop safer hydraulic fracturing 

chemicals. However, the following are some specific examples of efforts that companies cite as part 

of their efforts toward safer chemical use:

• A renewable citrus-based replacement for conventional surfactants (Fisher, 2012); 
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• A crosslinked gel system comprised of chemicals designated as safe food additives by the 

U.S. Food and Drug Administration (Holtsclaw et al., 2011); 

• A polymer-free gel additive (Al-Ghazal et al., 2013); 

• A dry, hydrocarbon-free powder to replace liquid gel concentrate (Weinstein et al., 2009); 

• Biodegradable polymers (Irwin, 2013); 

• The use of ultraviolet light to control bacteria (Rodvelt et al., 2013); 

• New chelating agents that reduce the use of strong acids (LePage et al., 2013); 

• Eco-friendly viscoelastic surfactant (VES) polymer-free fluid reduces fracture cleanup time 

with 95% retrieved fluids compared to 40 – 60% and is less toxic than polymer-based 

fluids (AlKhowaildi et al., 2016); and

• The recovery and reuse of produced water as hydraulic fracturing fluids, which can reduce

the need to add additional chemicals (Horn et al., 2013). 

A review of the EPA’s new chemicals program found that, from 2009 to April 2015, the Agency 

received pre-manufacturing notices (PMN) for about 110 chemicals that have the potential for use 

as additives. Examples include chemicals intended for use as clay control agents, corrosion 

inhibitors, gel crosslinkers, emulsifiers, foaming agents, hydrate inhibitors, scale inhibitors, and 

surfactants. At the time of PMN submission, these chemicals were not in commercial use in the 

United States. As of April 2015, the EPA had received 30 notices of commencement, indicating that 

some of the chemicals are now used commercially.

As different hydraulic fracturing fluids are developed, they have corresponding effects on different 

stages of the hydraulic fracturing water cycle. For example, in Figure 5-4(b) an example of an 

energized fluid uses a total water volume of 105,000 gal (397,000 L), which means less water is 

required in the water acquisition stage and less produced water results in less wastewater. Figure 

5-4(a) shows slickwater with 4,763,000 gal (18,030,000 L) of water, yet a larger fraction of 

slickwater may be reused, reducing the need for more water for another frac job and requiring the 

treatment of less wastewater.

5.10 Synthesis

The chemical mixing stage includes the mixing of base fluid, proppant, and additives on the well pad 

to make hydraulic fracturing fluid. This chapter provided an analysis of the factors affecting 

potential impacts on drinking water resources during the chemical mixing stage of the hydraulic 

fracturing water cycle and the factors governing the frequency and severity of these impacts. 

5.10.1 Summary of Findings

Reports have demonstrated that spills and releases of chemicals and fluids have occurred during 

the chemical mixing stage and have reached soils and surface water receptors. Spill reports have 

not documented impacts on groundwater related to the chemical mixing stage. Spill reports have 

little information on post-spill testing and sampling. Impacts on groundwater may remain 

undocumented. The potential pathway for impact on groundwater has been demonstrated and 
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documented for chemicals spilled during other parts of the hydraulic fracture water cycle. 

(Evidence of groundwater impact from produced water spills is discussed Chapter 7.) 

The hydraulic fracturing fluid generally consists of a base fluid (typically water), a proppant 

(typically sand), and additives (chemicals), although there is no standard or single composition of 

hydraulic fracturing fluid used. According to the analysis of the EPA FracFocus 1.0 project database, 

based on FracFocus disclosure data from January 2011 to February 2013, approximately 93% of 

hydraulic fracturing fluids use water as a base fluid. Non-aqueous fluids, such as nitrogen, carbon 

dioxide, and hydrocarbons, are also used as base fluids or used in combination with water as base 

fluids. The number of chemicals injected into a well typically ranges from 4 to 28, with a median of 

14 (U.S. EPA, 2015a). In water-based hydraulic fracturing, the composition, by volume, of a typical 

hydraulic fracturing fluid is 90% to 97% water, 2% to 10% proppant, and 2% or less additives 

(Carter et al., 2013; Knappe and Fireline, 2012). 

The EPA has identified 1,084 different chemicals used in chemical mixing. A recent study of 

FracFocus disclosure data, covering January 2011 to April 2015, has reported 263 new CASRNs, 

increasing the number of chemicals identified for use by approximately 24% (Konschnik and 

Dayalu, 2016). Hydraulic fracturing chemicals cover a wide range of chemical classes and a wide 

range of physicochemical properties. The chemicals include acids, aromatic hydrocarbons, bases, 

hydrocarbon mixtures, polymers, and surfactants. The use of 32 chemicals, excluding water, quartz, 

and sodium chloride, is reported in 10% or more of disclosures in the EPA FracFocus 1.0 project 

database. The ten most common chemicals (excluding quartz) are methanol, hydrotreated light 

petroleum distillates, hydrochloric acid, isopropanol, ethylene glycol, peroxydisulfuric acid 

diammonium salt, sodium hydroxide, guar gum, glutaraldehyde, and propargyl alcohol (U.S. EPA, 

2015c). These chemicals can be present in multiple additives. Methanol, hydrotreated light 

petroleum distillates, and hydrochloric acid are the three chemicals reported to be used in more 

than half of all hydraulic fracturing jobs, with methanol being used at 72% of all sites. 

An EPA analysis of spills data (January 2006 to April 2012, from nine states, nine service 

companies, and nine operators) identified over 36,000 spills, with 457 spills (~1%) that were on or 

near the well pad and definitively associated with hydraulic fracturing. Of these spills, 151 were of

chemicals or hydraulic fracturing fluid and thus assumed to be associated with the chemical mixing 

stage. Chemical spills during the chemical mixing stage were primarily caused by equipment failure 

(34%), followed by human error (25%), although 26% spills had an unknown source. The 

remaining spills were caused by a failure of container integrity, weather, vandalism, and well 

communication. Reported spills covered a large range of volumes, from 5 to 19,320 gal (19 to 

73,130 L), with a median of 420 gal (1,600 L) (U.S. EPA, 2015m). 

The rate of reported spills during the hydraulic fracturing water cycle is estimated to range from 

0.4 to 12.2 reported spills for every 100 wells, based on spills data from North Dakota, 

Pennsylvania, and Colorado, with a median rate of 2.6 reported spills for every 100 wells (See 

Appendix C). The estimated rates provide an approximate estimate of the potential frequency of the 

number of spills at a site. It is uncertain how representative these rates are of national spill rates or 

rates in other states. These numbers are not specific to the chemical mixing stage. In 2015, there 
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are 2.6 reported spills occurring during the chemical mixing stage per 100 wells hydraulically 

fractured in North Dakota.

The total volume of chemicals used on site are estimated to range from 2,600 to 30,000 gal (9,800 

to 114,000L). An estimate for the mean volume for any chemical used on-site is 650 gal (2,500 L) 

with a mean mass of 1500 kg (3,200 lb). An estimate of 2,300 to 6,500 gal (8,800 to 25,000 L) of 

additives are stored on site, typically in multiple totes of 200 to 375 gal (760 to 1,420 L). These 

volumes provide insight on how much potentially could spill at any given hydraulic fracturing site 

and what the volume of a spill might be depending on where/when it occurs during the chemical 

mixing process. 

The potential of spills to reach drinking water resources depends on site and chemical properties. 

The fate and transport of spilled hydraulic fracturing chemicals is complex, particularly because 

chemicals are generally present as diverse, complex mixtures. There are different pathways for a 

spill to reach ground and surface water and to serve as a long term source. Roughly 40% of 

hydraulic fracturing chemicals are organic chemicals, which have physicochemical properties that 

cover the parameter space, from fully miscible to insoluble and from highly hydrophobic to highly 

hydrophilic. Of the 20 most frequently used chemicals used at hydraulic fracturing sites, three 

chemicals have low mobility: hydrotreated light petroleum distillates, heavy aromatic petroleum 

solvent naphtha, and naphthalene. These chemicals have the potential to act as long term sources of 

contamination if spilled on-site.

5.10.2 Factors Affecting the Frequency or Severity of Impacts

The specific factors that have the potential to affect the frequency and severity of impacts include 

the size and type of the fracturing operation; volume, mass, and concentration of chemicals spilled; 

type of chemicals and their properties; combination of chemicals spilled; environmental conditions; 

proximity to drinking water resources; employee training and experience; quality and maintenance 

of equipment; and spill containment and mitigation. 

The size and type of a fracturing operation, including the number of wellheads, the depth of the 

well, the length of the leg(s), and the number of stages and phases, affect the potential frequency 

and severity spills. Larger operations can require larger volumes of chemicals, more storage 

containers, more equipment, and additional transfers between different pieces of equipment.

Larger storage containers increase the maximum volume of a spill or leak from a storage container. 

Additional transfers between equipment increase the possibility of human error and potential 

frequency of spills. 

The volume, mass, and concentration of spilled chemicals affect the frequency and severity of 

impacts. A larger volume increases the potential for a spill to travel a longer distance and reach a 

drinking water resource. The severity of the spill will be affected by the spill volume, the total mass 

of chemicals released, and the concentration with which it reaches the drinking water resource.

The type of chemicals spilled affects how the chemicals will move and transform in the 

environment and the type of impact it will have on a drinking water resource. More mobile 

chemicals move faster through the environment, which can increase the frequency of impact. More 
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soluble chemicals can reach a drinking water resource at higher concentrations, thereby increasing 

the potential severity of an impact. Less mobile chemicals will move more slowly, and can have 

delayed and longer-term impacts at lower concentrations. The potential severity of impact is 

affected by how the chemical adversely impacts water quality. Some chemicals can have severe 

impacts at low concentrations, while some chemicals can have minimal impacts even at high 

concentrations. Water quality impacts can range from aesthetic effects (e.g., taste, smell) to adverse 

health effects. 

The environmental conditions at and around the spill site affect the fate and transport of a given 

chemical and thus affect the frequency of impacts as well as potential severity. Conditions include

soil properties, climate, weather, and terrain. Permeable soils allow for rapid transport of the 

spilled fluid through the subsurface and to groundwater. The presence of preferential flow paths 

(e.g., fractures, animal burrows) may provide rapid transport through the subsurface in what might 

appear to have low permeability. The presence of complexing agents and colloids may further 

increase transport of less soluble chemicals. Precipitation can re-mobilize trapped chemicals and 

move them over land or through the subsurface.

The proximity of a spill to drinking water resources affects the frequency and severity of impact. 

The closer a spill is to a drinking water resource, the higher the potential to reach it. As a fluid 

moves toward a drinking water resource, it can decrease in concentration, which can reduce the 

severity of an impact. The characteristics of the drinking water resource will also influence the 

severity of the impact of a spill. For example, a slow release into a fast moving stream will result in 

large dilution and lower concentrations of chemicals (less severe impact). The transport of a 

chemical to groundwater may have a more severe impact, as there may be less dispersion of the 

chemical (higher concentrations in the groundwater, more severe impact) and the chemical could 

serve as a long-term source of contamination (resulting in a chronic exposure versus an acute 

exposure).

Effective spill containment and mitigation measures can prevent or reduce the frequency and 

severity of impacts. Spill containment measures include well pad containment liners, diversion 

ditches, berms, dikes, overflow prevention devices, drip pans, and secondary containers. These may 

prevent a spill from reaching soil and water receptors. Spill mitigation, including removing 

contaminated soils, vacuuming up spilled fluids, and using sorbent materials can limit the severity 

of a spill. It is unclear how effective these practices are and to what extent they are implemented.

5.10.3 Uncertainties

The lack of information and the uncertainty around information having to do with the composition 

of additives and fracturing fluids, containment and mitigation measures in use, the proximity of 

chemical mixing to drinking water resources, and the fate and transport of spilled fluids limits our 

ability to fully assess potential impacts on drinking water resources and the factors affecting their 

frequency and severity.

There is no standard design for hydraulic fracturing fluids. Detailed information on the chemicals 

used is limited. Volumes, concentrations, and mass, as well as the identity of some of chemicals
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stored on-site, are generally not publicly available. The FracFocus national registry, which currently 

holds the most comprehensive information on water and chemicals used in hydraulic fracturing 

fluids, is structured so as to input chemical information as a maximum percentage of the mass of 

fracturing fluid and the given additive. This does not provide exact information on the volume of a 

chemical, the mass of a chemical, or the actual composition of an additive. The accuracy and 

completeness of original FracFocus disclosure information has not been verified. In applying the 

EPA-standardized chemical list to the ingredient records in the EPA FracFocus 1.0 project database, 

standardized chemical names were assigned to only 65% of the ingredient records from the more 

than 36,000 unique, fully parsed disclosures. The remaining ingredient records could not be 

assigned a standardized chemical name and were excluded from analyses (U.S. EPA, 2015a). 

Operators may specify certain ingredients as confidential business information (CBI) and not 

disclose the chemical used. More than 70% of disclosures in the EPA FracFocus 1.0 project database 

contained at least one CBI chemical. Of disclosures with at least one CBI chemical, the average 

number of CBI chemicals per disclosure was five. Approximately 11% of all chemicals reported in 

the disclosures in the EPA FracFocus 1.0 project database were reported as CBI (U.S. EPA, 2015a). 

The rate of withholding in FracFocus 2.0 data has increased to 16.5% (Konschnik and Dayalu, 

2016). No data are available in FracFocus disclosures for any chemical listed as CBI. Therefore, 

chemicals identified as CBI in FracFocus disclosures are not included in any of the analyses in this 

assessment including estimates of chemical volume, physicochemical properties, or frequency of 

use. It is feasible that the same chemicals are repeatedly reported as CBI. Each reported CBI 

chemical could also be unique, which would mean there is a very large number of chemicals that we 

know nothing about. This results in an unknown amount of uncertainty regarding CBI chemicals 

and their potential impact on drinking water resources.

Of the 1,084 hydraulic fracturing fluid chemicals identified by the EPA, 629 were inorganic 

chemicals, mixtures, or polymers, and thus they did not have estimated physicochemical properties 

reported in the EPI SuiteTM database. Knowing the chemical properties of a spilled fluid is essential

to predicting how and where it will travel in the environment. Although we can make some 

generalizations about the physicochemical properties of these chemicals and how spilled chemicals 

may move in the environment, the distribution of properties could change if we obtained data for 

all known fracturing fluid chemicals (as well as for those listed as CBI). 

There has been limited research on the fate and transport of spilled chemicals on site. We have 

provided a limited overview discussing the processes that may be important, but the processes are 

complex. There is great uncertainty in how these chemicals will move in the environment. These 

processes are complicated by the data gaps in fluid characteristics, especially present in mixtures, 

and there is limited understanding on how chemicals act in mixture in the environment. Hydraulic 

fluid mixtures are different than other previously studied mixtures (like petroleums, coal tars, and 

polychlorinated biphenyls (PCBs). Those mixtures are of chemicals of similar classes, while 

hydraulic fracturing fluids are chemicals covering a range of different chemical classes.

There is a lack of field data at hydraulic fracturing sites. There is a lack of baseline ground and 

surface water quality data. This lack of data limits our ability to assess the relative change to water 

quality from a spill or attribute the presence of a contaminant to a specific source. There is a lack of 
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publicly or readily accessible sampling of soils and groundwater after a fracturing job is complete. 

The lack of data and uncertainty on what chemicals are used for hydraulic fracturing makes it 

unclear what chemicals to measure. Further uncertainty lies in the limited analytical techniques for 

chemicals used in hydraulic fracturing. 

There are uncertainties and data gaps in the current information on spills. The EPA spills report 

included data from January 2006 to April 2012 from nine states, nine service companies, and nine 

oil and gas production well operators (U.S. EPA, 2015a). This data contained over 36,000 reported 

spills. From this data set, only 457 were determined to be definitively associated with hydraulic 

fracturing and occurred on or near the well pad. With these data, it is impossible to know if all these 

spill reports capture all spills occurring at hydraulic fracturing sites. The available data might not 

extrapolate to the rest of the nation. Spill reports had limited information on spill causes, 

containment and mitigation measures, and sources of spills. The actual chemicals spilled, the total 

mass, and the composition are generally not included. There are little available data on impacts of 

spills, due to a lack of baseline data and incomplete documentation of follow-up actions and testing.

In general, then, we are limited in our ability to fully assess potential impacts on drinking water 

resources from chemical spills, based on current available information. To improve our 

understanding we need: more information on the chemical composition of additives and fracturing 

fluids and the physicochemical properties of chemicals used; baseline monitoring and field studies 

of spilled chemicals; ground and surface water drinking water resources located and identified, 

with quality conditions performed before and after hydraulic fracturing; detailed site-specific 

environmental conditions; more information on containment and mitigation measures and their 

effectiveness; and more detail on the characteristics of spills, such as the exact chemicals and the 

amount spilled (mass, concentration, volume).

5.10.4 Conclusions

This chapter discusses the factors that affect the potential for the chemical mixing stage of the 

hydraulic fracturing water cycle to impact drinking water resources. Reports have demonstrated 

that spills and releases of chemicals and fluids have occurred during the chemical mixing stage and 

have reached soils and surface waters with the potential to reach groundwater. The potential for 

spilled fluids to reach, and therefore impact, ground or surface water resources depends on the 

composition of the spilled fluid, spill characteristics, spill response activities, and the fate and 

transport of the spilled fluid. There is no standard composition for a hydraulic fracturing fluid, 

which consists of base fluid, proppant, and additives. The EPA identified 1,084 chemicals that have 

been reported to be used nationwide, and these chemicals cover a wide variety of chemical classes 

and physicochemical properties, and this number is increasing. These chemicals cover a range of 

classes and physicochemical properties. The type of fluid and the number, volume, and type of 

chemicals used vary from site to site. Hydraulic fracturing fluids generally consist of a mixture of 

chemicals, which affects the potential for a release to reach a drinking water resource and the 

severity of the potential impact. State and industry spill data collected and reviewed by the EPA and 

others indicate that small (approximately 30 gal or 100 L) and large spills (greater than 1,000 gal or 

4,000 L) can reach surface water resources. While small spills have reached surface water 

resources (and have the potential to reach groundwater resources), large volume spills are more 
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likely to travel longer distances and thus have a greater potential to reach ground and surface water 

resources. Large volume spills, particularly of concentrated additives, also have a greater potential 

to result in more severe impacts on drinking water resources, because they can deliver a large 

quantity of potentially hazardous chemicals to ground or surface water resources. 
Chapter 6 – Well Injection 

6-1

Chapter 6. Well Injection

Abstract 

The well injection stage of the hydraulic fracturing water cycle involves the injection of hydraulic 

fracturing fluids through the oil and gas production well and their movement in the production zone. 

Subsurface pathways created during this stage—including the production well and newly created 

fractures—can allow hydraulic fracturing fluids or naturally occurring fluids to reach groundwater

resources.

This chapter examines two types of pathways by which hydraulic fracturing fluids and liquids and/or 

gases that exist in the subsurface can move to, and affect the quality of, subsurface drinking water 

resources. First, fluids can move via pathways adjacent to or through the production well as a result of 

inadequate design, construction, or degradation of the casing or cement. Second, fluid movement can 

occur within the subsurface geologic formations via fractures extending out of oil/gas-containing 

formations, by intersecting abandoned or active offset wells, or via naturally occurring faults and 

fractures. 

The primary factors that can affect the frequency or severity of impacts to drinking water associated 

with injection for hydraulic fracturing are: (1) the condition of the well’s casing and cement and their 

placement relative to drinking water resources, (2) the vertical separation between the production zone 

and formations that contain drinking water resources, and (3) the presence/proximity and condition of 

wells near the hydraulic fracturing operation.

We identified two cases where hydraulic fracturing activities affected the quality of drinking water 

resources due to well construction issues, including inadequate cement or ruptured casing. Additionally, 

there are places where oil and gas reservoirs and drinking water resources co-exist in the same 

formation and hydraulic fracturing operations occur, which results in the introduction of hydraulic 

fracturing fluids into the drinking water resource. There are other cases involving the migration of stray 

gas where hydraulic fracturing could be a contributing cause to impacts on drinking water resources.

While there is evidence that these pathways have formed and that groundwater quality has been 

impacted, there are limited nationally available data on the performance of wells used in hydraulic

fracturing operations, pre- and post-hydraulic fracturing groundwater quality, and the extent of the 

fractures that develop during hydraulic fracturing operations.

These data limits, in combination with the geologic complexity of the subsurface environment and the 

fact that these processes cannot be directly observed, make determining the frequency of such impacts 

challenging. 
Chapter 6 – Well Injection 

6-2 

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Chapter 6 – Well Injection 

6-3 

6. Well Injection

6.1 Introduction 

In the well injection stage of the hydraulic fracturing water cycle, hydraulic fracturing fluids 

(primarily water, mixed with the types of chemicals and proppant described in Chapter 5) are 

injected into a well under pressure.1 These fluids flow under pressure through the well, then exit 

the well and move into the formation, where they create fractures in the rock. This process is also 

known as a fracture treatment or a type of stimulation.2 The fractures, which typically extend 

hundreds of feet away from the well, are designed to remain within the production zone to access

as much oil or gas as possible by using an appropriate amount of water and chemicals to complete 

the operation.3

Production wells are sited and designed primarily to optimize production of oil or gas, which 

requires isolating water-bearing formations from hydrocarbon-bearing formations in order to 

prevent the water from diluting the hydrocarbons and to protect drinking water resources.4

However, problems with the well’s components or improperly sited, designed, or executed 

hydraulic fracturing operations (or combinations of these) could adversely impact the quality of 

drinking water resources. (Note that, due to the subsurface nature of activities in the well injection 

stage, the drinking water resources that may be directly impacted are groundwater resources; see 

Chapter 2 for additional information about groundwater.5) 

The well and the geologic environment in which it is located are a closely linked system. Wells are 

often designed with multiple barriers (i.e., isolation afforded by the well’s casing and cement and 

the presence of subsurface rock formations) to prevent fluid movement between oil/gas zones and 

drinking water resources. Therefore, this chapter discusses (1) the well (including its construction 

and operation) and (2) the characteristics of or features in the subsurface geologic formations that 

could provide or have provided pathways for migration of fluids to drinking water resources. If 

present, and in combination with the existence of a fluid and a physical force that moves the fluid, 

these pathways can lead to impacts on the quality of drinking water resources throughout the life of 

the well, including during and after hydraulic fracturing.6

 

1 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 block or 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 or the targeted rock formation) 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 A subsurface formation (or “formation”) is a mappable body of rock of distinctive rock type(s) and characteristics (such 

as permeability and porosity) with a unique stratigraphic position. 

5 Government agencies and other organizations use a variety of terms to describe potable groundwater and groundwater 

resources. In this chapter, we use the general term “groundwater resources” to refer to drinking water resources that 

occur underground. However, other terms are used in specific contexts to reflect the language used in cited materials.

6 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 for more information. 
Chapter 6 – Well Injection 

6-4 

Fluids can move via pathways adjacent to or through the production well that are created in 

response to the stresses exerted during hydraulic fracturing operations if the well is not able to 

withstand these stresses (Section 6.2). While wells are designed and constructed to isolate fluids 

and maximize the production of oil and gas, inadequate construction or degradation of the casing or 

cement can allow fluid movement that can impact drinking water quality. Potential issues 

associated with wells may be related to the following:

• Inadequate or degraded casing. This may be influenced by the number of casing strings and 

the depths to which they are set, compatibility with the geochemistry of intersected 

formations, the age of the well, whether re-fracturing is performed, and other operational 

factors. 

• Inadequate or degraded cement. This may be influenced by a lack of cement in key 

subsurface intervals, poor-quality cement, improperly placed cement, or degradation of 

cement over time.

Fluid movement can also occur via induced fractures and/or other features within subsurface 

formations (Section 6.3). While the hydraulic fracturing operation may be designed so that the 

fractures will remain within the production zone, it is possible that, in the execution of the 

hydraulic fracturing treatment, fractures can extend beyond their designed extent. Four scenarios 

associated with induced fractures may contribute to fluid migration or communication between 

zones: 

• Flow of injected and/or displaced fluids through pore spaces in adjacent rock formations 

out of the production zone due to pressure differences and buoyancy effects. 

• Fractures extending out of oil/gas formations into drinking water resources or zones that 

are in communication with drinking water resources or fracturing into zones containing 

drinking water resources. 

• Fractures intersecting artificial structures, including active (producing) or inactive offset 

wells near the well that is being stimulated (i.e., well communication) or abandoned or 

active mines.

• Fractures intersecting geologic features that can act as pathways for fluid migration, such as 

existing permeable faults and fractures.

This chapter describes the conditions that can contribute to or cause the development of the 

pathways listed above, the evidence for the existence of these pathways, examples of impacts on the 

quality of drinking water resources associated with these pathways that have been documented in 

the literature, and the factors that can affect the frequency or severity of those impacts. (See 

Chapter 10 for a discussion of factors and practices that can reduce the frequency or severity of 

impacts to drinking water quality.)

The interplay between the well and the subsurface features is complex and not directly observable; 

therefore, sometimes it is not possible to identify what specific element is contributing to or is the 

primary cause of an impact on drinking water resources. For example, concerns have been raised 
Chapter 6 – Well Injection 

6-5 

regarding stray gas detected in groundwater in natural gas production areas (for additional 

information about stray gas, see Sections 6.2.2 and 6.3.2.4).1 Stray gas migration is a technically 

complex phenomenon, because there are many potential naturally occurring or artificially created 

routes for migration of gas into aquifers, including along production wells and via naturally existing 

or induced fractures. It is also challenging to determine the source of the natural gas and whether 

the mobilization is related to oil or gas production activities. 

Furthermore, identifying cases where contamination of drinking water resources occurs due to oil 

and gas production activities—including hydraulic fracturing operations—requires extensive 

amounts of site and operational data, collected before and after hydraulic fracturing operations. 

(See Section 6.4 for additional information on data limitations.) Where such data do exist and 

provide evidence of contamination, we present it in the following sections. We do not attempt to 

predict which of these pathways is most likely to occur or to lead to a drinking water impact, or the 

magnitude of an impact that might occur as a result of migration via any single pathway, unless the 

information is available and documented based on collected data. However, a qualitative 

assessment of the factors that can affect the frequency or severity of impacts on drinking water 

quality associated with the well injection stage is possible; see Section 6.4. 

6.2 Fluid Migration Pathways Within and Along the Production Well

In this section, we discuss pathways for fluid movement along or through the production well used 

in the hydraulic fracturing operation. While these pathways can form during other times within the 

life of an oil and gas well, the repeated high pressure stresses exerted during hydraulic fracturing 

operations can make maintaining the mechanical integrity of the well more difficult (Council of 

Canadian Academies, 2014).2 Section 6.2.1 presents the purpose of the various well components 

and typical well construction configurations. Section 6.2.2 describes the pathways for fluid 

movement that can potentially develop within the production well and wellbore and the conditions 

that lead to pathway development, either as a result of the original design of the well, degradation 

over time or use, or hydraulic fracturing operations. 

While we discuss casing and cement separately, it is important to note that these are related—

inadequacies in one of these components can lead to stresses on the other. For example, flaws in 

cement may expose the casing to corrosive fluids. Furthermore, casing and cement work together in 

the subsurface to form a barrier to fluid movement, and it may not be possible to distinguish 

whether mechanical integrity problems are related to the casing, the cement, or both. For additional 

information on well design and construction, see Appendix D. 

6.2.1 Overview of Well Construction

Production wells are constructed to transport hydrocarbon resources from the reservoirs in which 

they are found to the surface. They are also used to isolate fluid-bearing zones (containing oil, gas, 

 

1 Stray gas refers to the phenomenon of natural gas (primarily methane) migrating into shallow drinking water resources 

or to the surface.

2 Mechanical integrity of a well refers to the absence of significant leakage within the injection tubing, casing, or packer 

(referred to as internal mechanical integrity) or outside of the casing (referred to as external mechanical integrity).
Chapter 6 – Well Injection 

6-6 

or fresh water) from each other. Multiple barriers (i.e., casing and cement) are often present, and 

they act together to prevent both horizontal fluid movement (in or out of the well) and vertical fluid 

movement (along the wellbore from deeper oil- or gas-bearing formations to drinking water 

resources). Proper design and construction of the casing, cement, and other well components in the 

context of the location of drinking water resources and maintaining mechanical integrity 

throughout the life of a well are necessary to prevent migration of hydraulic fracturing fluids and 

formation fluids into drinking water resources.

A well is a multiple-component system that typically includes casing, cement, and a completion 

assembly, and it may be drilled vertically, horizontally, or in a deviated orientation (Figure 6-1).1,2

These components work together to prevent unintended fluid movement into, out of, or along the 

well. Due to the presence of multiple barriers within the well and the geologic system in which it is 

placed, the existence of a pathway for fluid movement through a component of this system does not 

necessarily mean that an impact on a drinking water resource has occurred or will occur. 

Figure 6-1. Schematic cross-section of general types of oil and gas resources and the

orientations of production wells used in hydraulic fracturing.

 

1 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. 

2 For the purposes of this assessment, a well’s orientation refers to its inclination from verticality. Wells drilled straight 

downward are considered to be vertical, wells drilled directionally to end up parallel to the production zone’s bedding 

plane are considered horizontal, and directionally drilled wells that are neither vertical nor horizontal are referred to as 

deviated. In industry usage, a well’s orientation commonly refers both to its inclination from vertical and the azimuthal 

(compass) direction of a directionally drilled wellbores. 
Chapter 6 – Well Injection 

6-7 

Casing primarily acts as a barrier to lateral movement of fluids, and cement primarily acts as a 

barrier to unintended vertical movement of fluids. Together, casing and cement are important in 

preventing fluid movement into drinking water resources, and are the focus of this section. Figure 

6-2 illustrates the configurations and types of casing and cement and other features that may occur 

in oil and gas production wells. The figure depicts an idealized representation of the components of 

a production well; it is important to note that there is a wide variety in the design of hydraulically 

fractured oil and gas wells in the United States (U.S. EPA, 2015n), and the descriptions in the figure 

or in this chapter do not represent every possible well design.

6.2.1.1 Casing

Casing is steel pipe that is placed into the drilled wellbore to maintain the stability of the wellbore, 

to transport the hydrocarbons from the subsurface to the surface, and to prevent intrusion of other 

fluids into the well and wellbore (Hyne, 2012; Renpu, 2011). A long continuous section of casing is 

referred to as a casing string, which is composed of individual lengths of casing (known as casing 

joints) that are threaded together using casing collars. In different sections of the well, multiple 

concentric casing strings of different diameters can be used, depending on the construction of the 

well.

The presence of multiple layers of casing strings can isolate and protect geologic zones containing 

drinking water. In addition to conductor casing, which prevents the hole from collapsing during 

drilling, one to three other types of casing may be also present in a well. The types of casing include 

(from largest to smallest diameter) surface casing, intermediate casing, and production casing

(GWPC, 2014; Hyne, 2012; Renpu, 2011). One or more of any of these types of casing (but not 

necessarily all of them) may be present in a well. Surface casing often extends from the wellhead 

down to the base (i.e., the bottom or lowest part) of the drinking water resource to be protected. 

Wells also may be constructed with production liners, which are anchored or suspended from 

inside the bottom of the previous casing string. Production liners serve the same purpose as 

production casing but extend only to the end of the previous casing, rather than all the way to the 

surface. Wells may also have production tubing, which is used to transport the hydrocarbons to the 

surface. Tie-back liners may be used to extend a production liner to the surface when downhole 

pressure or corrosive conditions warrant additional protection of the intermediate or production 

casing.

Among the wells represented by the Well File Review (described in Text Box 6-1), between one and 

four casing strings were present (the Well File Review did not evaluate conductor casings). A 

combination of surface and production casings was most often reported, followed by a combination 

of surface, intermediate, and production strings. All of the production wells used in hydraulic 

fracturing operations in the Well File Review had surface casing, while approximately 39% of the 

wells (an estimated 9,100 wells) had intermediate casing, and 94% (an estimated 21,900 wells) had

production casing (U.S. EPA, 2015n).1, 2 

 

1 9,100 wells (95% confidence interval: 2,900 – 15,400 wells). 

2 21,900 wells (95% confidence interval: 19,200 – 24,600 wells). 
Chapter 6 – Well Injection 

6-8 

Figure 6-2. Overview of well construction.
Chapter 6 – Well Injection 

6-9 

Hydraulic fracturing operations impose a variety of stresses on the well components. In order to 

prevent the formation of pathways to drinking water resources, the casing should be designed with 

sufficient strength to withstand the stresses it will encounter during the installation, cementing, 

hydraulic fracturing, production, and post-production phases of the life of the well. These stresses, 

illustrated in Figure 6-3, include burst pressure (the interior pipe pressure that will cause the 

casing to burst), collapse pressure (the pressure applied to the outside of the casing that will cause 

it to collapse), tensile stress (the stress related to stretching exerted by the weight of the casing or 

tubing being raised or lowered in the hole), compression and bending (the stresses that result from 

pushing along the axis of the casing or bending the casing), and cyclic stress (the stress caused by 

frequent or rapid changes in temperature or pressure). While the injection stage represents a 

relatively brief portion of the life of a hydraulic fracturing well (Section 3.3), injection imposes the 

highest stresses the well is likely to encounter. 

Text Box 6-1. The Well File Review.

The EPA conducted a survey of onshore oil and gas production wells that were hydraulically fractured by nine 

oil and gas service companies in the continental United States between approximately September 2009 and 

September 2010. This effort, known as the “Well File Review,” produced two reports. The first report, Review 

of Well Operator Files for Hydraulically Fractured Oil and Gas Production Wells: Well Design and Construction

(U.S. EPA, 2015n) describes well design and construction characteristics and their relationships to the 

location of operator-reported drinking water resources and the number and relative location of constructed 

barriers (i.e., casing and cement) that can block pathways for potential subsurface fluid movement. A second 

report, Review of Well Operator Files for Hydraulically Fractured Oil and Gas Production Wells: Hydraulic 

Fracturing Operations (U.S. EPA, 2016c) presents information on hydraulic fracturing job characteristics and 

the reported use of casing pressure tests, annular pressure monitoring, surface treating pressure monitoring, 

and microseismic monitoring conducted before or during hydraulic fracturing operations; it also explores the 

roles of well mechanical integrity and induced fracture growth as they relate to the potential for subsurface 

fluid movement to intersect protected groundwater resources.

The survey was based on a sample of 323 hydraulically fractured oil and gas production wells. Results of the 

research are presented as rounded estimates of the frequency of occurrence of hydraulically fractured 

production well design, construction, and operational characteristics with 95% confidence intervals (CIs). 

The results are statistically representative of an estimated 23,200 onshore oil and gas production wells 

hydraulically fractured in 2009 and 2010 by nine service companies where an estimated 28,500 hydraulic 

fracturing jobs were performed.

In addition, the casing must be resistant to corrosion from contact with the formations and any 

fluids that might be transported through the casing, including hydraulic fracturing fluids, brines, 

and oil or gas. Casing strength or corrosion resistance can be increased by using fiberglass or highstrength alloys or by increasing the thickness of the casing. 

One way to ensure that the strength of the casing is sufficient to withstand the stresses imposed by 

hydraulic fracturing operations is to pressure test the casing. The casing can be pressurized to the 

pressure anticipated during hydraulic fracturing operations and shut-in periods; if the well can 

hold the pressure, it is considered to be leak-free and therefore should be able to withstand the 

pressures of hydraulic fracturing. However, if the test pressure is less than the hydraulic fracturing 
Chapter 6 – Well Injection 

6-10 

pressure, the casing is determined to be leak-free, but its suitability to resist the stresses associated 

with the planned fracturing operation is less certain.

The Well File Review (U.S. EPA, 2016c) found that pressure tests were performed prior to an 

estimated 15,600 of 28,500 hydraulic fracturing jobs the EPA studied, including cases where a frac 

string was pressure tested.1 In 52% of those pressure tests performed (representing 28% of the 

hydraulic fracturing jobs studied), the well was tested to a pressure equal to or greater than the 

maximum pressure that occurred during the hydraulic fracturing job (U.S. EPA, 2016c).2 Thus, in a 

significant number of hydraulic fracturing jobs (i.e., 72% of the wells studied), there are no data in 

the well files to indicate that the casing was tested in a manner that could ensure the adequacy of 

the casing to withstand the pressures of hydraulic fracturing. While, in some cases, casing may not 

have been pressure tested because a frac string was to be installed to protect the casing from the 

increased pressure, only 10% of fracturing jobs were conducted using a frac string.

Figure 6-3. The various stresses to which the casing will be exposed. 

In addition to the stresses illustrated, the casing will be subjected to bending and cyclic stresses. Source: U.S. EPA 

(2012d). 

 

1 15,600 jobs (95% confidence interval: 11,800 – 19,300 jobs).

2 52% of pressure tests (95% confidence interval: 20 – 82% of tests). 
Chapter 6 – Well Injection 

6-11 

6.2.1.2 Cement

Cement is one of the most important components of a well for providing zonal isolation and 

reducing impacts on drinking water. Cement in the space between the casing and formation isolates 

fluid-containing formations from each other, protects the casing from exposure to formation fluids, 

and provides additional strength to the casing. The strength of the cement and its compatibility 

with the formation and fluids encountered are important for maintaining mechanical integrity 

throughout the life of the well.

A variety of methods are available for placing the cement, evaluating the adequacy of the cementing 

process and the resulting cement job, and repairing any identified deficiencies. Cement is most

commonly emplaced by pumping the cement down the inside of the casing to the bottom of the 

wellbore and then up the space between the outside of the casing and the formation (or the next 

largest casing string). This method is referred to as the primary cement job and can be performed 

as a continuous event in a single stage (i.e., “continuous cementing”) or in multiple stages (i.e., 

“staged cementing”). Staged cementing may be used when, for example, the estimated weight and 

pressure associated with standard cement placement could damage weak zones in the formation

(Crook, 2008). 

Deficiencies in the cementing process can result from poorly centered casing, poor removal of 

drilling mud behind the casing, cement shrinkage, premature gelation, excessive fluid loss, 

improper mixing, or lost cement.1, 2 Cement deficiencies can be reduced by proper design of the 

cementing process including use of casing centralizers, proper design of the cement, proper mud 

removal, and use of cement additives (Kirksey, 2013).3 If any deficiencies or defects in the primary 

cement job are identified, remedial cementing may be performed. See Text Box 6-2 for an example 

of an incident where cementing issues were studied as part of an evaluation of drinking water well 

impacts. 

Text Box 6-2. Dimock, Pennsylvania.

In 2009, shortly after drilling and hydraulic fracturing in the Marcellus Shale commenced in the area,

residents near the township of Dimock, Pennsylvania reported that natural gas was appearing or increasing 

in their water wells (Hammond, 2016; PA DEP, 2009a). 

Water wells in the area largely draw from the Catskill Formation and range in depth from less than 50 ft (15 

m) to more than 500 ft (150 m) (Molofsky et al., 2013). In this area, the Marcellus Shale is about 7,000 ft

(2,000 m) below the surface and its natural gas is extracted through vertical and horizontal wells (Hammond, 

2016). Methane exists naturally in the subsurface in this part of Pennsylvania, including in the Catskill 

Formation and the geologic formations below it (Baldassare et al., 2014; Molofsky et al., 2013; Molofsky et al., 

2011). 

(Text Box 6-2 is continued on the following page.)

 

1 Gelation is the process in the setting of the cement where it begins to solidify and lose its ability to transmit pressure to

the formation.

2 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. 

3 Centralizers are used to keep the casing in the center of the hole and allow an even cement job.
Chapter 6 – Well Injection 

6-12 

Text Box 6-2 (continued). Dimock, Pennsylvania.

The Pennsylvania Department of Environmental Protection (PA DEP) investigated and made a determination 

that 18 water wells located within a 9 mi2 (23 km2) area had been negatively affected as a result of natural gas 

extraction activities. For approximately two years, during which there was a partial ban on gas well drilling 

and hydraulic fracturing in the vicinity, the gas company plugged four gas wells and undertook remedial 

construction actions at 18 additional gas wells (including remedial cementing at several wells, adding as 

much as 6,300 ft (1,900 m) of cement behind the production casings) (PA DEP, 2010b, d, 2009a). 

The figure below presents a simplified geologic representation of water wells and one type of horizontal gas 

well completed within the geologic formations in the area. The location of remedial cementing performed in 

some gas wells is indicated.

Several studies in this and surrounding areas have focused on the geochemistry of the groundwater, in 

particular on gas composition, and noble and natural gas isotopes in the water. Results are consistent with an 

accumulation of stray gas originating from greater depth and moving to the Catskill Formation (Jackson et al., 

2013c; Molofsky et al., 2013; Molofsky et al., 2011). However, the identity of the geologic formation(s) 

sourcing the natural gas is not always certain and may be consistent with sourcing from either the Marcellus 

(as suggested by Jackson et al. (2013c)), or the intervening geologic formations (Molofsky et al., 2013). 

The role of hydraulic fracturing in the migration of gas to the Catskill Formation, and the specific pathways by 

which this migration occurred, is even less certain. Some investigators suspect that the initial gas well 

construction allowed natural gases from deeper formations to move upward along uncemented wellbores 

(Hammond, 2016; PA DEP, 2010b, d, 2009a). However, no publicly available information exists to document 

whether hydraulic fracturing may have aided fluid movement along wellbores to enter drinking water 

resources from greater depths. Reviews of information, such as hydraulic fracturing job reports showing the 

intervals hydraulically fractured, injection rates, and pressure monitoring, would support an evaluation of 

whether hydraulic fracturing might have played a role in the migration of natural gas to drinking water wells 

in the area.
Chapter 6 – Well Injection 

6-13 

Among the wells represented in the Well File Review, over 90% of cemented casings were 

cemented using primary cementing methods. Secondary or remedial cementing was used on an 

estimated 8% of casings (most often on surface and production casings and less often on 

intermediate casings).1 The remedial cementing techniques employed in these wells included 

cement squeezes, cement baskets, and pumping cement down the annulus (U.S. EPA, 2015n). See 

Appendix D for more information on remedial cementing techniques.

The cement does not always need to be continuous along the entire length of the well to protect 

drinking water resources; rather, protection of drinking water resources depends on a good cement 

seal across the appropriate subsurface zones, including all fresh water- and hydrocarbon-bearing 

zones. One study of wells in the Gulf of Mexico found that, if at least 50 ft (15 m) of high quality 

cement was present, pressure differentials as high as 14,000 psi (97 MPa) would not lead to 

breakdown in isolation between geologic zones (King and King, 2013). 

Most wells have cement behind the surface casing, which is a key barrier to contamination of 

drinking water resources. The surface casings in nearly all of the wells used in hydraulic fracturing 

operations represented in the Well File Review (93% of the wells, or an estimated 21,500 wells) 

were fully cemented.2,3 None of the wells studied in the Well File Review had completely 

uncemented surface casings. 

The length and location of cement behind intermediate and production casings can vary based on 

the presence and locations of over-pressured formations, formations containing fluids, or 

geologically weak formations (i.e., those that are prone to structural failure when exposed to 

changes in subsurface stresses). State regulations and economics also play a role. 

In the Well File Review, the intermediate casings of most of the wells studied were fully cemented, 

although there were relatively wide 95% confidence intervals in the results. Among production 

casings, about half were partially cemented, about a third were fully cemented, and the remainder 

were either uncemented or their cementing status was undetermined. Among the approximately 

9,100 wells represented in the Well File Review that are estimated to have intermediate casing, the 

intermediate casing was fully cemented in an estimated approximately 7,300 wells (80%) and 

partially cemented in an estimated 1,700 wells (19%).4,5 Production casings were partially 

cemented in 47% of the wells, or approximately 10,900 wells (U.S. EPA, 2015n).6 

 

1 8% of casings (95% confidence interval: 3% – 14% of casings).

2 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. 

3 21,500 wells (95% confidence interval: 19,500 – 23,600 wells). 

4 9,100 wells (95% confidence interval: 2,900 – 15,400 wells).

5 7,300 wells (95% confidence interval: 600 – 13,900 wells).

6 10,900 wells (95% confidence interval: 6,900 – 14,900 wells).
Chapter 6 – Well Injection 

6-14 

The Well File Review also estimated the number of wells with a continuous cement sheath along the 

outside of the well. An estimated 6,800 of the wells represented in the study (29%) had cement 

from the bottom of the well to the ground surface, and approximately 15,300 wells (66%) had one 

or more uncemented intervals between the bottom of the well and the surface.1,2 In the remaining 

wells, the location of the top of the cement was uncertain, so no determination could be made 

regarding whether the well had a continuous cement sheath along the outside of the well (U.S. EPA, 

2015n). 

A variety of logs are available to evaluate the quality of cement behind the well casing. Among wells 

in the Well File Review, the most common type of cement evaluation log run was a standard 

acoustic cement bond log (U.S. EPA, 2015n). Standard acoustic cement bond logs are used to 

evaluate both the extent of the cement placed along the casing and the cement bond between the 

cement, casing, and wellbore. Cement bond indices calculated from standard acoustic cement bond 

logs on the wells in the Well File Review showed a median bond index of 0.7 just above the 

hydraulic fracturing zone; this value decreased to 0.4 over a measured distance of 5,000 ft (2,000

m) above the hydraulic fracturing zone (U.S. EPA, 2015n).3 While standard acoustic cement bond 

logs can give an average estimate of bonding, they cannot alone indicate zonal isolation, because 

they may not be properly run or calibrated (Boyd et al., 2006; Smolen, 2006). One study of 28 wells 

found that cement bond logs failed to predict communication between formations 11% of the time

(Boyd et al., 2006). In addition, they cannot discriminate between full circumferential cement 

coverage by weaker cement and lack of circumferential coverage by stronger cement (King and 

King, 2013; Smolen, 2006). A few studies have compared cement bond indices to zonal isolation, 

with varying results. For example, Brown et al. (1970) showed that among 16 South American wells 

with varying casing size and cement bond indices, a cemented 5.5 in (14 cm) diameter casing with a 

bond index of 0.8 along as little as 5 ft (1.5 m) can act as an effective seal. The authors also suggest 

that an effective seal in wells having calculated bond indices differing from 0.8 are expected to have 

an inverse relationship between bond index and requisite length of the cemented interval, with 

longer lengths needed along casing having a lower bond index. Another study recommends that 

wells undergoing hydraulic fracturing should have a given cement bond over an interval three 

times the length that would otherwise be considered adequate for zonal isolation (Fitzgerald et al., 

1985). Conversely, King and King (2013) concluded field tests from wells studied by Flournoy and 

Feaster (1963) had effective isolation when the cement bond index ranged from 0.31 to 0.75. 

External mechanical integrity tests (MITs), including temperature logs, noise logs, and radioactive 

tracer logs, are another means to evaluate the zonal isolation performance of well cement. Instead 

of measuring the apparent quality of the cement, external MITs measure whether there is evidence 

of fluid movement along the wellbore (and potentially to a drinking water resource). An external 

MIT conducted before the hydraulic fracturing job can allow detection of channels in the cement 

that could allow injected fluids to move out of the production zone. An external MIT performed 

 

1 6,800 wells (95% confidence interval: 1,600 – 11,900 wells). 

2 15,300 wells (95% confidence interval: 10,500 – 20,100 wells). 

3 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. 
Chapter 6 – Well Injection 

6-15 

after hydraulic fracturing operations can detect any fluid movement resulting from cement damage 

caused by the hydraulic fracturing job. 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 mechanical integrity is an event 

that can result in fluid movement from the well if remediation is not performed. More details on 

MITs are available in Appendix D.

Monitoring the treatment pressure of the hydraulic fracturing operation can also detect problems 

occurring during fracturing. Sudden changes in pressure during hydraulic fracturing operations can 

be indicative of failures in the cement or casing. This type of monitoring is performed in nearly all 

hydraulic fracturing jobs: the Well File Review (U.S. EPA, 2016c) found that the treatment pressure 

was monitored in 97% (or 27,700) of all hydraulic fracturing jobs studied.1

6.2.1.3 Well Orientation

A well can be drilled and constructed with any of several different orientations: vertical, horizontal, 

and deviated. The well’s orientation can be important, because it affects the difficulty of drilling, 

constructing, and cementing the well. In particular, as described in Section 6.2.2, constructing and 

cementing horizontal wells present unique challenges (Sabins, 1990). In a vertical well, the 

wellbore is vertical throughout its entire length, from the wellhead at the surface to the production 

zone. Deviated wells are usually drilled vertically in the shallowest part of the well but are then 

drilled directionally, deviating from the vertical direction at some point such that the bottom of the 

well is at a significant lateral distance away from the point in the subsurface directly under the 

wellhead. In a horizontal well, the well is drilled vertically to a point known as the kickoff point, 

where the well turns toward the horizontal, extending into and parallel with the approximately 

horizontal targeted producing formation (Figure 6-2). 

Among wells evaluated in the Well File Review, about 65% were vertical, 11% were horizontal, and 

24% were deviated wells (U.S. EPA, 2015n).2This is generally consistent with information available 

in industry databases—of the approximately 16,000 oil and gas wells used in hydraulic fracturing 

operations in 2009 (one of the years for which the data for the Well File Review were collected), 

39% were vertical, 33% were horizontal, and 28% were either deviated or the orientation was 

unknown (DrillingInfo, 2014b). See Section 3.3 for additional information on the use of horizontal 

wells in the United States.

6.2.1.4 Well Completion

Another important aspect of well construction is the way in which the well is completed into the 

production zone, because the well’s completion is part of the system of barriers and must be intact 

for the well to operate properly. A variety of completion configurations are available. The most 

common configuration is for casing to extend to the end of the wellbore and be cemented in place

(U.S. EPA, 2015n; George et al., 2011; Renpu, 2011). In these cased and cemented completions, the 

 

1 27,700 jobs (95% confidence interval: 24,800 – 30,600 jobs). 

2 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.
Chapter 6 – Well Injection 

6-16 

cement provides the primary containment of fluids to the production zone. Before hydraulic 

fracturing begins, perforations are made through the casing and cement into the production zone. It 

is through the perforated casing and cement that hydraulic fracturing is conducted. In some cases, a

smaller temporary casing, known as a temporary frac string, is inserted inside the production 

casing to protect the casing from the high pressures imposed during hydraulic fracturing 

operations. 

A different type of a cased completion uses production casing set on formation packers, where the 

production casing extends through the production zone and the length of the casing extending 

through the drilled horizontal wellbore is left uncemented, but has a series of formation packers 

that swell to seal the annulus between the casing and the formation.1 With these completions, the 

production zone is fractured in separate stages through ports that open between the formation 

packers. When formation packers are used, they provide the primary isolation of hydraulic 

fracturing fluids during hydraulic fracturing.

Another type of completion is an open hole completion. When open hole completions are used, the 

entire production zone is fractured all at once in a single stage or may be fractured in separate 

stages using a temporary frac string set on one or more temporary formation packers that are 

positioned to a different interval for each stage. If a temporary frac string is used in an open hole 

completion, its packer(s) provide the primary isolation of hydraulic fracturing fluids during 

hydraulic fracturing and if no temporary frac string is used, then the next higher casing in the well 

provides the primary isolation of hydraulic fracturing fluids during the treatment.

Among wells represented in the Well File Review, an estimated 6% of wells (1,500 wells) had open 

hole completions, 6% of wells (1,500 wells) used formation packers, and the rest were cased and 

cemented (U.S. EPA, 2015n).2,3 

In some cases, wells may be re-completed after the initial construction, with re-fracturing if 

production has decreased (Vincent, 2011). Re-completion also may include additional perforations 

in the well at a different interval to produce from a new formation, lengthening the wellbore, or 

drilling new laterals from an existing wellbore. In 95% of the re-completions represented in the 

Well File Review, hydraulic fracturing occurred at shallower depths than the previous job (U.S. EPA, 

2016c).4

6.2.2 Factors that can Affect Fluid Movement to Drinking Water Resources 

The following sections describe the pathways for fluid movement that can develop within the 

production well and wellbore. We also describe the conditions leading to the development of fluid 

movement pathways and, where available, evidence that a pathway has allowed fluid movement to 

 

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 uncemented casing and formation, 

preventing migration of fluids. 

2 1,500 wells with open hole completions (95% confidence interval: 10 – 4,800 wells). 

3 1,500 wells using formation packers (95% confidence interval: 1,400 – 1,600 wells). 

4 95% of jobs (95% confidence interval: 75 – 99% of jobs).
Chapter 6 – Well Injection 

6-17 

occur within the casing or cement, and—in the case of sustained casing pressure (Section 6.2.2.4)—

a combination of factors within the casing and cement. (See Figure 6-4 for an illustration of 

potential fluid movement pathways related to casing and cement.) 

Figure 6-4. Potential pathways for fluid movement in a cemented wellbore.

These pathways (represented by the white arrows) include: (1) casing and 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, and (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. 
Chapter 6 – Well Injection 

6-18 

We describe information regarding the rate at which these pathways have been identified in 

hydraulic fracturing wells when it is available. Where such information does not exist, we present

the results of research on oil and gas production wells in general or on injection wells, including 

those used for the geologic sequestration of carbon dioxide.1 Publicly accessible information is 

insufficient to determine whether wells intended for hydraulic fracturing are constructed 

differently from production wells where no fracturing is conducted. See Chapter 10 for additional 

discussion of data gaps. It is not generally possible, based on the literature reviewed for this 

assessment, to determine the precise degree to which hydraulic fracturing created, or moved fluids 

along, the pathways described or whether all of the wells studied were hydraulically fractured. Nor 

is it generally possible to estimate the degree to which wells that were hydraulically fractured have 

a significantly different number of redundant barriers to protect drinking water resources than 

other production wells. However, given the applicability of well construction technology to address 

the subsurface conditions encountered in hydraulic fracturing operations and production or 

injection operations in general, the information presented here is considered relevant to the 

assessment.

6.2.2.1 Pathways Related to Well Casing

High pressures associated with hydraulic fracturing operations can damage casing and lead to fluid 

movement that can impact drinking water quality. As noted above, the casing string through which 

hydraulic fracturing fluids are injected is subject to higher internal pressures during hydraulic 

fracturing operations than during other phases in the life of a production well. To withstand the 

stresses created by the high pressure of hydraulic fracturing, the well and its components must 

have adequate strength and elasticity. If the casing is compromised or is otherwise not strong 

enough to withstand these stresses (Figure 6-3), a casing failure can result. If undetected or not 

repaired, casing failures can serve as pathways for hydraulic fracturing fluids to leak out of the 

casing. Below we present data or information suggesting that pathways along the casing are 

present or allowing fluid movement. See Chapter 10 for more information on factors that can 

increase or decrease the frequency or severity of impacts to drinking water quality associated with 

well construction. 

Hydraulic fracturing fluids or fluids present within the well casing could flow into other zones in 

the subsurface if there is a leak in the casing, and cement is inadequate or not present. As described 

below, pathways for fluid movement associated with well casing can be related to the original 

design or construction of the well, degradation of the casing over time, or problems that can arise 

through extended use as the casing succumbs to stresses.

Casing failure can also occur if the wellbore passes through a structurally weak geologic zone that 

shears and deforms the well casing. Such shearing is common when drilling through zones 

containing salt (Renpu, 2011). The changes in the pressure field in the portions of the formation 

near the wellbore during hydraulic fracturing can also cause mechanically weak formations to 

shear, potentially damaging the well’s casing or cement. Palmer et al. (2005) demonstrated through 

modeling that hydraulic fracturing within coal that had a low unconfined compressive strength 

 

1 An injection well is a well into which fluids are being injected (40 Code of Federal Regulations (CFR) 144.3).
Chapter 6 – Well Injection 

6-19 

could cause shear failure of the coalbeds surrounding the wellbore. Shearing of the coalbed layers 

can cause the casing to deform and potentially fail.

Corrosion in uncemented zones is the most common cause of casing failure. This can occur if 

uncemented sections of the casing are exposed to corrosive substances such as brine or hydrogen 

sulfide (Renpu, 2011). Corrosion commonly occurs at the collars that connect sections of casing or 

where equipment is attached to the casing. Corrosion at collars can exacerbate problems with loose 

or poorly designed connections, which are another common cause of casing leaks (Agbalagba et al., 

2013; Brufatto et al., 2003). Watson and Bachu (2009) found that 66% of all casing corrosion

occurred in uncemented well sections, as shown in Pathway 1 of Figure 6-4. 

As noted above, the casing and cement work together to strengthen the well and provide zonal 

isolation. Uncemented casing does not necessarily lead to fluid migration. However, migration can 

occur if the casing in an uncemented zone fails during hydraulic fracturing operations. 

Other mechanical integrity problems have been found to vary with the well environment, 

particularly environments with high pressures and temperatures. Wells in high pressure/high 

temperature environments, wells with thermal cycling, and wells in corrosive environments can 

have life expectancies of less than 10 years (Agbalagba et al., 2013). 

The depth of the surface casing relative to the base of the drinking water resource to be protected is 

an important factor in protecting the drinking water resource. In a limited risk modeling study of 

selected injection wells in the Williston Basin, Michie and Koch (1991) found the risk of aquifer 

contamination from leaks from the inside of the well to the drinking water resource was seven in 

1,000,000 injection wells if the surface casing was set deep enough to cover the drinking water 

resource, and that the risk increased to six in 1,000 wells if the surface casing was not set deeper 

than the bottom of the drinking water resource. An example where surface casing did not extend 

below drinking water resources comes from an investigation of 14 selected drinking water wells 

with alleged water quality problems in the Wind River and Fort Union formations near Pavillion,

Wyoming (WYOGCC, 2014b). The state found that the surface casing of oil and gas wells was 

shallower than the depth of three of the 14 drinking water wells. Some of the oil and gas wells with 

shallow surface casing had elevated gas pressures in their annuli (WYOGCC, 2014b). The presence 

of gas in the annuli, combined with surface casing that is set above the lowest drinking water 

resource, could allow migration of gas into drinking water resources.

Fleckenstein et al. (2015) found that the depth of surface casing and the presence of uncemented 

gas zones are major factors in determining the likelihood of well failures and contamination. Their 

study in the Wattenberg field in Colorado classified the wells in the field into seven categories 

based on the depth of surface casing, the presence of cement, and the presence of intermediate gas 

zones above the production zone (Table 6-1). The categories were arranged in order of risk, with 

category 1 wells being at the highest risk of allowing fluid migration and category 7 wells being the 

least likely to allow migration. The overall barrier failure rate was 2.4% of all wells, and the overall 

catastrophic failure rate was 0.06% of all wells. A remediation effort was made in order to decrease 

the likelihood of fluid migration, which included the plugging of 1,103 of the 17,948 wells studied. 

All the wells shown in the table are vertical wells that were drilled between 1970 and 2013. Similar 
Chapter 6 – Well Injection 

6-20 

categories were created for the 973 horizontal wells in the field. No failures were recorded for any 

of the horizontal wells. 

Table 6-1. Failure rates of vertical wells in the Wattenberg field, Colorado.

From Fleckenstein et al. (2015). 

Category and descriptiona, b Total wells 

Wells with 

barrier 

failuresc

Wells with 

catastrophic 

failuresd

1--Shallow surface casing and exposed (uncemented) overpressured intermediate gas zones399 92 (23.06%) 3 (0.75%)

2 – Shallow surface casing and exposed under-pressured

intermediate gas zones

7,811 276 (3.53%) 6 (0.08%)

3 – Shallow surface casing but no exposed gas zones 3,407 20 (0.59%) 1 (0.03%)

4 – Shallow surface casing with production casing cemented 

to bottom of surface casing

1,063 0 (0%) 0 (0%)

5 – Deep surface casing with production casing cement below 

top of gas 

1,374 13 (0.95%) 0 (0%)

6 – Deep surface casing with production casing cement above 

top of gas

2,069 0 (0%) 0 (0%)

7 – Deep surface casing with production casing cement to 

bottom of surface casing

705 0 (0%) 0 (0%)

Total 16,828 401 (2.4%) 10 (0.06%)

a The study defined shallow surface casing as casing that did not extend below the Fox Hills Aquifer, a deep aquifer that had not 

been identified and protected by the state prior to 1994. 

b Uncemented zones could be located along the intermediate or production casings.

c Barrier failures were considered to have occurred when there were signs of a failure, but no contamination. 

d A catastrophic failure was considered to have occurred where there was contamination of drinking water aquifers (i.e., the 

presence of thermogenic gas in a drinking water well) and evidence of a well defect such as exposed intermediate gas zone or 

casing leaks.

Sherwood et al. (2016) examined complaint records in the same field. They reviewed 29 Colorado 

Oil and Gas Commission complaint records associated with 32 incidents at 42 drinking water wells 

in which thermogenic methane was detected. (See Text Box 6-3 for more information on 

thermogenic and biogenic methane.) Of the 29 complaints, 10 were determined to be caused by oil 

and gas wellbore failures, one was suspected of being a wellbore failure but not confirmed, three 

were settled in court with documents being sealed, and the remaining 15 were unresolved.1 If all 32 

cases are assumed to be associated with an individual oil and gas well, that would result in a failure 

rate of 0.06% of all oil and gas wells in the basin, the same failure rate as found in the Fleckenstein 

et al. (2015) study. As in the Fleckenstein study, surface casing that was set too shallow and 

1 This paper defined a wellbore failure as the failure of one or more barriers to fluid movement in the wellbore (e.g., 

cement, casing, etc.).
Chapter 6 – Well Injection 

6-21 

uncemented intermediate zones were the main contributing factors to wellbore failure. All 11 of the 

confirmed or suspected wellbore failures involved vertical wells that were drilled before 1933 and 

had surface casing shallower than nearby aquifers. Of these wells, seven had been hydraulically 

fractured. The study noted that the failure rate was fairly constant over time with about two new 

cases per year since 2000 and that the rate had not changed since high rates of hydraulic fracturing 

of horizontal wells became prevalent around 2010. This is consistent with the study’s finding of no 

failures in horizontal wells.

During hydraulic fracturing operations in September of 2010 near Killdeer, in Dunn County, North 

Dakota, the production, surface, and conductor casing of the Franchuk 44-20 SWH well ruptured, 

causing fluids to spill to the surface (Jacob, 2011). The rupture occurred during the 5th of 

23 planned stages of hydraulic fracturing when the pressure spiked to over 8,390 psi (58 MPa). 

Ruptures were found in two locations along the production casing―one just below the surface and 

one at about 55 ft (17 m) below ground surface. The surface casing ruptured in three places down 

to a depth of 188 ft (57 m), and the conductor casing ruptured in one place. Despite a shutdown of 

the pumps, the pressure was still sufficient to cause fluid to travel through the ruptured casings and 

to flow to the surface. Ultimately, over 166,000 gal (628,000 L) of fluids and approximately 

2,860 tons (2,595 metric tons) of contaminated soil were removed from the site (Jacob, 2011). 

The EPA investigated the Killdeer site as part of its Retrospective Case Study in Killdeer, North 

Dakota: Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources (U.S. 

EPA, 2015i). As part of the study, water quality samples were collected from three domestic wells, 

nine monitoring wells, two supply wells, one municipal well, and one state well in July 2011, 

October 2011, and October 2012. Two study wells installed less than 60 ft (20 m) from the 

production well (NDGW08 and NDGW07) had significant differences in water quality compared to 

the remaining study wells.1 These two wells showed differences in ion concentrations (e.g., 

chloride, calcium, magnesium, sodium, strontium) and tert-butyl alcohol (TBA). The sampling 

identified brine contamination that was consistent with mixing of local groundwater with brine 

from Madison Group formations, which the well had penetrated. The TBA was consistent with 

degradation of tert-butyl hydroperoxide, a component of the hydraulic fracturing fluid used in the 

Franchuk well. Based on the analysis of potential sources of contamination, the EPA determined 

that the only potential sources of TBA were gasoline spills, leaky underground storage tanks, and 

hydraulic fracturing fluids. However, the lack of MTBE and other signature compounds associated 

with gasoline or fuels strongly suggests that the rupture (blowout) was the only source consistent 

with findings of high brine and TBA concentrations in the two wells.2 For additional information 

about impacts at the Killdeer site, see Section 6.3.2.2.

 

1 Based on comparison with historical Killdeer aquifer water quality data, the remaining study wells were in general 

consistent with historical background data; these wells were then used for the data analysis as background wells. 

Comparisons of TBA between the study data and historical data could not be made since no historical data for TBA were 

found for the Killdeer aquifer.

2 A well blowout is the uncontrolled flow of fluids out of a well.
Chapter 6 – Well Injection 

6-22 

Inadequate casing or cement can respond poorly when blowout preventers activate.1When

blowout preventers are activated, they immediately stop the flow in the well, which can create a 

sudden pressure increase in the well. If the casing or cement are not strong enough to withstand 

the increased pressure when this occurs, well components can be damaged (The Royal Society and 

the Royal Academy of Engineering, 2012) and the potential for fluid release and migration in the 

subsurface increases. Blowouts can also occur during the production phase, and cause spills on the 

surface that can affect drinking water resources; see Section 7.4.2.2. 

While well construction and hydraulic fracturing techniques continue to change, the pressure- and 

temperature-related stresses associated with hydraulic fracturing remain as factors that can affect 

the integrity of the well casing. Tian et al. (2015) investigated one such case where temperature 

effects led to casing damage in China. In the Changning-Weiyuan basin in China, 13 of 33 wells 

(39.4%) suffered casing damage, with most of the wells experiencing the damage after fracturing. 

The authors found that injection of the cooler hydraulic fracturing fluid led the casing temperature 

to drop from the formation temperature of 212°F to 64°F (100°C to 18°C) in some cases. This drop 

in temperature, in turn, caused pockets of high pressure fluid outside the casing to contract. If the 

temperature dropped below 136°F (58°C), the effect was sufficient to form a vacuum outside the 

casing, potentially leading to casing deformation. Areas of the casing with severe doglegs (i.e., bends 

in the well) and where there was a smaller space between the casing and formation were more 

prone to this type of damage. While the conditions in this Chinese basin may or may not represent 

conditions in U.S. basins, they do demonstrate that temperature changes during hydraulic 

fracturing can place additional stress on the well and highlight their importance as a consideration 

in casing design. In the case mentioned, increasing the space around the casing, decreasing dogleg 

angles, properly removing drilling mud, and using high strength, low elasticity cement were found 

to improve performance.

Sugden et al. (2013) used numerical simulation to examine a similar problem using parameters 

chosen to represent the Haynesville Shale. They found that injecting a fluid at 70°F (21°C) could 

cool the wellbore temperature from 320°F to 96°F (160°C to 36°C). The temperature change was 

90% complete within the first half hour of hydraulic fracturing operations. They also found that a 

well with a 20 degree per 100 ft (31 m) dogleg decreased the pressure required to damage the well 

casing by 850 psi (5.9 MPa). The study also reported that cooling of fluids in voids in the cement can 

lead to contraction of the fluids. In low permeability shales, fluid cannot flow in fast enough to 

compensate, and the pressure in the void can drop significantly. Sugden et al. (2013) report that 

such cement voids can reduce the pressure needed to rupture the casing by 40%. 

Emerging isotopic techniques can be used to identify the extent to which stray gas occurring in 

drinking water resources is linked to casing failure. (See Text Box 6-3 for more information on stray 

gas.) Darrah et al. (2014) used hydrocarbon and noble gas isotope data to investigate the source of 

gas in eight identified “contamination clusters” that occurred in the Marcellus and Barnett shales. 

Seven of these clusters were stripped of atmospheric gases (Argon-36 and Neon-20) and were 

 

1 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.
Chapter 6 – Well Injection 

6-23 

enriched in crustal gases, indicating the gas migrated quickly from depth without equilibrating with 

intervening formations. The rapid transport was interpreted to mean that the migration did not 

occur along natural fractures or pathways, which would have allowed equilibration to take place. 

Based on the isotopic results, the authors also ruled out the possibility that the gas was carried 

upward (relative to the surface) as the geologic formation in which it formed was uplifted over 

geologic time. Possible explanations for the rapid migration include transport up the well and 

through a leaky casing (Pathway 1 in Figure 6-4) or along uncemented or poorly cemented 

intervals from shallower depths (Pathways 2 through 5 in Figure 6-4). In four Marcellus Shale 

clusters, gas found in drinking water wells had isotopic signatures and ratios of ethane to methane 

that were consistent with those in the producing formation. The authors conclude that this suggests 

that gas migrated along poorly constructed wells from the producing formation, likely with 

improper, faulty, or failing production casings. In three clusters, the isotopic signatures and ethane 

to methane ratios were consistent with formations overlying the Marcellus. The authors suggest 

that this migration occurred from the shallower gas formations along uncemented or improperly 

cemented wellbores. In another Marcellus cluster in the study, deep gas migration was linked to a 

subsurface well, likely from a failed well packer.

Text Box 6-3. Stray Gas Migration.

Stray gas refers to the phenomenon of natural gas (primarily methane) migrating into shallow drinking water 

resources, into water wells or other types of wells, to the surface, or to near-surface features (e.g., basements, 

streams, or springs). The source of the migrating gas can be natural gas reservoirs (either conventional or 

unconventional), or from coal mines, landfills, leaking gas wells, leaking gas pipelines, buried organic matter, 

or natural microbial processes (Li and Carlson, 2014; Baldassare, 2011). Although methane is not a regulated 

drinking water contaminant, its presence in drinking water resources can initiate chemical and biological 

reactions that release or mobilize other contaminants. Over time, it can promote more reducing conditions in 

groundwater, potentially leading to reductive dissolution of iron and manganese and the possible liberation 

of naturally occurring contaminants, such as arsenic, that are potentially associated with iron and manganese

(U.S. EPA, 2014f). In addition, methane can accumulate to explosive levels in confined spaces (like basements 

or cellars) if it exsolves (degases) from groundwater into those spaces. (See Section 9.5.5 for information 

about the hazards associated with methane exposure.) 

Detectable levels of dissolved natural gas exist in some aquifers, even in the absence of human activity 

(Gorody, 2012). In northern Pennsylvania and New York, low levels of methane are frequently found in water 

wells in baseline studies, prior to commercial oil or gas development (Christian et al., 2016; Kappel, 2013; 

Kappel and Nystrom, 2012); for example, one USGS study detected methane in 80% of sampled wells in Pike 

County, Pennsylvania (Senior, 2014). The origin of methane in groundwater 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). 

Gas occurrence is linked to local and regional geologic characteristics. In some cases, thermogenic methane 

occurs naturally in shallow formations because the formation itself was uplifted (relative to the surface) over 

geologic time. In other cases, it has migrated there via one or more pathways. For example, Brantley et al. 

(2014) suggest that northern Pennsylvania’s glacial history can help explain why stray gas is more common

(Text Box 6-3 is continued on the following page.)
Chapter 6 – Well Injection 

6-24 

Text Box 6-3 (continued). Stray Gas Migration.

there than in the southern part of the state. Christian et al. (2016), Mcphillips et al. (2014), Molofsky et al. (In 

Press), and Wilson (2014) all identified correlations between the presence of methane in water wells and 

certain geologic, hydrographic, and geochemical parameters, such as valley locations and the presence of coal

beds. 

Stray gas migration can be a technically complex phenomenon to study, in part because there are many 

potential sources and routes for migration. When a particular site lacks detailed monitoring data, especially 

baseline measurements, determination of sources and migration routes is complicated and challenging. 

Examining the concentrations and isotopic compositions of methane and higher molecular weight 

hydrocarbons such as ethane and propane can aid in determining the source of stray gas (Tilley and 

Muehlenbachs, 2012; Baldassare, 2011; Rowe and Muehlenbachs, 1999). Isotopic composition and 

methane-to-ethane ratios can help determine whether the gas is thermogenic or biogenic in origin and 

whether it is derived from shale or other formations (Gorody, 2012; Muehlenbachs et al., 2012; Barker and 

Fritz, 1981). Isotopic analysis can also be used to identify the strata where the gas originated and provide 

evidence for migration mechanisms (Darrah et al., 2014). For example, isotope-based techniques have been 

used to investigate the potential sources of methane in drinking water wells in Dimock, Pennsylvania 

(Hammond, 2016), and Jackson et al. (2013c) found evidence of potential Marcellus gas contamination in 

some Pennsylvania drinking water wells using stable-isotopic ratios, while other wells in the area appeared 

to be contaminated by shallower sources (not associated with gas production).

However, determining the source of methane does not necessarily establish the migration pathway. Multiple 

researchers (e.g., Siegel et al., 2015; Jackson et al., 2013c; Molofsky et al., 2013; Révész et al., 2012; Osborn et 

al., 2011) have described biogenic and/or thermogenic methane in groundwater supplies in Marcellus gas 

production areas, although the sources and pathways of migration are generally unknown. Well casing and

cementing issues may be an important source of stray gas problems (Jackson et al., 2013c); however, other 

potential subsurface pathways are also discussed in the literature. Zhang and Soeder (2016) suggested that 

air-drilling practices used to construct the vertical component of gas wells can affect methane migration by 

creating groundwater surges in the shallow subsurface. The type of well may also play a role; in one study, 

deviated gas wells in Canada were three to four times more likely than vertical wells to have evidence of gas 

migration to the surface (Jackson et al., 2013b). 

In the absence of data on specific pathways, some researchers have investigated geographic correlations. 

Jackson et al. (2013c) and Osborn et al. (2011) found that thermogenic methane concentrations in well water 

increased with proximity to Marcellus Shale production sites. In contrast, Molofsky et al. (2013) found the 

presence of gas to be more closely correlated with topography and elevation, and (Siegel et al., 2015)found no 

correlation between methane in groundwater and proximity to production wells. Kresse et al. (2012)

investigated methane concentration and isotopic geochemistry in shallow groundwater in the Fayetteville 

Shale area, and found no evidence that the water had been influenced by shale gas activities. Similarly, Li and 

Carlson (2014), while not ruling out potential leakage pathways from deeper reservoirs, found no systematic 

correlation between increasing well drilling density in the Wattenberg Field in Colorado and near-surface 

stray gas concentrations. 

EPA conducted retrospective case studies to investigate stray gas in northeastern Pennsylvania and the Raton 

Basin of Colorado. As described in the northeastern Pennsylvania case study report, Retrospective Case Study 

in Northeastern Pennsylvania: Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water 

Resources (U.S. EPA, 2014f), 27 of 36 drinking water wells within the study area (75%) contained elevated 

methane concentrations. For some of the wells, the EPA concluded that the methane (of both thermogenic 

and biogenic origin) was naturally occurring gas, not attributable to gas exploration activities. In others, it 

(Text Box 6-3 is continued on the following page.)
Chapter 6 – Well Injection 

6-25 

Text Box 6-3 (continued). Stray Gas Migration.

appeared that methane had entered the water wells following well drilling and hydraulic fracturing. In most 

cases, the methane in the wells likely originated from intermediate formations between the production zone 

and the surface; however, in some cases, the methane appears to have originated from deeper layers such as 

those where the Marcellus Shale is found (U.S. EPA, 2014f). The Raton Basin case study examined the Little 

Creek Field, where potentially explosive quantities of methane entered drinking water wells in 2007. As 

described in the EPA’s Retrospective Case Study in the Raton Basin, Colorado: Study of the Potential Impacts of 

Hydraulic Fracturing on Drinking Water Resources (U.S. EPA, 2015k), the methane was found to be primarily 

thermogenic in origin, modified by biologic oxidation (U.S. EPA, 2015k). Secondary biogeochemical changes 

related to the migration and reaction of methane within the shallow drinking water aquifer were reflected in 

the characteristics of the Little Creek Field groundwater (U.S. EPA, 2015k). 

The sources of methane in the two studies could be determined with varying degrees of certainty. Narrowly

identifying the most likely pathway(s) of migration has been more difficult. In northeastern Pennsylvania, 

while the sources could not be definitively determined, the Marcellus Shale could not be excluded as a 

potential source in some wells based on isotopic signatures, methane-to-ethane ratios, and isotope reversal 

properties (U.S. EPA, 2014f). The Pennsylvania Department of Environmental Protection (PA DEP) cited at 

least two operators for failure to prevent gas migration at wells within the study area. Evidence cited by the 

state included isotopic comparison of gas samples from drinking water wells, water bodies, and gas wells; 

inadequate cement jobs; and sustained casing pressure (although, under Pennsylvania law, oil or gas 

operators can be cited if they cannot disprove the contamination was caused by their well using pre-drilling 

samples) (Llewellyn et al., 2015). A separate study (Ingraffea et al., 2014) showed that wells in this area had 

higher incidences of mechanical integrity problems relative to wells in other parts of Pennsylvania. While the 

study did not definitively show that stray gas was linked to construction problems, it does imply that there 

may be more difficulties in constructing wells in this area. In the Little Creek Field in the Raton Basin, the

source of methane was identified as the Vermejo coalbeds. While the nature of the migration pathway is 

unknown, modeling suggests that it could have occurred along natural rock features in the area and/or along 

a gas production well (U.S. EPA, 2015k). Because the production wells were shut in shortly after the incident 

began, the wells could not be inspected to determine whether a mechanical integrity failure in the wellbore 

was a likely cause of the migration.1

These two case studies illustrate the considerations involved with understanding stray gas migration and the 

difficulty in determining sources and migration pathways. To more conclusively determine sources and 

migration pathways, studies in which data are collected on mechanical integrity and hydrocarbon gas (e.g., 

methane, ethane) concentrations both before and after hydraulic fracturing operations, in addition to the 

types of data summarized above, would be needed.

In the Wattenberg Field in Colorado, Li et al. (2016a) investigated the concentration of various ions 

in water from an uncontaminated aquifer, an aquifer containing thermogenic methane, and 

produced water from oil and gas wells to understand the transport of aqueous- and gas-phase 

fluids at the site. The results indicated that the methane that was contaminating water wells was 

not transported with aqueous phase fluids; the authors suggested that this can provide evidence for 

migration mechanisms, because certain pathways (e.g., migration from improperly sealed well 

 

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.
Chapter 6 – Well Injection 

6-26 

casings) could potentially result in gas-phase but not aqueous-phase migration. See Text Box 6-4 for 

another example of an investigation into the occurrence of stray gas in drinking water wells.

Text Box 6-4. Parker County, Texas.

Peer-reviewed studies have been conducted within the Barnett Shale area, which includes Parker County, 

Texas. These include sampling studies of private water well composition, noble gas content, and isotopic 

signatures of natural gases, as well as analysis of existing water sample data. Disagreement exists about the 

origin of the increased natural gas in private well water. 

One suggested possibility is that production casing annuli could serve as a migration pathway for natural gas 

from formations located between the Barnett and the Trinity to reach overlying intervals (including the 

Trinity aquifer) (Darrah et al., 2014). However, using measurements of hydrocarbon and noble gas isotopes, 

Wen et al. (2016) suggests the source of methane in the Trinity aquifer water wells is directly from the 

underlying Strawn Formation and not from pathways associated with the gas production wells although the 

timing of methane entry into the Strawn is not known.

6.2.2.2 Pathways Related to Cement

Fluid movement can result from inadequate well design or construction (e.g., cement loss or other 

problems that arise in cementing of wells) or degradation of the cement over time (e.g., corrosion 

or the formation of microannuli), which may, if undetected and not repaired, cause the cement to 

succumb to the stresses exerted during hydraulic fracturing.1 The well cement must be able to 

withstand the subsurface conditions and the stresses encountered during hydraulic fracturing 

operations. This section presents data and information that can help indicate that pathways within 

the cement are present or allowing fluid movement.

Uncemented zones can allow fluids or brines to move into drinking water resources. If a fluidcontaining zone is left uncemented, the open annulus between the formation and casing can act as a 

pathway for migration of that fluid. Fluids can enter the wellbore along any uncemented section of 

the wellbore if a sufficient pressure gradient is present. Once the fluids have entered the wellbore, 

they can travel up along the entire uncemented length of the wellbore as shown in Pathway 2 of 

Figure 6-4. 

As mentioned in Section 6.2.2.1, Fleckenstein et al. (2015) found uncemented gas zones to be a 

significant factor in barrier failures in wells in the Wattenberg basin in Colorado. A report on the 

Pavillion field by AME (2016) identified a similar set of risk factors for fluid migration including: 

uncemented production casing, shallow surface casing, and the presence of both an intermediate 

pressurized gas zone and a permeable groundwater zone encountered in the same production 

wellbore.

Because of their low density and buoyancy, gaseous fluids such as methane will migrate up the 

wellbore if an uncemented wellbore is exposed to a gas-containing formation. Gas may then be able 

 

1 Microannuli are very small openings that form between the cement and its surroundings and that may serve as 

pathways for fluid migration to drinking water resources. 
Chapter 6 – Well Injection 

6-27 

to enter other formations (including drinking water resources) if the wellbore is uncemented and 

the pressure in the annulus is sufficient to force fluid into the surrounding formation (Watson and 

Bachu, 2009; Harrison, 1985). The rate at which the gas can move will depend on the difference in 

pressure between the annulus and the formation (Wojtanowicz, 2008). See Chapter 10 for a 

discussion of practices, such as well testing, that can decrease the frequency of such gas migration 

that could impact drinking water quality.

In several cases, poor or failed cement has been linked to stray gas migration (Text Box 6-3). A 

Canadian study found that uncemented portions of casing were the most significant contributors to 

gas migration (Watson and Bachu, 2009). The same study also found that 57% of all casing leaks 

occurred in uncemented segments. In the study by Darrah et al. (2014) (Section 6.2.2.1), using 

isotopic data, four clusters of gas contamination were linked to poor cementing. In three clusters in 

the Marcellus and one in the Barnett, gas found in drinking water wells had isotopic signatures 

consistent with intermediate formations overlying the producing zone. This suggests that gas 

migrated from the intermediate units along the well annulus, along uncemented portions of the 

wellbore, or through channels or microannuli. 

Cementing of the surface casing is the primary aspect of well construction intended to protect 

drinking water resources. Most states require the surface casing to be set and cemented from the 

level of the lowermost drinking water resource to the surface (GWPC, 2014). Most wells—including 

those used in hydraulic fracturing operations—have such cementing in place. Among the wells 

represented in the Well File Review, surface casing was found to be fully cemented in 93% of wells. 

Of these, an estimated 55% of wells (12,600 wells) were cemented to below the operator-reported 

protected groundwater resource; in an additional 28% of wells (6,400 wells), the operatorreported protected groundwater resources were fully covered by the next cemented casing 

string.1,2,3 A portion of the annular space between the casing and the operator-reported protected 

groundwater resources was uncemented in at least 3% of wells (600 wells) (U.S. EPA, 2015n).4 

Improper placement of cement can lead to defects in external mechanical integrity. For example, an 

improper cement job can be the result of loss of cement during placement into a formation with 

 

1 In the Well File Review, protected groundwater resources were as reported by well operators. For most wells 

represented in the Well File Review, protected groundwater resources were identified based on state or federal 

authorization documents. Other data sources used by well operators included aquifer maps, data from offset production 

wells, open hole log interpretations by operators, operator experience, online databases, and references to a general 

requirement by the oil and gas agency. 

2 The research that the EPA reviewed used various terms to describe subsurface water resources that are 

used/potentially used for drinking water. Where another term is relevant to describing the author’s research, we use that 

term; for the purpose of this assessment, all of these terms are considered to fall within the assessment’s definition of 

“drinking water resources.” See Chapter 2 for additional information on the definition of a drinking water resource. 

3 6,400 wells (95% confidence interval: 500 – 12,300 wells). 

4 600 wells (95% confidence interval: 10 – 1,800 wells). 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 groundwater 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 groundwater resource. An additional 6% of wells represented had surface casing set below 

the reported protected groundwater resource depth, but because the protected groundwater depth was based on a 

nearby water well depth, the true base of the protected groundwater resource may be deeper, leaving uncertainty as to 

whether the surface casing in these wells is set deeper than the base of the protected groundwater resource.
Chapter 6 – Well Injection 

6-28 

high porosity or fractures, causing a lack of adequate cement across a water- or brine-bearing zone. 

Additionally, failure to use cement that is compatible with the anticipated subsurface conditions, 

failure to remove drilling fluids from the wellbore, and improper centralization of the casing in the 

wellbore can all lead to the formation of channels (i.e., small connected voids) in the cement during 

the cementing process (McDaniel et al., 2014; Sabins, 1990). If the channels are small and isolated, 

they may not lead to fluid migration. However, if they are long and connected, extending across 

multiple formations, or connecting to other existing channels or fractures, they can present a 

pathway for fluid migration. Figure 6-4 shows a variety of pathways for fluid migration that are 

possible from failed cement jobs.

One example of how hydraulic fracturing of a well with insufficient and improperly placed cement 

led to contamination occurred in Bainbridge Township, Ohio. This incident was well studied by the 

Ohio Department of Natural Resources (ODNR, 2008) and by an expert panel (Bair et al., 2010). The 

level of detail available for this case is not typically found in studies of such events but was collected 

because of the severity of the impacts and the resulting legal action. The English #1 well was drilled 

to a depth of 3,900 ft (1,200 m) below ground surface (bgs) in October 2007 with the producing 

formation located between 3,600 and 3,900 ft (1,100 and 1,200 m) bgs. Overlying the producing 

formation were several uneconomic formations containing over-pressured gas (i.e., gas at 

pressures higher than the hydrostatic pressure exerted by the fluids within the well).1 The original 

cement design required the cement to be placed 700 – 800 ft (210 – 240 m) above the producing 

formation to seal off these areas. During cementing, however, both the spacer fluid and cement 

were lost in the subsurface, and the cement did not reach the intended height.2 Despite the lack of 

sufficient cement, the operator proceeded with hydraulic fracturing.

During the hydraulic fracturing operation in November 2007, about 840 gal (3,200 L) of fluid 

flowed up the annulus and out of the well. When the fluid began flowing out of the annulus, the 

operator immediately ceased operations and shut in the well; this caused the pressure in the 

wellbore to increase. About a month later, there was an explosion in a nearby house where methane 

had entered from an abandoned and unplugged drinking water well connected to the cellar (Bair et 

al., 2010).In addition to the explosion, the over-pressured gas entering the aquifer resulted in the 

contamination of 26 private drinking water wells with methane. The wells, some of which had 

histories of elevated methane prior to the incident, were taken off-line. By 2010, all of the well 

owners had been connected to a public water supply (Tomastik and Bair, 2010). 

Contamination at the Bainbridge Township site was the result of inadequate cement. The ODNR 

determined that failure to cement the over-pressured gas formations, proceeding with the 

hydraulic fracturing operation without adequate cement, and the extended period during which the 

well was shut in all contributed to the contamination of the aquifer with stray gas (ODNR, 2008). 

Cement logs found the cement top was at 3,640 ft (1,110 m) bgs, leaving the uneconomic gasproducing formations and a portion of the production zone uncemented. The surface casing was 

253 ft (77 m) deep and cemented to the surface. Hydraulic fracturing fluids flowing out of the 

 

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. 
Chapter 6 – Well Injection 

6-29 

annulus provided an indication that hydraulic fracturing had created a path from the producing 

formation to the well annulus in addition to the uncemented gas zones. Because the well was shut

in, the pressure in the annulus could not be relieved, and the gas eventually traveled through 

natural fractures surrounding the wellbore into local drinking water aquifers (during the time the 

well was shut in, natural gas seeped into the well annulus and pressure built up from an initial 

pressure of 90 psi (0.6 MPa) to 360 psi (2.5 MPa)). From the aquifer, the gas moved into drinking 

water wells and from one of those wells into a cellar, resulting in the explosive accumulation of gas.

The Well File Review found that 3% of all hydraulic fracturing jobs (800 jobs) reported a 

mechanical integrity failure that allowed fluid to enter an annular space (U.S. EPA, 2016c).1 The 

mechanical integrity failures generally resulted in hydraulic fracturing fluid entering the annular 

space between the casing and formation or between two casings, and were generally noted by 

increases in annular pressure or fluid bubbling to the surface. Other possible mechanisms for the 

failures include casing leaks, cement failure, and fractures extending above the height of the 

cement. (See Section 6.3.2.2 for additional information on fracture overgrowth.) While failures 

were noted, these do not necessarily indicate there was movement of fluid into a drinking water 

resource. In most cases, when problems occurred, the hydraulic fracturing operation was stopped 

and operators addressed the cause of the failure before hydraulic fracturing operations resumed; 

however, in 0.5% of the hydraulic fracturing jobs (100 jobs) with identified failures, there was no 

additional barrier between the annular space with fluid and protected drinking water resources.2

While it could not definitively be determined whether fluid movement into the protected drinking 

water resource occurred, in these cases, all of the protective barriers intended to prevent such fluid 

migration failed, leaving the groundwater resource vulnerable to contamination. 

While limited literature is available on construction (including cementing) flaws in hydraulically 

fractured wells, several studies have examined construction flaws in oil and gas wells in general. 

One study that examined reported drinking water contamination incidents in Texas identified 10 

incidents related to drilling and construction activities among 250,000 oil and gas wells (Kell, 

2011). The study noted that many of the contamination incidents were associated with wells that 

were constructed before Texas revised its regulations on cementing in 1969 (it is not clear how old 

the wells were at the time the contamination occurred). Because this study relied on reported 

incidents, it is possible that other wells exhibited mechanical integrity issues but did not result in 

contamination of a drinking water well or were not reported. Therefore, this should be considered 

a low-end estimate of the number of mechanical integrity issues that could be tied directly to 

drilling and construction activities. It is important to note that the 10 contamination incidents 

identified were not associated with wells that were hydraulically fractured (Kell, 2011). 

Several investigators have studied violations information from the PA DEP online violation 

database to evaluate the rates of and possible factors contributing to mechanical integrity 

problems, including those related to cement. The results of these studies are summarized in Table 

6-2. 

1 800 jobs (95% confidence interval: 10 – 1,700 jobs). 

2 100 jobs (95% confidence interval: 10 – 300 jobs). 
Chapter 6 – Well Injection 

6-30 

Table 6-2. Results of studies of PA DEP violation data that examined mechanical integrity 

failure rates.

Study

Violations 

investigated

Wells 

studied

Data 

timeframe Key findingsa

Considine et al. 

(2012)

Violations resulting 

in environmental 

damage

3,533 2008−2011

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.

Davies et al. 

(2014)

Failure of one of the 

barriers preventing 

fluid migration

8,030 2005−2013

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.

Ingraffea et al. 

(2014)

Violations and 

inspection records 

indicating structural 

integrity loss 

3,391 2000−2012

Wells in unconventional reservoirs 

experienced a rate of structural integrity 

loss of 6.2%, while the rate for 

conventional wells was 1%.

Vidic et al. 

(2013)

Construction 

violations related to 

casing or cement 

6,466 2008−2013 Approximately 3.4% of wells received this 

type of violation.

Olawoyin et al. 

(2013) All violations 2,001 2008−2010

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%. 

Brantley et al. 

(2014)

Violations related 

to well construction 

issues 

7,234 2005 – 2013

Over the period studied, a total of 3.4% of 

well operators received violations for 

construction issues. Violations in any given 

year ranged from 0.6% to 10.8%. Also, 

0.24% of wells were cited for methane 

migration.

a While all of these studies used the same database, their results vary because they studied different timeframes and used 

different definitions of what violations constituted a mechanical integrity problem or failure.

Because a significant portion of Pennsylvania’s recent oil and gas activity is in the Marcellus Shale, 

many of the wells in these studies were most likely used for hydraulic fracturing. For example, 

Ingraffea et al. (2014) found that approximately 16% of the oil and gas wells drilled in the state 

between 2000 and 2012 were completed in unconventional reservoirs, and nearly all of these wells 

were used for hydraulic fracturing. Wells drilled in unconventional reservoirs experienced higher 

rates of structural integrity loss, as defined by the authors, than conventional wells drilled during 

the same time period (Ingraffea et al., 2014). The authors did not compare rates of structural 
Chapter 6 – Well Injection 

6-31 

integrity loss in conventional wells that were and were not hydraulically fractured; they assumed 

that unconventional wells were hydraulically fractured and conventional wells were not. 

Violation rates resulting in environmental damage among all Pennsylvania wells dropped from 

52.9% in 2008 to 20.8% in 2011 (Considine et al., 2012), and the drop may be due to a number of 

factors. Violations related to failure of cement or other well components represented a minority of 

all well violations (i.e., among wells that were and were not hydraulically fractured). Of 845 events 

that caused environmental damage, including but not limited to contamination of drinking water 

resources, Considine et al. (2012) found that about 10% (85 events) were related to casing and 

cement problems. The rest of the incidents were related to site restoration and spills; the violations 

noted are confined to those incidents that caused environmental damage (i.e., the analysis excluded 

construction flaws that did not have adverse environmental effects). In addition, two wells (0.06%) 

were found to have contributed to methane migration into drinking water. Ingraffea et al. (2014)

identified a significant increase in mechanical integrity problems such as casing leaks, sustained 

casing pressure, and insufficient cement from 2009 to 2011, rising from 5% to 6% of all newly 

drilled oil and gas wells, followed by a decrease beginning in 2012 to about 2% of all wells, a 

reduction of approximately 100 violations among 3,000 wells from 2011 to 2012. The rise in 

mechanical integrity problems between 2009 and 2011 coincided with an increase in the number of 

wells in unconventional reservoirs. 

While all of the studies shown in the table used the same database, their results vary, not only 

because of the different timeframes studied, but also because they used different definitions of what 

violations constituted a mechanical integrity problem or failure. For example, Considine et al. 

(2012) considered all events resulting in environmental damage—including effects such as 

erosion—and found a relatively high violation rate. Davies et al. (2014) and Ingraffea et al. (2014)

investigated violations related to mechanical integrity, while Vidic et al. (2013) looked only at 

mechanical integrity violations resulting in fluid migration out of the wellbore; these more specific 

studies found relatively lower violation rates. Olawoyin et al. (2013) performed a statistical 

analysis that weighted violations based on risk and found that the most risky violations included 

those involving pits, erosion, waste disposal, and blowout preventers. 

Another source of information on contamination caused by wells is positive determination letters 

(PDLs) issued by the PA DEP. PDLs are issued in response to a complaint when the state determines 

that contamination did occur in proximity to oil and gas activities. The PDLs take into account the 

impact, timing, mechanical integrity, and formation permeability; liability is presumed for wells 

within a given distance if the oil and gas operator cannot refute that they caused the contamination, 

based on pre-drilling sampling (Brantley et al., 2014).1 Brantley et al. (2014) examined these PDLs, 

and concluded that, between 2008 and 2012, the water supplies of approximately seven properties 

were impacted; depending on the assumptions used to determine how many unconventional gas 

wells affected a single property; this equates to a rate of 0.12 to 1.1% of the 6,061 wells begun in 

that timeframe. While these oil and gas wells were linked to contamination of wells and springs, the 

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. 
Chapter 6 – Well Injection 

6-32 

mechanisms for the impacts (including whether fluids may have been spilled at the surface or if 

there was a pathway through the well or through the subsurface rock formation to the drinking 

water resource) were not described by Brantley et al. (2014). 

While the studies discussed above present possible explanations for higher violation incidences in 

unconventional wells that are likely to be hydraulically fractured, it should be noted that other 

explanations not specific to hydraulic fracturing are also possible. These could include different 

inspection protocols and different formation types.

Cementing in horizontal wells, which are commonly hydraulically fractured, presents challenges 

that can contribute to higher rates of mechanical integrity issues. The observation by Ingraffea et al. 

(2014) that wells drilled in unconventional reservoirs (which are horizontal in Pennsylvania)

experience higher rates of structural integrity loss than conventional wells is supported by 

conclusions of Sabins (1990), who noted that horizontal wells have more cementing problems 

because they are more difficult to center properly and can be subject to settling of solids on the 

bottom of the wellbore. Cementing in horizontal wells presents challenges that can contribute to 

higher rates of mechanical integrity issues. 

Thermal and cyclic stresses caused by intermittent operation also can stress cement (King and 

King, 2013; Ali et al., 2009). Increased pressures and cyclic stresses associated with hydraulic 

fracturing operations can contribute to cement integrity losses and, if undetected, small mechanical 

integrity problems can lead to larger ones. Temperature differences between the (typically 

warmer) subsurface environment and the (typically cooler) injected fluids, followed by contact 

with the (typically warmer) produced water, can lead to contraction of the well materials (both 

casing and cement), which introduces additional stresses. Similar temperature changes may occur 

when multiple fracturing stages are performed. Because the casing and cement have different 

mechanical properties, they may respond differently to these stress cycles and debond. 

Several studies illustrate the effects of cyclic stresses. Dusseault et al. (2000) indicate that wells that 

have undergone several cycles of thermal or pressure changes will almost always show some 

debonding between cement and casing. Another laboratory study by De Andrade et al. (2015) found 

that cycling temperatures between 61°F and 151°F (16°C and 66°C) at 35 bar pressure (2.5 MPa) 

led to the formation of cracks in cement across both shale and sandstone formations. Cement 

damage was more significant in sandstone formations and worsened with each thermal cycle. A 

similar study by Roy et al. (2016) at ambient pressure did not find any cracks larger than 200 

microns with temperature fluctuation between -40°F and 158°F (-40°C and 70°C), although 

numerical modeling of the same scenario predicted that cracks up to 1 to 10 microns would form, 

which would not have been detected by the methods used. Microannuli formed by this debonding 

can serve as pathways for gas migration, in particular because the lighter density of gas provides a 

larger driving force for migration through the microannuli than for heavier liquids.1One laboratory 

study indicated that microannuli on the order of 0.01 in (0.25 mm) could increase effective cement 

permeability from 1 nD (1 × 10−21 m2) in good quality cement up to 1 mD (1 × 10−15 m2) (Bachu and 

Bennion, 2009). This six-order magnitude increase in permeability shows that even small 

1 Microannuli can also form due to an inadequate cement job, e.g., poor mud removal or improper cement placement rate.
Chapter 6 – Well Injection 

6-33 

microannuli can significantly increase the potential for flow through the cement. Typically, these 

microannuli form at the interface between the casing and cement or between the cement and 

formation. Debonding and formation of microannuli can occur through intermittent operation, 

pressure tests, and workover operations (Dusseault et al., 2000).1While a small area of debonding 

may not lead to fluid migration, the microannuli in the cement resulting from the debonding can 

serve as initiation points for fracture propagation if re-pressurized gas enters the microannulus 

(Dusseault et al., 2000). 

A number of modeling studies have indicated that fractures can propagate upwards from existing 

defects in cement or areas with poorer bonding (Kim et al., 2016; Roy et al., 2016; De Andrade et al., 

2015). Feng et al. (2015) showed that fractures in cement tended to propagate upwards along the 

wellbore instead of radially. Modeling studies have also shown that cements with lower Young’s 

modulus tend to propagate fractures more slowly than stiffer cements (Kim et al., 2016; Feng et al., 

2015).2

The Council of Canadian Academies (2014) found that the repetitive pressure surges occurring

during the hydraulic fracturing process would make maintaining an intact cement seal more of a 

challenge in these wells. Wang and Dahi Taleghani (2014) performed a modeling study, which 

concluded that hydraulic fracturing pressures could initiate annular cracks in cement. Another 

study of well data indicated that cement failure rates are higher in intermediate casings compared 

to other casings (McDaniel et al., 2014). The failures occurred after drilling and completion of wells, 

and the authors surmised that the cement failures were most likely due to cyclic pressure stresses 

caused by drilling. Theoretically, similar cyclic pressure events could also be experienced in the 

production casing during multiple stages of hydraulic fracturing. Mechanical stresses associated 

with well operation or workovers and pressure tests also may lead to small cracks in the cement, 

which may provide migration pathways for fluid. 

Corrosion can lead to cement failure. Cement can fail to maintain integrity as a result of degradation 

of the cement after the cement is set. Cement degradation can result from attack by corrosive brines 

or chemicals such as sulfates, sulfides, and carbon dioxide that exist in formation fluids (Renpu, 

2011). These chemicals can alter the chemical structure of the cement, resulting in increased 

permeability or reduced strength and leading to loss of cement integrity over time. Additives or 

specialty cements exist that can decrease cement susceptibility to specific chemicals. 

6.2.2.3 Well Age 

Hydraulic fracturing within older (legacy) wells has the potential to impact drinking water 

resources, either due to inadequate design and construction or degradation of the well components 

over time that afford pathways for the unintended migration of fluids. While new wells can be 

specifically designed to withstand the stresses associated with hydraulic fracturing operations, 

1 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.

2 Young’s modulus, a ratio of stress to strain, is a measure of the rigidity of a material.
Chapter 6 – Well Injection 

6-34 

older wells, which are sometimes used in hydraulic fracturing operations, may not have been 

designed to the same specifications, and their reuse for this purpose could be a concern.

Aging and extended use of a well contribute to casing corrosion and degradation, and the potential 

for fluid migration related to compromised casing tends to be higher in older wells. For example, 

exposure to corrosive chemicals such as hydrogen sulfide, carbonic acid, and brines can accelerate 

corrosion (Renpu, 2011). Ajani and Kelkar (2012) studied wells in Oklahoma and found a 

correlation between well age and mechanical integrity issues. Specifically, in wells spaced between 

1,000 and 2,000 ft (300 and 600 m) from a well being fractured, the likelihood of impact on the well 

(defined in the study as a loss of gas production or increase in water production) rose from 

approximately 20% to 60% as the well’s age increased from 200 days to over 600 days. Age was 

also found to be a factor in mechanical integrity problems in a study of wells drilled offshore in the 

Gulf of Mexico (Brufatto et al., 2003). 

The Well File Review (U.S. EPA, 2016c, 2015n) provides evidence that fracturing does occur in 

older wells, including re-entering existing wells to fracture them for the first time or re-fracturing

in wells that have been previously fractured. The Well File Review found that the median age of 

wells being initially fractured was 45 days, with well ages at time of fracturing ranging from 8 days 

to nearly 51 years. While 64% of the wells studied in the Well File Review were fractured within 6 

months of the well spud date, the median age for wells being re-fractured was 6 years.1,2 An 

estimated 11% of fracture jobs studied in the Well File Review were re-completions in a different 

zone than the original fracture job and 8% were re-fractures in the same zone as the original 

fracture job.3,4 

The Well File Review also found that well component failures appeared to occur more frequently in 

older wells that were being re-completed or re-fractured.5 The failure rate in hydraulic fracturing 

jobs involving re-completions and re-fractures was 6%, compared to 2% for hydraulic fracturing 

jobs in wells that had not been previously fractured.6,7While the confidence levels overlap, there is 

an indication that re-fractured and re-completed wells are more likely to suffer a failure of one or 

more components during hydraulic fracturing operations. 

Frac strings, which are specialized pieces of casing inserted inside the production casing, can be 

used to protect older casing during fracturing. However, the effect of hydraulic fracturing on the 

cement on the production casing in older wells is unknown. One study on re-fracturing of wells 

noted that the mechanical integrity of the well was a key factor in determining the success or failure 

of the fracture treatment (Vincent, 2011). The Well File Review (U.S. EPA, 2016c) found that 

1 Spudding refers to starting the well drilling process by removing rock, dirt, and other sedimentary material with the drill 

bit.

2 64% of wells (95% confidence interval: 48 – 77% of wells).

3 11% of jobs (95% confidence interval: 5 – 23% of jobs).

4 8% of jobs (95% confidence interval: 5 – 12% of jobs).

5 The Well File Review defines a failure as a defect in a well component that allows fluid to flow into an annular space. 

6 6% failure rate (95% confidence interval: 2 – 19% failure rate). 

7 2% failure rate (95% confidence interval: 0.5 – 8% failure rate).
Chapter 6 – Well Injection 

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failures occurred more frequently in completions using frac strings, with failures occurring 20% of 

the time, compared to failures occurring 0.9% of the time when a frac string was not used.1,2 

Note that there are also potential issues related to where these older wells are sited. For example, 

some wells could be in areas with naturally occurring subsurface faults or fractures that could not 

be detected or fully characterized with the technologies available at the time of construction. It is 

also possible that, in areas of historic petroleum exploration, old abandoned wells can be present 

which may have been improperly plugged or have degraded over time.3 These wells could serve as 

pathways for fluid migration if they are located within the fracture network of the well; see Section 

6.3.2. 

6.2.2.4 Sustained Casing Pressure 

Sustained casing pressure illustrates how the issues related to casing and cement discussed in the 

preceding sections can work together and be difficult to differentiate.4 It is an indicator that 

pathways within the well related to the well’s casing, cement, or both allowed fluid movement to 

occur. Sustained casing pressure can result from casing leaks, uncemented intervals, microannuli, 

or some combination of the three, which can be an indication that a well has lost mechanical 

integrity. Sustained casing pressure can be observed when an annulus (either the annulus between 

the tubing and production casing or between any two casings) is exposed to a source of nearly 

continuous elevated pressure. Goodwin and Crook (1992) found that sudden increases in sustained 

casing pressure occurred in wells that were exposed to high temperatures and pressures. 

Subsequent logging of these wells showed that the high temperatures and pressures led to shearing 

of the cement/casing interface and a total loss of the cement bond. Aly et al. (2015) demonstrated 

methods using a combination of chemical analysis, isotopic analysis, well logs, and drilling records 

to identify the most likely source of fluids causing sustained casing pressure.

Sustained casing pressure occurs more frequently in older wells and horizontal or deviated wells. 

One study found that sustained casing pressure becomes a greater concern as a well ages. Sustained 

casing pressure was found in less than 10% of wells that were less than a year old, but was present 

in up to 50% of 15-year-old wells (Brufatto et al., 2003). While these wells may not have been

hydraulically fractured, the study demonstrates that older wells can exhibit more mechanical 

integrity problems. Fleckenstein et al. (2015) also found that older wells exhibited more barrier 

failures, including sustained casing pressure. They reported that 3.53% of the wells in the study 

with under-pressured intermediate gas zones developed sustained casing pressure, although it is 

likely the sustained casing pressure was due to poor well design (i.e., under older standards) rather 

1 20% failure rate (95% confidence interval: 10 – 36% failure rate).

2 0.9% failure rate (95% confidence interval: 0.8 – 1.0% failure rate).

3 An abandoned well refers to a well that is no longer being used, either because it is not economically producing or it 

cannot be used because of its poor condition.

4 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 (Skjerven et al., 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. It is possible to have pressure in more 

than one of the annuli.
Chapter 6 – Well Injection 

6-36 

than well age. Watson and Bachu (2009) found that a higher portion of deviated wells had 

sustained casing pressure compared to vertical wells. Increased pressures and cyclic stresses (Syed 

and Cutler, 2010) during hydraulic fracturing and difficulty in cementing horizontal wells (Sabins, 

1990) also can lead to increased instances of sustained casing pressure (Muehlenbachs et al., 2012; 

Rowe and Muehlenbachs, 1999). 

Sustained casing pressure can be a concern for several reasons. If the pressures are allowed to build 

up to above the burst pressure of the exterior casing or the collapse pressure of the interior casing, 

the casing may fail. Increased pressure can also cause gas or liquid to enter lower-pressured 

formations that are exposed to the annulus either through leaks or uncemented sections. 

Laboratory experiments by Harrison (1985) demonstrated that over-pressurized gas in the annulus 

could cause rapid movement of gas into drinking water resources if a permeable pathway exists 

between the annulus and the groundwater. Over-pressurization of the annulus is commonly

relieved by venting the annulus to the atmosphere; however, this does not address the underlying 

problem in the well and can result in additional releases of methane to the atmosphere. 

One example of an area where sustained casing pressure is common is Alberta, Canada, where 14% 

of the wells drilled since 1971 experienced serious sustained casing flow. This was defined in a 

study by Jackson and Dussealt (2014) as more than 10,594 ft3 (300 m3)/day at pressures higher 

than 0.48 psi/ft (11 kPa/m) of depth times the depth of the surface casing. Another study in the 

same area found gas in nearby drinking water wells had a composition consistent with biogenic 

methane mixing with methane from nearby coalbed methane and deeper natural gas fields (Tilley 

and Muehlenbachs, 2012). 

In a few cases, sustained casing pressure in wells that have been hydraulically fractured may have 

been linked to drinking water contamination, although it is challenging to definitively determine 

the actual cause. In one study in northeastern Pennsylvania, methane to ethane ratios and isotopic

signatures were used to investigate stray gas migration into domestic drinking water (U.S. EPA, 

2014f). Composition of the gas in the water wells was consistent with that of the gas found in

nearby gas wells with sustained casing pressures; other possible sources of the gas could not be 

ruled out. Several gas wells in the study area were cited by the PA DEP for having elevated 

sustained casing annulus pressures. One such case included four well pads with two wells drilled on 

each pad in southeastern Bradford County. The wells, drilled between September 2009 and May 

2010, were 6,890 to 7,546 ft (2,100 to 2,300 m) deep and had surface casing to 984 ft (300 m). The 

casing below the surface casing was uncemented. All four wells experienced sustained casing 

pressure, with pressures ranging from 483 to 909 psi (3.3 to 6.3 MPa). Methane appeared in three 

nearby domestic drinking water wells in July 2010. Investigation into the cause of the methane 

contamination identified the drilled gas wells with sustained casing pressure as the most likely 

cause. The likely path was over-pressured gas from intermediate zones above the Marcellus Shale 

entering the uncemented well annulus and traveling up the annulus and along bedding planes 

which intersected the well annulus.1The determination was based on multiple lines of evidence, 

including: no methane present in a pre-drill sample, increases in methane after the wells had been 

 

1 A bedding plane is the surface that separates two layers of stratified rocks.
Chapter 6 – Well Injection 

6-37 

drilled, similar isotopic composition of the gas in the domestic wells and the gas in the annular 

space of the gas wells, and the presence of bedding planes which intersected the uncemented 

portion of the gas wells leading upwards toward the domestic wells (Llewellyn et al., 2015). 

Adequate well design, detection (i.e., through annulus pressure monitoring), and repair of sustained 

casing pressure reduce the potential for fluid movement. (See Chapter 10 for additional discussion 

of practices that can reduce the frequency or severity of impacts to drinking water quality.) Watson 

and Bachu (2009) found that regulations requiring monitoring and repair of sustained casing vent 

flow or sustained casing pressure had a positive effect on lowering leak rates. The authors also

found injection wells initially designed for the higher pressures associated with injection (vs. 

production) experienced sustained casing pressure less often than those that were retrofitted

(Watson and Bachu, 2009). As mentioned above, Fleckenstein et al. (2015) found that placing the 

surface casing below all potential sources of drinking water and cementing intermediate gas zones 

significantly reduced sustained casing pressure. 

Another study in Mamm Creek, Colorado, obtained similar results. The Mamm Creek field is in an 

area where lost cement and shallow, gas-containing formations are common. All the wells in the 

formation were hydraulically fractured (S.S. Papadopulos & Associates, 2008). A number of wells in 

the area have experienced sustained casing pressure, and methane has been found in several 

drinking water wells along with seeps into local creeks and ponds. In one well, drilled in January 

2004, four pressured gas zones were encountered during drilling and there was a lost cement 

incident, which resulted in the cement top being more than 4,000 ft (1,000 m) lower than originally 

intended. Due to high bradenhead pressure (661 psi, or 4.6 MPa), cement remediation efforts were 

implemented (Crescent, 2011; COGCC, 2004).1 The operator of this well was later cited by the 

Colorado Oil and Gas Conservation Commission (COGCC) for causing natural gas and benzene to 

seep into a nearby creek. The proposed route of contamination was contaminants flowing up the 

well annulus and then along a fault. The proposed contamination route appeared to be validated 

because, once remedial cementing was performed on the well, methane and benzene levels in the 

creek began to drop (Science Based Solutions LLC, 2014). In response to the incident, the state 

instituted requirements to identify and cement above the top of the highest gas-producing 

formation in the area and to monitor casing pressures after cementing. 

A study in the Woodford Shale in Oklahoma examined how various cement design factors affected 

sustained casing pressure (Landry et al., 2015). The study focused on wells in the Cana-Woodford 

basin, a very deep basin at 11,000 to 15,000 ft (3,400 to 4,600 m) below ground surface, where the 

depth, long laterals, fracture gradients, and low permeability of the formations in the basin make 

cementing a challenge. One operator had seven test wells in the basin, of which six exhibited 

sustained casing pressure, usually after hydraulic fracturing operations. In early designs, the 

operator had not been using centralizers on the horizontal sections of the well, because they 

increased the frequency of stuck pipe. However, improvements in centralizer design allowed the 

operator to use centralizers more frequently on later well designs, and the operator tried several 

different techniques to address the sustained casing pressure problems, with varying results: 

1 Bradenhead pressure is pressure between two casings in an oil and gas well. 
Chapter 6 – Well Injection 

6-38 

• In three of the wells, the operator used three different techniques: a conventional cement

job with a water-based drilling mud and single slurry design; oil-based mud with single

slurry design; and a foamed cement to cement the vertical portion of the well from the

kickoff point up with conventional water-based cement on the lateral. All three of these

wells experienced sustained casing pressure after hydraulic fracturing operations.

• In a fourth well, in 2013, the operator used centralizers, with three centralizers per every

two casing joints along the lateral and one centralizer per joint in the vertical section. The

design also involved an enhanced spacer fluid to remove drilling mud and a self-healing

cement in the upper portion of the well. While some channeling was detected in this well,

the channels were not connected and did not lead to sustained casing pressure.

The operator constructed an additional 21 wells using the same technique as was performed in the 

fourth well, and 20 did not show any sustained casing pressure after fracturing. This study shows 

the importance of cement design factors, such as casing centralization and mud removal, in 

preventing sustained casing pressure. 

Not every well that shows positive pressure in the annulus poses a potential problem. Sustained 

pressure is only a problem when it exceeds the ability of the wellbore to contain it or when it 

indicates leaks in the cement or casing (TIPRO, 2012). A variety of management options are 

available for managing such pressure including venting, remedial cementing, and use of kill fluids in 

the annulus (TIPRO, 2012).1While venting may be a common method to address sustained casing 

pressure, it does not address the underlying mechanical integrity failure and is only a temporary 

solution. Furthermore, venting releases fluids at the wellhead which, if gaseous, can contribute to 

increased atmospheric emissions, or if liquid, potential spills on the surface.

6.3 Fluid Migration Associated with Induced Fractures within Subsurface 

Formations

This section discusses potential pathways for fluid movement associated with induced fractures 

and subsurface formations (outside of the well system described in Section 6.2). It examines the 

potential for fluid migration into drinking water resources by evaluating the development of 

migration pathways within subsurface formations, the flow of injected and formation fluids, and 

important factors that affect these processes. 

Fluid movement requires both a physical pathway (e.g., via the interconnected pores within a 

permeable rock matrix or via a fracture in the rock) and a driving force.2 In subsurface formations, 

fluid movement is driven by the existence of a hydraulic gradient, which depends on elevation and 

pressure and is influenced by fluid density, composition, and temperature (Pinder and Celia, 2006). 

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.

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. 
Chapter 6 – Well Injection 

6-39 

In the context of hydraulic fracturing, two key factors govern fluid migration during and after the 

hydraulic fracturing event: 

• Pressure differentials in the reservoir, which are influenced both by initial subsurface

conditions and by the pressures created by injection and production regimes. Specific

factors that may influence pressure differentials include structural or topographic features,

over-pressure in the shale reservoir, or a temporary increase in pressure as a result of fluid

injection during hydraulic fracturing (Birdsell et al., 2015a).

• Buoyancy, which is driven by density differences among and between gases and liquids.

Fluid migration can occur when these density differences exist in the presence of a pathway

(Pinder and Gray, 2008).

During hydraulic fracturing, pressurized fluids leaving the well create fractures within the 

production zone and then enter the formation through these newly created (induced) fractures. 

Unintended fluid migration can result from this fracturing process. Migration pathways to drinking 

water resources could develop as a result of changes in the subsurface flow or pressure regime 

associated with hydraulic fracturing; via fractures that extend beyond the intended formation or 

that intersect existing natural faults or fractures; and via fractures that intersect offset wells or 

other artificial structures (Jackson et al., 2013d). These subsurface pathways may facilitate the 

migration of fluids by themselves or in conjunction with the well-based pathways described in 

Section 6.2. Fluids potentially available for migration include both fluids injected into the well 

(including leakoff) and fluids already present in the formation (including brine or natural gas).1

The potential for subsurface fluid migration into drinking water resources can be evaluated during 

two different time periods (Kim and Moridis, 2015): 

1. Following the initiation of fractures in the reservoir, prior to any oil or gas production. The

injected fluid, pressurizing the formation, flows through the fractures and the fractures

grow into the reservoir. Fluid leaks off into the formation, allowing the fractures to close

except where they are held open by the proppant (Adachi et al., 2007). Fractures will

generally continue to propagate until the fluid lost to leakoff is equal to the fluid injection

rate (King and Durham, 2015).

2. During the production period, after fracturing is completed and pressure in the fractures is

reduced. At this time, fluids (including oil/gas and produced water) flow from the reservoir

into the well. As fluids are withdrawn from the formation, pore pressure decreases; as a

result, the effective stress applied to fractures increases and (in the absence of proppant)

fractures will close (Aybar et al., 2015).

Note that these two time periods vary in duration. As described in Chapter 3, the first period of 

fracture creation and propagation (i.e., the hydraulic fracturing itself) is a relatively short-term 

process, typically lasting 2 to 10 days, depending on the number of stages in the fracture treatment 

1 Leakoff is the fraction of the injected fluid that infiltrates into the formation and is not recovered (i.e., it “leaks off” and 

does not return through the well to the surface) during production (Economides et al., 2007). Fluids that leak off and are 

not recovered are sometimes referred to as “lost” fluids.
Chapter 6 – Well Injection 

6-40 

design. On the other hand, operation of the well for production covers a substantially longer period 

(depending on many factors such as the amount of hydrocarbons in place and economic 

considerations), and can be as long as 40 or 60 years in onshore tight gas reservoirs (Ross and King, 

2007). 

The following discussion of potential subsurface fluid migration into drinking water resources 

focuses primarily on the physical movement of fluids and the factors affecting this movement. 

Section 6.3.1 describes the basic principles of subsurface fracture creation, geometry, and 

propagation, to provide context for the discussion of potential fluid migration pathways in Section 

6.3.2. Geochemical and biogeochemical reactions among hydraulic fracturing fluids, formation 

fluids, subsurface microbes, and rock formations are another important component of subsurface 

fluid migration and transport. See Chapter 7 for a discussion of the processes that affect pore fluid 

biogeochemistry and influence the chemical and microbial composition of produced water.

6.3.1 Overview of Subsurface Fracture Growth

Fracture initiation and growth is a highly complex process due to the heterogeneous nature of the 

subsurface environment. As shown in Figure 6-5, fracture formation is controlled by the three in 

situ principal compressive stresses: the vertical stress, the maximum horizontal stress, and the 

minimum horizontal stress. During hydraulic fracturing, pressurized fluid injection creates high 

pore pressures around the well. Fractures form when this pressure exceeds the local least principal 

stress and the tensile strength of the rock (Zoback, 2010; Fjaer et al., 2008). 

Fractures propagate (increase in length) in the direction of the maximum principal stress; they are 

tensile fractures that open in the direction of least resistance and then propagate in the plane of the 

greatest and intermediate stresses (Nolen-Hoeksema, 2013). Deep in the subsurface, the maximum 

principal stress is generally in the vertical direction, because the overburden (the weight of 

overlying rock) is the largest single stress. Therefore, in deep formations, fracture orientation is 

expected to be vertical. This is the scenario illustrated in Figure 6-5. At shallower depths, where the 

rock is subjected to less pressure from the overburden, more fracture propagation is expected to be 

in the horizontal direction. Using tiltmeter data from over 10,000 fractures in various North 

American shale reservoirs, Fisher and Warpinski (2012) found that induced fractures deeper than 

about 4,000 ft (1,000 m) are primarily vertical (see below for more information on tiltmeters). 

Between approximately 4,000 and 2,000 ft (1,000 and 600 m), they observed that fracture 

complexity increases, and fractures shallower than about 2,000 ft (600 m) are primarily (though 

not entirely) horizontal.1However, local geologic conditions can cause fracture orientations to 

deviate from these general trends (Ryan et al., 2015). Horizontal fracturing can also occur in deeper 

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. For the reasons 

explained above, this is more likely to occur at shallower depths. However, even in shallow zones, fractures are unlikely to 

be completely horizontal. As noted by Fisher and Warpinski, “All of the fractures do not necessarily turn horizontal; they 

might have significant vertical and horizontal components with more of a T-shaped geometry.” In the Fisher and 

Warpinski data set, the maximum horizontal component of the fractures is approximately 70%. 
Chapter 6 – Well Injection 

6-41 

settings in some less-common reservoir environments where the principal stresses have been 

altered by salt intrusions or similar types of geologic activity (Jones and Britt, 2009). 

Figure 6-5. Hydraulic fracture planes (represented as ovals), with respect to the principal 

subsurface compressive stresses: SV (the vertical stress), SH (the maximum horizontal stress), 

and Sh (the minimum horizontal stress). 

In addition to the principal subsurface stresses, a variety of factors and processes affect the 

complex process of fracture creation, propagation, geometry, and containment.1 Computational

modeling techniques have been developed to simulate fracture creation and propagation and to 

provide a better understanding of this complex process (Kim and Moridis, 2013).2 Modeling 

hydraulic fracturing in shale or tight gas reservoirs requires integrating the physics of both flow 

and geomechanics to account for fluid flow, fracture propagation, and dynamic changes in pore 

volume and permeability. Some important flow and geomechanical parameters included in these 

1 Fracture geometry refers to characteristics of the fracture such as height and aperture (width). 

2 There are different kinds of mathematical models. Analytical models have a closed-form solution and therefore are 

relatively simple to solve. In contrast, computational models (also called numerical models) require more extensive 

computational resources and are used to study the behavior of complex systems. 
Chapter 6 – Well Injection 

6-42 

types of advanced models are: permeability, porosity, Young’s modulus, Poisson’s ratio, and tensile 

strength, as well as heterogeneities associated with these parameters.1

Based on modeling and laboratory experiments (e.g., by Khanna and Kotousov, 2016; Li et al., 

2016c; Li et al., 2016b; de Pater, 2015; Kim and Moridis, 2015; Lee et al., 2015; Narasimhan et al., 

2015; Smith and Montgomery, 2015; Wang and Rahman, 2015; Kim and Moridis, 2013), below are 

some of the factors that have been noted in the literature as influencing fracture growth:

• Geologic properties of the production zone such as rock type and composition, permeability, 

thickness, and the presence of pre-existing natural fractures; 

• The presence, composition, and properties of the liquids and gases trapped in pore spaces;

• Geomechanical properties, including tensile strength, Young’s modulus, and the pressure at 

which the rock will fracture; 

• Characteristics of the interface (boundary) between adjacent rock layers; and

• Operational characteristics, including injection rate and pressure, the properties of the 

hydraulic fracturing fluids, and fracture spacing. 

Some modeling investigations have indicated that the vertical propagation of fractures (due to 

tensile failure) may be limited by shear failure, which increases the permeability of the formation 

and allows more fluid to leak off into the rock. These findings demonstrate that elevated pore 

pressure can cause shear failure, thus further affecting matrix permeability, flow regimes, and 

leakoff (Daneshy, 2009). 

It is important to note that, while computational modeling is a useful tool to understand complex 

systems, modeling has limitations and associated uncertainties. All models rely on assumptions and 

simplifications, and there is, as stated by Ryan et al. (2015), “currently no single numerical 

approach that simultaneously includes the most important thermo-hydromechanical and chemical 

processes which occur during the migration of gas and fluids along faults and leaky wellbores.”

Uncertainties in selecting values for input parameters and potentially inadequate field data for 

model verification limit the reliability of model predictions. 

In addition to their use in research applications, analytical and numerical modeling approaches are 

used to design hydraulic fracturing treatments and predict the extent of fractured areas (Adachi et 

al., 2007). Specifically, modeling techniques are used to assess the treatment’s sensitivity to critical 

parameters such as injection rate, treatment volumes, fluid viscosity, and leakoff. Existing models 

range from simpler (typically two-dimensional) theoretical models to computationally more

complicated three-dimensional models. 

Monitoring of hydraulic fracturing operations can also provide insights into fracture development. 

Monitoring techniques involve both operational monitoring methods and “external” methods not 

 

1 As described in Section 6.2.2.2, 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.
Chapter 6 – Well Injection 

6-43 

directly related to the production operation. Operational monitoring refers to the monitoring of 

pressure and flow rate, along with related parameters such as fluid density and additive 

concentrations, using surface equipment and/or downhole sensors (Eberhard, 2011). This 

monitoring is conducted to ensure the operation is proceeding as planned and to determine if 

operational parameters need to be adjusted. Interpretation of pressure data can be used to better 

understand fracture behavior (Kim and Wang, 2014). For example, pressure data from previous 

hydraulic fracturing operations can indicate whether a geologic barrier to fracture growth exists 

and whether the barrier has been penetrated, or whether fractures have intersected with natural 

fractures or faults (API, 2015). Anomalies in operational monitoring data can also indicate whether 

an unexpected event has occurred, such as communication with another well (Section 6.3.2.3). 

As described in Chapter 4, the volume of fluid injected is typically monitored and tracked to provide 

information on the volume and extent of fractures created (Flewelling et al., 2013). However,

numerical investigations have found that reservoir gas flows into the fractures immediately after 

they open from hydraulic fracturing, and injection pressurizes both gas and water within the 

fracture to induce further fracture propagation (Kim and Moridis, 2015). Therefore, the fracture 

volume can be larger than the injected fluid volume. As a result, simple estimation of fracture 

volume based on the amount of injected fluid may underestimate fracture growth, and additional 

information (e.g., from geophysical monitoring techniques) is needed to accurately predict the 

extent of induced fractures. 

External monitoring technologies can also be used to collect data on fracture characteristics and 

extent during hydraulic fracturing and/or production. These monitoring methods can be divided 

into near-wellbore and far-field techniques. Near-wellbore techniques include the use of tracers, 

temperature logs, video logs, and caliper logs that measure conditions in and immediately around 

the wellbore (Holditch, 2007). However, near-wellbore techniques and logs only provide 

information for, at most, a distance of two to three wellbore diameters from the well and are, 

therefore, not suited for tracking fractures for their entire length (Holditch, 2007). 

Far-field methods, such as microseismic monitoring or tiltmeters, are used if the intent is to 

estimate fracture growth and height across the entire fractured reservoir area. Microseismic 

monitoring involves placing geophones in a position to detect the very small amounts of seismic 

energy generated during subsurface fracturing (Warpinski, 2009).1 Monitoring these microseismic

events gives an idea of the location and size of the fracture network, as well as the orientation and 

complexity of fracturing (Fisher and Warpinski, 2012). Using the results of microseismic 

monitoring in conjunction with other information, such as time-lapse, multicomponent seismic data 

(collected with surface surveys), can provide additional information for understanding fracture 

complexity and the interaction between natural and induced fractures (D'Amico and Davis, 2015). 

The Well File Review (U.S. EPA, 2016c) found that microseismic monitoring was conducted at 0.5% 

(100) of the hydraulic fracturing jobs studied.2 Tiltmeters, which measure extremely small 

deformations in the earth, can be used to determine the direction and volume of the fractures and, 

1 Typical microseismic events associated with hydraulic fracturing have a magnitude on the order of -2.5 (negative two 

and half) (Warpinski, 2009). 

2 100 jobs (95% confidence interval: 40 – 300 jobs).
Chapter 6 – Well Injection 

6-44 

within certain distances from the well, to estimate their dimensions (Lecampion et al., 2005). Other 

monitoring techniques, such as seismic surveys, can also be used to gather information about the 

subsurface environment. For example, Viñal and Davis (2015) demonstrated the use of time-lapse 

multi-component seismic surveys to monitor changes in the overburden due to hydraulic 

fracturing. Chapter 10 provides additional discussion of factors and practices, such as site 

monitoring, that can reduce the frequency or severity of impacts to drinking water quality.

6.3.2 Migration of Fluids through Pathways Related to Fractures/Formations

As described above, subsurface migration of fluids requires a pathway, induced or natural, with 

enough permeability to allow fluids to flow, as well as a hydraulic gradient physically driving the 

movement. The following subsections describe and evaluate potential pathways for the migration 

of hydraulic fracturing fluids, hydrocarbons, or other fluids from producing formations to drinking 

water resources. They also present cases where the existence of these pathways has been 

documented. The potential subsurface migration pathways are categorized as follows: 

(1) migration out of the production zone through pore space in the rock, (2) migration due to 

fracture overgrowth out of the production zone, (3) migration via fractures intersecting offset wells 

or other artificial structures, and (4) migration via fractures intersecting other geologic features, 

such as permeable faults or pre-existing natural fractures. Although these four potential pathways 

are discussed separately here, they may act in combination with each other or in combination with 

pathways along the well (as discussed in Section 6.2) to affect drinking water resources. 

The possibility of fluid migration between a hydrocarbon-bearing formation and a drinking water 

resource can be related to the vertical distance between these formations (Reagan et al., 2015; 

Jackson et al., 2013d). In general, as the separation distance between the production zone and a 

drinking water aquifer decreases, the likelihood of upward migration of hydraulic fracturing to 

drinking water aquifers increases (Birdsell et al., 2015a). The separation distance between 

hydraulically fractured producing zones and drinking water resources (and these formations’ depth 

from the surface) varies substantially among shale gas plays, coalbed methane plays, and other 

areas where hydraulic fracturing takes place in the United States (Figure 6-6 and Table 6-3). Many 

hydraulic fracturing operations target deep shale zones such as the Marcellus or Haynesville/

Bossier, where the vertical distance between the top of the shale formation and the base of drinking 

water resources may be 1 mi (1.6 km) or greater. This is reflected in the Well File Review, in which 

approximately half of the wells were estimated to have 5,000 ft (2,000 m) or more of measured 

distance along the wellbore between the point of the shallowest hydraulic fracturing and the 

operator-reported base of the protected groundwater resource (U.S. EPA, 2015n).1 Similarly, in a 

review of FracFocus data from over 40,000 wells across the United States, Jackson et al. (2015)

found that the median depth of wells used for hydraulic fracturing was 8,180 ft (2,490 m) and the 

mean depth was 8,290 ft (2,530 m). 

 

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. True vertical separation 

distances were not reported in the Well File Review. Measured distance along a well is equal to the true vertical distance 

only in straight, vertical wells. Otherwise, the true vertical distance is less than the measured distance.
Chapter 6 – Well Injection 

6-45 

Figure 6-6. Vertical distances in the subsurface separating drinking water resources and 

hydraulic fracturing depths. 

However, as shown in Table 6-3, some hydraulic fracturing operations occur at shallower depths or 

in closer proximity to drinking water resources. For example, both the Antrim and the New Albany 

plays are relatively shallow, with distances of 100 to 1,900 ft (31 to 580 m) between the producing 

formation and the base of drinking water resources. In the Jackson et al. (2015) review of 

FracFocus data, 16% of wells reviewed were within 1 mi (1.6 km) of the surface and 3% were 

within 2,000 ft (600 m) of the surface.1The distribution of the more shallow hydraulically fractured 

wells varied nationally but was concentrated in Texas, California, Arkansas, and Wyoming. For 

example, in California and Arkansas, 88% and 85% of hydraulically fractured wells, respectively,

were within about 5,000 ft (2,000 m) of the surface. Overall, the Well File Review found a higher 

proportion of relatively shallow wells—the data in the Well File Review indicated that 20% of wells 

used for hydraulic fracturing (an estimated 4,600 wells) had less than 2,000 ft (600 m) between the 

shallowest point of the fractures and the base of protected groundwater resources (U.S. EPA, 

2015n).2This is likely because the Well File Review results are more representative of hydraulic 

fracturing operations across the country; Jackson et al. (2015) acknowledge that their analysis 

1 Jackson et al. (2015) use true vertical depth data from FracFocus; this represents the depth of the well but not 

necessarily the depth of the fractures. The depth of the fractures may be shallower than the true vertical depth of the well, 

though Jackson et al. (2015) note that most states do not require operators to submit information on the true vertical 

depth to the top of the fractures.

2 4,600 wells (95% confidence interval: 900 – 8,300 wells). The Well File Review defines this separation distance as the 

measured depth of the point of shallowest hydraulic fracturing in the well, minus the depth of the operator-reported 

protected groundwater resource.
Chapter 6 – Well Injection 

6-46 

underestimates the occurrence of relatively shallow hydraulic fracturing for states in which 

FracFocus reporting is not required.

Table 6-3. 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 (2004a). See Chapter 3 for information on the locations of these basins, 

plays, and formations.

Basin/play/ 

formationa

Approx. depth 

(ft [m] below surface)

Approx. net 

thickness (ft [m])

Distance between top of 

production zone and base 

of treatable water (ft [m])b

Shale plays

Antrim 600 to 2,200 

[200 to 670]

70 to 120 

[20 to 37]

300 to 1,900

[90 to 580]

Barnett 6,500 to 8,500 

[2,000 to 2,600]

100 to 600

[30 to 200]

5,300 to 7,300

[1,600 to 2,200]

Eagle Ford 4,000 to 12,000 

[1,000 to 3,700]

250

[76]

2,800 to 10,800

[850 to 3,290]

Fayetteville 1,000 to 7,000 

[300 to 2,000]

20 to 200

[6 to 60]

500 to 6,500

[200 to 2,000]

Haynesville-Bossier 10,500 to 13,500 

[3,200 to 4,120]

200 to 300

[60 to 90]

10,100 to 13,100 

[3,080 to 3,990]

Marcellus 4,000 to 8,500 

[1,000 to 2,600]

50 to 200

[20 to 60]

2,125 to 7,650

[648 to 2,330]

New Albany 500 to 2,000 

[200 to 600]

50 to 100

[20 to 30]

100 to 1,600

[30 to 490]

Woodford 6,000 to 11,000 

[2,000 to 3,400]

120 to 220

[37 to 67]

5,600 to 10,600

[1,700 to 3,230]

Coalbed methane basins

Black Warrior 

(Upper Pottsville)

0 to 3,500

[0 to 1,100]

< 1 to > 70

[< 1 to > 20]

As little as zeroc

Powder River 

(Fort Union)

450 to >6,500 

[140 to >2,000]

75

[23] As little as zeroc

Raton (Vermejo 

and Raton)

< 500 to > 4,100

[< 200 to > 1,300]

10 to >140

[3 to >43]

As little as zeroc

San Juan (Fruitland) 550 to 4,000 

[170 to 1,000]

20 to 80

[6 to 20] As little as zeroc

a For coalbed methane, values are given for the specific coal units noted in parentheses.

b The base of treatable water is defined at the state level; the information in the table is based on depth data from state oil and 

gas agencies and state geological survey data.

c Formation fluids in producing formations meet the salinity threshold that is used in some definitions of a drinking water 

resource in at least some areas of the basin. See the discussion after Text Box 6-5 for more information about this definition.
Chapter 6 – Well Injection 

6-47 

In coalbed methane plays, which are typically shallower than shale gas plays, vertical separation 

distances can be even smaller. In the Raton Basin of southern Colorado and northern New Mexico, 

approximately 10% of coalbed methane wells have less than 675 ft (206 m) of separation between 

the gas wells’ perforated intervals and the depth of local water wells. In certain areas of the basin, 

this distance is less than 100 ft (31 m) (Watts, 2006). In California, nearly half of the hydraulic 

fracturing has occurred at depths less than about 900 ft (300 m) (CCST, 2015b), with hundreds of 

wells in the San Joaquin Valley between 150 ft (46 m) and 2,000 ft (600 m) deep (Jackson et al., 

2015). 

Some hydraulic fracturing operations are conducted within formations containing drinking water

resources (Table 6-3). One example of hydraulic fracturing taking place within a geologic formation

that is also used as a drinking water source is in the Wind River Basin in Wyoming (Digiulio and

Jackson, 2016; WYOGCC, 2014b; Wright et al., 2012). Vertical gas wells in this area target the lower 

Wind River Formation and the underlying Fort Union Formation, which consist of interbedded

layers of sandstones, siltstones, and mudstones. The Wind River Formation also serves as the

principal source of domestic, municipal, and agricultural water in this rural area. There are no

laterally continuous confining layers of shale in the basin to prevent upward movement of fluids.

While flow in the basin generally tends to be downward, local areas of upward flow have been

documented (Digiulio and Jackson, 2016). Assessing the relative depths of drinking water resources 

and hydraulic fracturing operations near Pavillion, Wyoming, Digiulio and Jackson (2016) found

that approximately 50% of fracture jobs were within 1,969 ft (600 m) of the deepest domestic

drinking water well in the area, and that 10% were within 820 ft (250 m) (Digiulio and Jackson,

2016). Among the wells evaluated by DiGiulio and Jackson, the shallowest fracturing occurred at

1,057 ft (322 m) below ground surface, which is comparable to depths targeted for drinking water

withdrawal in the formation. See Text Box 6-5 for more information on Pavillion, Wyoming.

Text Box 6-5. Pavillion, Wyoming.

The Pavillion gas field is located east of the town of Pavillion, Wyoming. In addition to gas production, the 

field is also home to rural residences that rely on approximately 40 private wells to supply drinking water. 

The oldest known domestic water well in the field dates to 1934 (AME, 2016). Gas production in the field 

began in 1960 and, by the 2000s, it had grown to producing from at least 180 wells. Most of these gas wells 

were drilled since 1990, and approximately 140 to 145 were not plugged as of mid-2016 (AME, 2016; Digiulio 

and Jackson, 2016). 

In the Pavillion gas field the same geologic formation that is used to produce hydrocarbons supplies the area’s 

drinking water (Digiulio and Jackson, 2016). Water wells draw from the Wind River Formation, and gas is 

extracted from both the Wind River Formation and the underlying Fort Union Formation. The Wind River 

Formation contains variably permeable strata with lenses of relatively higher permeability rock enriched 

with natural gas. Water quality is typically freshest nearer the surface, and there is no rock formation acting 

as a natural barrier to separate the drinking water from hydrocarbons (Digiulio and Jackson, 2016). There is 

approximately 200 ft (60 m) vertical distance separating the deepest domestic well in the field from the 

shallowest hydraulic fracturing, although there is approximately 2.5 mi (4 km) lateral distance between them 

(AME, 2016; Digiulio and Jackson, 2016). 

(Text Box 6-5 is continued on the following page.)
Chapter 6 – Well Injection 

6-48 

Text Box 6-5 (continued). Pavillion, Wyoming.

Following complaints by area residents about changes to their water quality in the mid-2000s, state and 

federal agencies began a series of investigations, centering on various aspects of the site and supporting 

differing conclusions about the source and mechanism of the water quality changes (AME, 2016). 

Twenty-five pits that were used to dispose of drill cuttings, drilling mud, and spent drilling fluids near some 

of the water wells were also investigated as a potential source of the groundwater contamination. Based on 

these evaluations, soil and/or groundwater remediation was performed at approximately six of the pits, no 

further action was recommended at approximately twelve pits, and the remaining pits are receiving further 

investigation (AME, 2016). 

Samples collected from two monitoring wells at depths between those of the drinking water and active 

intervals in gas production wells show elevated pH, unexpectedly high potassium values, and several organic 

constituents, including natural gas, alcohols, phenols, glycols, and benzene, toluene, ethylbenzene, and 

xylenes (BTEX) (Digiulio and Jackson, 2016). The potential source of chemicals in these two monitoring wells 

include formation water, contaminants remaining after well construction (AME, 2016) and hydraulic 

fracturing and other oil and gas activities (Digiulio and Jackson, 2016). 

Water samples collected from domestic wells contain dissolved methane and some contain high sodium and 

sulfate concentrations. Organic chemicals have also been detected in some domestic wells (AME, 2016; 

Digiulio and Jackson, 2016). These same investigators suspect that pit proximity explains the origin of organic 

chemicals. In addition, natural gases from intermediate depths not hydraulically fractured are likely moving 

along some gas wellbores, potentially into zones used for drinking water (AME, 2016). 

(Text Box 6-5 is continued on the following page.)
Chapter 6 – Well Injection 

6-49 

Text Box 6-5 (continued). Pavillion, Wyoming.

Of about 40 production wells at which pressure was measured on the bradenhead annulus between the 

production and surface casings, about 25% exhibited sustained casing pressure consistent with an ongoing

source of gas and/or liquid. Gas samples collected from bradenhead annuli, production tubing and casing, and

water wells indicate that the samples have similar gas compositions. This suggests a common origin, which is 

consistent with long-term migration from a deeper source (AME, 2016; WYOGCC, 2014b). 

Production wells may be the source of gas migration, and groundwater immediately around some of the 

disposal pits has been affected (AME, 2016). However, the investigative reports conclude that identifying the 

precise source(s) of the water quality issues is challenging due to the lack of comprehensive pre-drilling 

water quality and other baseline monitoring, the unique hydrogeologic setting, and the difficulty of 

identifying specific geologic or well pathways. 

In other cases, hydraulic fracturing takes place in formations that are not currently being used as 

sources of drinking water, but that meet the salinity threshold that is used in some definitions of 

drinking water resources.1 This occurs in low-salinity coal-bearing formations in the Raton Basin of 

Colorado (U.S. EPA, 2015k), the San Juan Basin of Colorado and New Mexico (U.S. EPA, 2004a), the 

Powder River Basin of Montana and Wyoming (as described in Chapter 7), and in several other 

coalbed methane plays. Hydraulic fracturing in these regions occurs in formations characterized by 

total dissolved solids (TDS) values substantially lower than the 10,000 mg/L TDS value used in the 

federal definition of an underground source of drinking water.2Across various basins, coalbed 

methane operations have been reported to occur in formations with 300 to 3,000 mg/L TDS and at 

depths as shallow as 350 ft (110 m) (U.S. EPA, 2004a). In one field in Alberta, Canada, there is 

evidence that fracturing in the same formation as a drinking water resource (in combination with 

mechanical integrity problems; see Section 6.2.2.4) led to gas migration into water wells (Tilley and 

Muehlenbachs, 2012). 

California is another area where hydraulic fracturing occurs in shallow zones with low-salinity 

groundwater. A study by the California Council on Science and Technology (CCST, 2015b) found 

that 3% of the hydraulic fracturing in the state occurred within 2,000 ft (600 m) of the surface. In 

California’s San Joaquin Valley, hydraulic fracturing appears to have been conducted in formations 

with a TDS of less than 1,500 mg/L (CCST, 2014). Another study in California examined the TDS 

values of water samples taken during oil and gas activities and found that 15% to 19% of the oil and 

1 For the purposes of this discussion, the federal definition of an underground source of drinking water is used. Pursuant 

to 40 CFR 144.3, an underground source of drinking water is “an aquifer or its portion which supplies any public water 

system; or which contains a sufficient quantity of groundwater to supply a public water system; and currently supplies 

drinking water for human consumption; or contains fewer than 10,000 mg/L TDS; and which is not an exempted aquifer.” 

This definition is used by the EPA’s Underground Injection Control Program, which regulates injection wells (but not 

hydrocarbon production wells). 

2 This salinity threshold is used as a point of comparison only. While the definition of an underground source of drinking 

water is not exactly the same as the definition of a drinking water resource (and many states have their own definitions of 

protected drinking water zones), the former provides a useful frame of reference when considering the ability of an 

aquifer to potentially serve as a source of drinking water. 
Chapter 6 – Well Injection 

6-50 

gas activities in Kern County, California, occurred within zones containing water with less than 

3,000 mg/L TDS (Kang and Jackson, 2016).1

The overall frequency at which hydraulic fracturing occurs in formations that meet the definition of 

drinking water resources across the United States is uncertain. Some information, however, that 

provides insights on the occurrence and geographic distribution of this practice is available. 

According to the Well File Review, an estimated 0.4% (90) of the 23,200 wells represented in that 

study had perforations used for hydraulic fracturing that were placed shallower than the base of 

the protected groundwater resources reported by well operators (U.S. EPA, 2015n).2 Additional

information is available from a database of produced water composition data maintained by the 

U.S. Geological Survey (USGS). The USGS produced water database contains results from analyses of 

samples of produced water, including (among other data) samples collected from more than 8,500 

oil and gas production wells in unconventional formations (coalbed methane, shale gas, tight gas, 

and tight oil) within the contiguous United States.3 Just over 5,000 of these samples, which were 

obtained from wells located in 37 states, reported TDS concentrations. Because the database does 

not track whether samples were from wells that were hydraulically fractured, the EPA selected 

samples from wells that were more likely to have been hydraulically fractured by restricting 

samples to those collected in 1950 or later and to those that were collected from wells producing 

from tight gas, tight oil, shale gas, or coalbed methane formations.4 This yielded 1,650 samples from 

wells located in Alabama, Colorado, North Dakota, Utah, and Wyoming, with TDS concentrations 

ranging from approximately 90 mg/L to 300,000 mg/L.5 Of the 1,650 samples, approximately 1,200 

(from wells in Alabama, Colorado, Utah, and Wyoming) reported TDS concentrations at or below 

10,000 mg/L, indicating that hydraulic fracturing there may have occurred within formations that 

meet the salinity threshold that is used in some definitions of a drinking water resource. This 

analysis, in conjunction with the result from the Well File Review, suggests that the overall 

frequency of this occurrence is relatively low, but is concentrated in particular areas of the country.

6.3.2.1 Flow of Fluids Out of the Production Zone

One potential pathway for fluid migration out of the production formation into drinking water 

resources is advective or dispersive flow of injected or displaced fluids through the formation 

matrix. In this scenario, fluids (such as those “lost” to leakoff, which are not recovered during 

 

1 Kern County accounts for 85 percent of the hydraulic fracturing that occurs in California (CCST, 2015b). 

2 90 wells (95% confidence interval: 10 – 300 wells). 

3 The EPA 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.

4 See Chapter 3, Text Box 3-1, which describes how commercial hydraulic fracturing began in the late 1940s.

5 For this analysis, the EPA 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, the EPA matched API numbers from coal bed methane wells in the USGS database v 2.1 to the 

same API numbers in the commercial database DrillingInfo, in which hydraulically fractured wells had been identified by 

the EPA using the assumptions described in Section 3.4. 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 

DrillingInfo database were retained for this analysis.
Chapter 6 – Well Injection 

6-51 

production) would flow through the pore spaces of rock formations, moving from the production 

zone into other formations. In deep, low-permeability shale and tight gas settings and where 

induced fractures are contained within the production zone, flow through the production formation 

has generally been considered an unlikely pathway for migration into drinking water resources

(Jackson et al., 2013d). 

Leakoff into shale gas formations can be as high as 90% or more of the injected volume (Table 7-2). 

The actual amount of leakoff depends on multiple factors, including the amount of injected fluid, the 

concentration of different components in the fracture fluid, the hydraulic properties of the 

reservoir (e.g., permeability), the composition of the formation matrix, the capillary pressure near 

the fracture faces, and the period of time the well is shut in following hydraulic fracturing before 

the start of production (Kim et al., 2014; Byrnes, 2011).1,2Researchers generally agree that the 

subsequent flow of this “lost” leakoff fluid is controlled or limited by processes such as imbibition 

by capillary forces and adsorption onto clay minerals (Dutta et al., 2014; Dehghanpour et al., 2013; 

Dehghanpour et al., 2012; Roychaudhuri et al., 2011) and osmotic forces (Zhou, 2016; Wang and 

Rahman, 2015; Engelder et al., 2014).3,4 It has been suggested that these processes can sequester 

the fluids in the producing formations permanently or for geologic time scales (Engelder et al., 

2014; Engelder, 2012; Byrnes, 2011). Birdsell et al. (2015b) made quantitative estimates of the 

amount of fluid that could be imbibed in shale formations. Their results indicate that between 15% 

and 95% of injected fluid volumes may be imbibed in shale gas systems, while amounts are lower in 

shale oil systems (3% to 27% of injected volumes). In modeling investigations, O'Malley et al. 

(2015) found that it is likely that most hydraulic fracturing fluid that does not flow back is stored in 

rock pore spaces (i.e., having displaced the gas that was present there) and not fractures. The 

amount that can be stored in fractures is highly dependent on the effective interconnected pore 

lengths. 

If the injected fluid is not sequestered in the immediate vicinity of the fracture network, migration 

into drinking water resources would likely require a substantial upward hydraulic gradient (e.g., 

due to the pressures introduced during injection for hydraulic fracturing), particularly for brine 

that is denser than the groundwater in the overlying formations (Flewelling and Sharma, 2014). In 

the presence of natural gas, buoyancy of the less dense gas could potentially provide an upward flux 

(Vengosh et al., 2014). However, Flewelling and Sharma (2014) indicated that pressure 

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 et al., 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 Dake (1978). 

4 The contrast in water activity between brine and fresh water generates very substantial osmotic pressure differences 

that will drive fluids into the shale matrix. The osmosis process requires a semi-permeable membrane and a 

concentration gradient to allow the solvent to pass through it. The clay in the shale formation can provide a function 

similar to a membrane (Zhou, 2016). 
Chapter 6 – Well Injection 

6-52 

perturbations due to hydraulic fracturing operations are localized to the immediate vicinity of the 

fractures, due to the very low permeabilities of shale formations; this means that hydraulic 

fracturing operations are unlikely to generate sufficient pressure to drive fluids into shallow 

drinking water zones. Some natural conditions could also create an upward hydraulic gradient in 

the absence of any effects from hydraulic fracturing. However, these natural mechanisms have been 

found to cause very low flow rates over very long distances, yielding extremely small vertical fluxes 

in sedimentary basins. These translate to some estimated travel times of 100,000 to 100,000,000 

years across a 328 ft (100 m) thick layer with about 0.01 nD (1 × 10−23 m2) permeability (Flewelling 

and Sharma, 2014). In an area of the Permian Basin with over-pressured source rocks, Engle et al. 

(2016) concluded that chemical, isotopic, and pressure data suggest that there is little potential for 

vertical fluid migration to shallow zones in the absence of pathways such as improperly abandoned 

wells (Section 6.3.2.3). 

To account for the combined effect of capillary imbibition, well operation, and buoyancy in upward 

fluid migration, Birdsell et al. (2015a) conducted a numerical analysis over five phases of activity at 

a hypothetical Marcellus-like hydraulic fracturing site: a pre-drilling steady state, the injection of 

fluids, a shut-in period, production, and the continued migration of hydraulic fracturing fluids after 

the well is plugged and abandoned. They quantified how much hydraulic fracturing fluid flows back 

up the well after fracturing, how much reaches overlying aquifers, and how much is permanently 

sequestered by capillary imbibition (which is treated as a sink term). Their results affirmed that, 

without a pathway such as a permeable fault or leaky wellbore, it is very unlikely that hydraulic 

fracturing fluid from a deep shale could reach an overlying aquifer. However, the study did indicate 

that upward migration on the order of 328 ft (100 m) could occur through relatively lowpermeability overburden, even if no discrete, permeable pathway exists. 

6.3.2.2 Fracture Overgrowth out of the Production Zone

Fractures extending out of the intended production zone into another formation, or into an 

unintended zone within the same formation, could provide a potential fluid migration pathway into 

drinking water resources (Jackson et al., 2013d). This migration could occur either through the 

fractures themselves or in connection with other permeable subsurface features or formations 

(Figure 6-7). Such “out-of-zone fracturing” is undesirable from a production standpoint and may 

occur as a result of inadequate reservoir characterization or fracture treatment design (Eisner et al., 

2006). Some researchers have noted that fractures growing out of the targeted production zone 

could potentially contact other formations, such as higher conductivity sandstones or conventional 

hydrocarbon reservoirs, which may create an additional pathway for migration into a drinking 

water resource (Reagan et al., 2015). In addition, fractures growing out of the production zone 

could potentially intercept natural, preexisting fractures (discussed in Section 6.3.2.4) or active or

abandoned wells near the well where hydraulic fracturing is performed (discussed in Section 

6.3.2.3). 
Chapter 6 – Well Injection 

6-53 

Figure 6-7. 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 

permeable fault.

The fracture’s geometry (Section 6.3.1) affects its potential to extend beyond the intended zone and 

serve as a pathway to drinking water resources. Vertical heights of fractures created during 

hydraulic fracturing operations have been measured in several U.S. shale plays, including the 

Barnett, Woodford, Marcellus, and Eagle Ford, using microseismic monitoring and tiltmeters 

(Fisher and Warpinski, 2012). These data indicate typical fracture heights extending from tens to 

hundreds of feet.1 Davies et al. (2012) analyzed this data set and found that the maximum fracture 

height was 1,929 ft (588 m) and that 1% of the fractures had a height greater than 1,148 ft (350 m).

This may raise some questions about fractures being contained within the producing formation, as 

some Marcellus fractures were found to extend vertically for at least 1,500 ft (460 m), while the 

maximum thickness of the formation is generally 350 ft (110 m) or less (MCOR, 2012). However, 

the majority of fractures within the Marcellus were found to have heights less than 328 ft (100 m), 

suggesting limited possibilities for fracture overgrowth exceeding the separation between shale 

reservoirs and shallow aquifers (Davies et al., 2012). This is consistent with modeling results found 

by Kim and Moridis (2015) and others, as described below. Where the producing formation is not 

 

1 As described in Section 6.3.1, microseismic data represent the small amounts of seismic energy generated during 

subsurface fracturing. The Fisher and Warpinski dataset includes the top and bottom depths of mapped fracture 

treatments in the four shale plays mentioned, giving the maximum propagation length.
Chapter 6 – Well Injection 

6-54 

continuous horizontally, the lateral extent of fractures may also become important. For example, in 

the Fisher and Warpinski (2012) data set, fractures were found to extend to horizontal lengths 

greater than 1,000 ft (300 m).

Results of National Energy Technology Laboratory (NETL) research in Greene County, 

Pennsylvania, are generally consistent with those reported in the Fisher and Warpinski (2012) data 

set. Microseismic monitoring was used at six horizontal Marcellus Shale wells to identify the 

maximum upward extent of brittle deformation (i.e., rock breakage) caused by hydraulic fracturing 

(Hammack et al., 2014). At three of the six wells, fractures extending between 1,000 and 1,900 ft 

(300 and 580 m) above the Marcellus Shale were identified. Overall, approximately 40% of the 

microseismic events occurred above the Tully Limestone, the formation overlying the Marcellus 

Shale. The microseismic data suggest that fracture propagation occurs above the Tully Limestone, 

which is sometimes referred to as an upper barrier to hydraulic fracture growth (Hammack et al., 

2014). However, all microseismic events were at least 5,000 ft (2,000 m) below drinking water 

aquifers, as the Marcellus Shale is one of the deepest shale plays (Table 6-3), and no impacts to 

drinking water resources or another local gas-producing interval were identified. See Text Box 6-6

for more information on the Greene County site. 

Text Box 6-6. Monitoring at the Greene County, Pennsylvania, Hydraulic Fracturing Test Site.

Monitoring performed at the Marcellus Shale test site in Greene County, Pennsylvania, evaluated fracture 

height growth and zonal isolation during and after hydraulic fracturing operations (Hammack et al., 2014). 

The site has six horizontally drilled wells and two vertical wells that were completed into the Marcellus Shale. 

Pre-fracturing studies of the site included a 3D seismic survey to identify faults, pressure measurements, and 

baseline sampling for isotopes; drilling logs were also run. Hydraulic fracturing occurred April 24 to May 6, 

2012, and June 4 to 11, 2012. Monitoring at the site included the following:

• Microseismic monitoring was conducted during four of the six hydraulic fracturing jobs on the site,

using geophones placed in the two vertical Marcellus Shale wells. These data were used to monitor

fracture height growth above the six horizontal Marcellus Shale wells during hydraulic fracturing.

• Pressure and production data were collected from a set of existing vertical gas wells completed in

Upper Devonian/Lower Mississippian zones 3,800 to 6,100 ft (1,200 to 1,900 m) above the Marcellus.

Data were collected during and after the hydraulic fracturing jobs and used to identify any

communication between the fractured areas and the Upper Devonian/Lower Mississippian rocks.

• Chemical and isotopic analyses were conducted on gas and water produced from the Upper

Devonian/Lower Mississippian wells. Samples were analyzed for stable isotope signatures of hydrogen,

carbon, and strontium and for the presence of perfluorocarbon tracers used in 10 stages of one of the

hydraulic fracturing jobs to identify possible gas or fluid migration to overlying zones (Sharma et al.,

2014a; Sharma et al., 2014b).

As of September 2014, no evidence was found of gas or brine migration from the Marcellus Shale (Hammack 

et al., 2014), although longer-term monitoring is necessary to confirm that no impacts to overlying zones 

have occurred (Zhang et al., 2014a). 

Similarly, in Dunn County, North Dakota, there is evidence suggestive of out-of-zone fracturing in 

the Bakken Shale (U.S. EPA, 2015i). At the Killdeer site (Section 6.2.2.1), hydraulic fracturing fluids 
Chapter 6 – Well Injection 

6-55 

and produced water were released during a rupture of the casing at the Franchuk 44-20 SWH well.

Water quality characteristics at two monitoring wells located immediately downgradient of the

Franchuk well reflected a mixing of local Killdeer Aquifer water with deep formation brine. Ion and

isotope ratios used for brine fingerprinting suggest that Madison Group formations (which directly 

overlie the Bakken in the Williston Basin) were the source of the brine observed in the Killdeer

Aquifer, and the authors concluded that this provides evidence for out-of-zone fracturing (U.S. EPA, 

2015i). Industry experience also indicates that out-of-zone fracturing could be fairly common in the

Bakken and that produced water from many Bakken wells has Madison Group chemical signatures 

(Arkadakskiy and Rostron, 2013; Arkadakskiy and Rostron, 2012; Peterman et al., 2012). 

Fracture growth from a deep formation to a near-surface aquifer is generally considered to be

limited by layered geological environments and other physical constraints (Fisher and Warpinski,

2012; Daneshy, 2009). For example, differences in in-situ stresses in layers above and below the

production zone can restrict fracture height growth in sedimentary basins (Fisher and Warpinski,

2012). High-permeability layers near hydrocarbon-producing zones can reduce fracture growth by 

acting as a “thief zone” into which fluids can migrate, or by inducing a large compressive stress that

acts on the fracture (de Pater and Dong, 2009, as cited in Fisher and Warpinski, 2012). Although 

thief zones may prevent fractures from reaching shallower formations or growing to extreme

vertical lengths, they do allow fluids to migrate out of the production zone into receiving

formations, which could (depending on site-specific conditions) potentially contain drinking water

resources. A volumetric argument has also been used to discuss limits of vertical fracture growth; 

that is, the volumes of fluid needed to sustain fracture growth beyond a certain height would be

unrealistic (Fisher and Warpinski, 2012). However, as described in Section 6.3.1, fracture volume

can be greater than the volume of injected fluid due to the effects of pressurized water combined

with the effects of gas during injection (Kim and Moridis, 2015). Nevertheless, some numerical

investigations suggest that, unless unrealistically high pressures and injection rates are applied to

an extremely weak and homogeneous formation that extends up to the near surface, hydraulic 

fracturing generally induces stable and finite fracture growth in a Marcellus-type environment and

fractures are unlikely to extend into drinking water resources (Kim and Moridis, 2015). 

Modeling studies have identified other factors that can affect the containment of fractures within 

the producing formation. As discussed above, additional numerical analysis of fracture propagation

during hydraulic fracturing has demonstrated that contrasts in the geomechanical properties of

rock formations can affect fracture height containment (Gu and Siebrits, 2008) and that geological

layers present within shale gas reservoirs can limit vertical fracture propagation (Kim and Moridis,

2015). In another modeling study, Myshakin et al. (2015) applied a multi-layered geologic model to 

study whether fracture growth can extend upward through overlying strata and reach drinking

water resources in a Marcellus Shale-type environment. Most fractures were predicted either to 

extend upward to the overlying layer (about 46%) or to remain in the Marcellus Shale (about 34%).

About 20% of the fractures were predicted to extend further upward into or above the overlying

limestone. These model results are consistent with microseismic events observed above the Tully 

Limestone in Greene County, Pennsylvania (Hammack et al., 2014), where the fracture heights 

ranged from 0 to 700 ft (0 to 200 m) and most of the fractures terminated less than 100 ft (31 m)

above the top of the Marcellus.
Chapter 6 – Well Injection 

6-56 

If fractures were to propagate from the production zone to drinking water resources, other factors 

would need to be in place for fluid migration to occur. Using a numerical simulation, Reagan et al. 

(2015) investigated potential short-term migration of gas and water between a shale or tight gas 

formation and a shallower groundwater unit, assuming that a permeable pathway already exists 

between the two formations. Note that, for the purposes of this study, the pathway was assumed to 

be pre-existing, and Reagan et al. (2015) did not model the hydraulic fracturing process itself.

The subsurface system evaluated in the Reagan et al. (2015) modeling investigation included a 

horizontal well used for hydraulic fracturing and gas production, a connecting pathway between 

the producing formation and the aquifer, and a shallow vertical water well in the aquifer (Figure 

6-7). The parameters and scenarios used in the study are shown in Table 6-4; two vertical 

separation distances between the producing formation and the aquifer were investigated, along 

with a range of production zone permeabilities and other variables used to describe four 

production scenarios. The horizontal well was assigned a constant bottomhole pressure of half the 

initial pressure of the target reservoir, not accounting for any over-pressurization from hydraulic 

fracturing. (As noted in Section 6.3.2.1, over-pressurization during hydraulic fracturing can create 

an additional driving force for upward migration.) In the simulation, migration was assessed 

immediately after hydraulic fracturing and for up to a 2-year simulation period representing the 

production stage. 

Results of this modeling investigation indicate a generally downward water flow within the 

connecting fracture (i.e., flow from the aquifer through the connecting fracture into the 

hydraulically induced fractures in the production zone) with some upward migration of gas

(Reagan et al., 2015). In certain simulated cases, gas breakthrough (the appearance of gas at the 

base of the drinking water aquifer) was also observed. The key parameter affecting migration of gas 

into the aquifer was the production regime, particularly whether gas production (which drives 

migration toward the production well) was occurring in the reservoir. Simulations that included a 

producing gas well showed only a few instances of breakthrough, while simulations without gas 

production (i.e., that assumed the well was shut-in) tended to result in breakthrough. When gas 

breakthrough did occur, the breakthrough times ranged from minutes to 20 days. However, in all 

cases, the gas escape was limited in duration and scope, because the amount of gas available for 

immediate migration toward the shallow aquifer was limited to that initially stored in the 

hydraulically induced fractures after the stimulation process and prior to production. These 

simulations indicate that the target reservoir may not be able to replenish the gas that was 

available for migration prior to production. 

Based on the results of the Reagan et al. (2015) modeling study, gas production from the reservoir 

appears likely to mitigate gas migration, both by reducing the amount of available gas and 

depressurizing the induced fractures (which counters the buoyancy of any gas that may escape 

from the production zone into the connecting fracture). Production at the gas well also creates 

pressure gradients that drive a downward flow of water from the aquifer via the fracture into the 

producing formation, increasing the amount of water produced at the gas well. Furthermore, the 

effective permeability of the connecting feature is reduced during water (downward) and gas 

(upward) counter-flow within the fracture, further retarding the upward movement of gas or 
Chapter 6 – Well Injection 

6-57 

allowing gas to dissolve into the downward flow. However, Reagan et al. (2015) did find an 

increased potential for gas release from the producing formation in cases where there is no gas 

production following hydraulic fracturing. The potential for gas migration during shut-in periods 

following hydraulic fracturing and prior to production may be more significant, especially when 

out-of-zone fractures are formed. Without the effects of production, gas can rise via buoyancy, with 

any downward-flowing water from the aquifer displacing the upward-flowing gas. 

Reagan et al. (2015) also found that the permeability of a connecting fault or fracture may be an 

important factor affecting the potential upward migration of gas (although not as significant as the 

production regime). For the cases where gas escaped from the production zone, the maximum 

volume of migrating gas depended upon the permeability of the connecting feature: the higher the 

permeability, the larger the volume. The modeling results also showed that lower permeabilities 

delay the downward flow of water from the aquifer, allowing the trace amount of gas that entered 

into the fracture early in the modeled period to reach the aquifer, which was otherwise predicted to 

dissolve in the water flowing downward in the feature. Similarly, the permeabilities of the target 

reservoir, fracture volume, and the separation distance were found to affect gas migration, because 

they affected the initial amount of gas stored in the hydraulically induced fractures. In contrast, the 

permeability of the drinking water aquifer was not found to be a significant factor in the 

assessment. 

Table 6-4. Modeling parameters and scenarios investigated by Reagan et al. (2015). 

This table illustrates the range of parameters included in the Reagan et al. (2015) modeling study. See Figure 6-7, 

Figure 6-8, and Figure 6-9 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 328 ft (100 m)

Vertical separation distance between producing 

formation and drinking water aquifer

656 ft (200 m);

2,625 ft (800 m)

Producing formation permeability range 1 nD (1 x 10-21 m2);

100 nD (1 x 10-19 m2);

1 μD (1 x 10-18 m2)

Drinking water aquifer permeability 0.1 D (1 x 10-13 m2);

1 D (1 x 10-12 m2)

Initial conditions Hydrostatic

Production well bottom hole pressure Half of the initial pressure of the producing formation 

(not accounting for over-pressurization 

from hydraulic fracturing)

Production regime Production at both the water well and the gas well;

Production at only the water well;

Production at only the gas well;

No production
Chapter 6 – Well Injection 

6-58 

Model parameter or variable Values investigated in model scenarios

Fracture pathway scenarios

Connecting feature permeability 1 D (1 x 10-12 m2);

10 D (1 x 10-11 m2);

1,000 D (1 x 10-9 m2)

Offset well pathway scenarios

Lateral distance from production well to offset well 33 ft (10 m)

Cement permeability of offset well 1 μD (1 x 10-18 m2);

1 mD (1 x 10-15 m2);

1 D (1 x 10-12 m2

);

1,000 D (1 x 10-9 m2)

6.3.2.3 Migration via Fractures Intersecting with Offset Wells and Other Artificial Structures

Another potential pathway for fluid migration is one in which hydraulic fracturing fluids or 

displaced subsurface fluids move through newly created fractures into an offset well or its fracture 

network, resulting in a process called well communication (Jackson et al., 2013d). The offset well 

can be an abandoned (i.e., plugged), inactive, or actively producing well. In addition, if the offset 

well has also been used for hydraulic fracturing, the fracture networks of the two wells might 

intersect. The situation where hydraulic fractures propagate to (and inject fluid into and/or cause 

pressure increases in) other existing wells or hydraulic fractures is referred to as a “frac hit” and is 

known to occur in areas with a high density of wells (Jackson et al., 2013a). 

Frac hits can be more common in unconventional production settings compared to conventional 

production settings, due to the closer/denser well spacing (King and Valencia, 2016). Figure 6-8

provides a schematic to illustrate fractures that intercept an offset well, and Figure 6-9 depicts (in a 

simplified illustration) how the fracture networks of two such wells might intersect. This can be a 

particular concern in shallower formations, where the local least principal stress is vertical 

(resulting in more horizontal fracture propagation), and in situations where there are drinking 

water wells in the same formation as wells used for hydraulic fracturing.

Instances of well communication have been known to occur and are described in well records and 

the oil and gas literature. For example, an analysis of operator data collected by the New Mexico Oil 

Conservation Division (NM OCD) in 2013−2014 identified 120 instances of well communication in 

the San Juan Basin between 2007 and 2013 (Vaidyanathan, 2014). In some cases, well 

communication incidents have led to documented production and/or environmental problems. A 

study in the Barnett Shale noted two cases of well communication, one with a well 1,100 ft (340 m) 

away and the other with a well 2,500 ft (760 m) away from the initiating well; ultimately, one of the

offset wells had to be re-fractured because the well communication halted production (Craig et al., 

2012). In some cases, the fluids that intersect the offset well flow up the wellbore and spill onto the 

surface. In its report Review of State and Industry Spill Data: Characterization of Hydraulic 

Fracturing-Related Spills, the EPA (2015m) recorded 10 incidents in which fluid spills were 
Chapter 6 – Well Injection 

6-59 

attributed to well communication events (see Text Box 5-10 for more information on this effort).1

The Well File Review (U.S. EPA, 2016c) reports that 1% of the wells (an estimated 280 wells) 

represented in the study reported a frac hit, where the hydraulic fracturing operation documented 

in the Well File Review led to communication with a nearby well.2 (It was not possible to determine 

whether fluids reached protected groundwater resources during these frac hits based on 

information in the well files.) While the subsurface effects of frac hits have not been extensively 

studied, these cases demonstrate the possibility of fluid migration via communication with other 

wells and/or their fracture networks. More generally, well communication events can indicate 

fracture behavior that was not intended by the treatment design.

Figure 6-8. 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).

 

1 These spills are represented by line numbers 163, 236, 265, 271, 286, 287, 375, 376, 377, and 380 in Appendix B of U.S. 

EPA (2015m). 

2 280 wells (95% confidence interval: 240 – 320 wells).
Chapter 6 – Well Injection 

6-60 

Figure 6-9. Well communication (a frac hit).

This image shows a conceptualized depiction of the fractures of a newly fractured well (Well A) intersecting the 

existing fracture network created during a previous hydraulic fracturing operation in an offset well (Well B). 

Evidence of this interaction may be observed in the offset well as a pressure change, lost production, and/or 

introduction of new fluids. Depending on the condition of the offset well, this can result in fluid being spilled onto 

the surface, rupturing of cement and/or casing and hydraulic fracturing fluid leaking into subsurface formations, 

and/or fluid flowing out through existing flaws in the casing and/or cement. (Figure is not to scale.)

A well communication event is usually observed at the offset well as a pressure spike, due to the 

elevated pressure from the originating well, or as an unexpected drop in the production rate (Lawal 

et al., 2014; Jackson et al., 2013a). Ajani and Kelkar (2012) performed an analysis of frac hits in the 

Woodford Shale in Oklahoma, studying 179 wells over a 5-year period. The authors used fracturing 

records from the newly completed wells and compared them to production records from 

surrounding wells. The authors assumed that sudden changes in production of gas or water 

coinciding with fracturing at a nearby well were caused by communication between the two wells, 

and increased water production at the surrounding wells was assumed to be caused by hydraulic 

fracturing fluid flowing into these offset wells. The results of the Oklahoma study showed that 

24 wells had decreased gas production or increased water production within 60 days of the initial 

gas production at the nearby fractured well. A total of 38 wells experienced decreased gas or 

increased water production up to a distance of 7,920 ft (2,410 m), which the study authors defined 

as the distance between the midpoints of the laterals; 10 wells saw increased water production 
Chapter 6 – Well Injection 

6-61 

from as far away as 8,422 ft (2,567 m). In addition, one well showed a slight increase in gas 

production rather than a decrease.1 

Other studies of well communication events have relied on similar information. In the NM OCD 

operator data set, the typical means of detecting a well communication event was through pressure 

changes at the offset well, production lost at the offset well, and/or fluids found in the offset well. In 

some instances, well operators determined that a well was producing fluid from two different 

formations, while in one instance, the operator identified a potential well communication event due 

to an increase in production from the offset well (Vaidyanathan, 2014). In another study, Jackson et 

al. (2013a) found that the decrease in production due to well communication events was much 

greater in lower permeability reservoirs. The authors note an example where two wells 1,000 ft 

(300 m) apart communicated, reducing production in the offset well by 64%. These results indicate 

that the subsurface interactions of well networks or complex hydraulics driven by each well at a 

densely populated (with respect to wells) area are important factors to consider for the design of 

hydraulic fracturing treatments and other aspects of oil and gas production. 

The key factor affecting the likelihood of a well communication event and the impact of a frac hit is 

the location of the offset well relative to the well where hydraulic fracturing was conducted (Ajani 

and Kelkar, 2012). In the Ajani and Kelkar (2012) analysis, the likelihood of a communication event 

was less than 10% in wells more than 4,000 ft (1,000 m) apart, but rose to nearly 50% in wells less 

than 1,000 ft (300 m) apart. Well communication was also much more likely with wells drilled from 

the same pad. The affected wells were found to be in the direction of maximum horizontal stress in 

the field, which correlates with the expected direction of fracture propagation. Modeling work by 

Myshakin et al. (2015) is generally consistent with these results, indicating that the risk of fluid 

movement through pre-existing wellbores or open faults is negligible unless hydraulic fractures are

located very close to these features.2

Statistical modeling by Montague and Pinder (2015) investigated the probability that a hypothetical 

new well used for hydraulic fracturing within the area of New York underlain by the Marcellus 

Shale would intersect an existing wellbore. The results indicated that this probability would be 

from 0 to 3.45%. The model incorporated the depth of the hypothetical new well, the vertical 

growth of induced fractures, and the depth and locations of existing nearby wells. The model also 

assumed that the existing wells are vertical and fracture growth is not impacted by nearby wells or 

existing fractures. However, the authors concluded that the inclusion of horizontal wells within the 

data set could increase the chance of intersection with induced fractures. 

Well communication may be more likely to occur where there is less resistance to fracture growth. 

Such conditions may be related to existing production operations (e.g., where previous 

hydrocarbon extraction has reduced the pore pressure, changed stress fields, or affected existing 

fracture networks) or the existence of high-permeability rock units (Jackson et al., 2013a). As Ajani 

and Kelkar (2012) found in the Woodford Shale, one of the deepest major shale plays (Table 6-3), 

induced fractures tend to enter portions of the reservoir that have already been fractured as 

 

1 The numbers of wells cited in the study reflect separate analyses, and the numbers cited are not additive.

2 In the Myshakin et al. (2015) paper, the authors do not quantify or explain what is meant by “very close.”
Chapter 6 – Well Injection 

6-62 

opposed to entering previously unfractured rocks, ultimately causing interference in offset wells.

Mukherjee et al. (2000) described this tendency for asymmetric fracture growth toward depleted 

areas in low-permeability gas reservoirs due to pore pressure depletion from production at offset 

wells. The authors note that pore pressure gradients in depleted zones would affect the subsurface 

stresses. Therefore, depending on the location of the new well with respect to depleted zone(s) and 

the orientation of the existing induced fractures, the newly created fracture can be asymmetric, 

with only one wing of the fracture extending into the depleted area and developing significant 

length and conductivity (Mukherjee et al., 2000). The extent to which the depleted area affects 

fracturing depends on factors such as cumulative production, pore volume, hydrocarbon saturation, 

effective permeability, and the original reservoir or pore pressure (Mukherjee et al., 2000). 

Similarly, high-permeability rock types acting as thief zones may also cause preferential fracturing 

due to a higher leakoff rate into these layers (Jackson et al., 2013a). 

In addition to location, the potential for impact on a drinking water resource also depends on the 

condition of the offset well. (See Section 6.2 for information on the mechanical integrity of well 

components.) In their analysis, Ajani and Kelkar (2012) found a correlation between well 

communication and well age: older wells were more likely to be affected. If the cement in the 

annulus between the casing and the formation is intact and the well components can withstand the 

stress exerted by the pressure of the fluid, nothing more than an increase in pressure and extra 

production of fluids would occur during a well communication event. However, if the offset well is 

not able to withstand the pressure of the hydraulic fracturing fluid, well components could fail

(Figure 6-4), allowing fluid to migrate out of the well. 

The highest pressures most hydraulic fracturing wells will face during their life spans occur during 

the process of fracturing (Section 3.3). In some cases, temporary equipment is installed in wells 

during fracturing to protect the well against the increased pressure. Therefore, many producing 

wells may not be designed to withstand pressures typical of hydraulic fracturing (Enform, 2013) 

and can experience problems when fracturing occurs in nearby wells. Depending on the location of 

the weakest point in the offset well, this could result in fluid being spilled onto the surface; 

rupturing of cement and/or casing and hydraulic fracturing fluid leaking into subsurface 

formations; and/or fluid flowing out through existing flaws in the casing and/or cement. (See 

Chapters 5 and 7 for additional information on how such spills can affect drinking water resources.) 

For example, a documented well communication event near Innisfail, Alberta, Canada (Text Box 

6-7) occurred when several well components failed, because they were not rated to handle the 

increased pressure caused by the well communication (ERCB, 2012). In addition, if the fractures 

were to intersect an uncemented portion of the wellbore, the fluids could potentially migrate into 

formations that are uncemented along the wellbore.

In older wells near a hydraulic fracturing operation, plugs and cement can degrade over time; in 

some cases, abandoned wells may never have been plugged properly. Before the 1950s, most well 

plugging efforts were focused on preventing water from the surface from entering oil fields. As a 

result, many wells from that period were abandoned with little or no cement (NPC, 2011b). This 

can be a significant issue in areas with legacy (i.e., historic) oil and gas exploration and when wells 

are re-entered and hydraulically fractured (or re-fractured) to increase production in a reservoir. In 
Chapter 6 – Well Injection 

6-63 

one study, 18 of 29 plugged and abandoned wells in Quebec were found to show signs of leakage

(Council of Canadian Academies, 2014). Similarly, a PA DEP report cited three cases where

migration of natural gas had been caused by well communication events with old, abandoned wells, 

including one case where private drinking water wells were affected (PA DEP, 2009c). In Tioga 

County, Pennsylvania, following hydraulic fracturing of a shale gas well, an abandoned well nearby 

produced a 30 ft (9 m) geyser of brine and gas for more than a week (Dilmore et al., 2015). 

Text Box 6-7. Well Communication at a Horizontal Well near Innisfail, Alberta, Canada.

In most cases, well communication during fracturing results in a pressure surge accompanied by a drop in gas 

production and additional flow of produced water or hydraulic fracturing fluid at an offset well. However, if 

the offset well is not capable of withstanding the high pressures of fracturing, more significant damage can 

occur.

In January 2012, fracturing at a horizontal well near Innisfail in Alberta, Canada, caused a surface spill of 

fracturing and formation fluids at a nearby operating vertical oil well. According to the investigation report by 

the Alberta Energy Resources Conservation Board (ERCB, 2012), pressure began rising at the vertical well 

less than two hours after fracturing ended at the horizontal well.

Several components of the vertical well facility―including surface piping, discharge hoses, fuel gas lines, and 

the pressure relief valve associated with compression at the well―were not rated to handle the increased 

pressure and failed. Ultimately, the spill released, in addition to gas, an estimated 19,816 gal (75,012 L3) of 

hydraulic fracturing fluid, brine, and oil covering an area of approximately 656 ft by 738 ft (200 m by 225 m). 

The ERCB determined that the lateral of the horizontal well passed within 423 ft (129 m) of the vertical well 

at a depth of approximately 6,070 ft (1,850 m) below the surface in the same formation. The operating 

company had estimated a fracture half-length of 262 to 295 ft (80 to 90 m) based on a general fracture model 

for the field.1 While there were no regulatory requirements for spacing hydraulic fracturing operations in 

place at the time, the 423 ft (129 m) distance was out of compliance with the company’s internal policy to 

space fractures from adjacent wells at least 1.5 times the predicted half-length. The company also did not 

notify the operators of the vertical well of the hydraulic fracturing operations. The incident prompted the 

ERCB to issue Bulletin 2012-02―Hydraulic Fracturing: Interwellbore Communication between Energy Wells, 

which outlines expectations for avoiding well communication events and preventing adverse effects on offset 

wells.

Various studies estimate the number of abandoned wells in the United States to be significant. The 

Interstate Oil and Gas Compact Commission (IOGCC, 2008) estimates that over one million wells 

were drilled in the United States prior to the enactment of state oil and gas regulations, and the 

status and location of many of these wells are unknown. A recent estimate of wells completed 

before the adoption of statewide well abandonment criteria in 1957 in Pennsylvania placed the 

range at 305,000 to 390,000 wells in the state, with more than 176,000 of those wells likely 

abandoned pre-1957 (Dilmore et al., 2015). As of 2000, PA DEP’s well plugging program reported 

that it had documented 44,700 wells that had been plugged and 8,000 that were in need of 

plugging, and approximately 184,000 additional wells with an unknown location and status (PA 

 

1 The fracture half-length is the radial distance from a wellbore to the outer tip of a fracture propagated from that well 

(Schlumberger, 2014). 
Chapter 6 – Well Injection 

6-64 

DEP, 2000). A similar evaluation from New York State found that the number of unplugged wells 

was growing in the state despite an active well plugging program (Bishop, 2013). In the Midwest, 

Sminchak et al. (2014) examined two areas of historical oil and gas exploration as part of an 

investigation of potential carbon dioxide sequestration sites. They found that a 4.3 mi by 4.3 mi (6.9 

km by 6.9 km) square area in Michigan contained 22 abandoned oil and gas wells and a 9.3 mi by 

9.3 mi (15.0 km by 15.0 km) square area in Ohio contained 359 abandoned oil and gas wells. 

Various state programs exist to plug identified orphaned wells, but they face the challenge of 

identifying and addressing a large number of wells.1 In some cases, remote sensing technologies can 

be used to identify wells for which no records exist. For example, an NETL study in Pennsylvania 

found that helicopter-based high-resolution magnetic surveys can be used to accurately locate wells 

with steel casing; wells with no steel casing exhibit weak or no magnetic anomaly and are not 

detected by such surveys (Veloski et al., 2015). Chapter 10 includes a discussion of factors and 

practices, including those related to active and abandoned wells near hydraulic fracturing 

operations, that can reduce the frequency of impacts to drinking water quality.

The Reagan et al. (2015) numerical modeling study included an assessment of migration via an 

offset well as part of its investigation of potential fluid migration from a producing formation into a 

shallower groundwater unit (Section 6.3.2.2). For the offset well pathway, it was assumed that the 

hydraulically induced fractures intercepted an older offset well with deteriorated components. 

(This assessment can also be applicable to cases where potential migration may occur via the 

production well-related pathways discussed in Section 6.2) The highest permeability value tested 

for the connecting feature represented a case with an open wellbore. A key assumption for this 

investigation was that the offset well was already directly connected to a permeable feature in the 

reservoir or within the overburden. 

Similar to the cases for permeable faults or fractures discussed in Section 6.3.2.2, the study 

investigated the effect of multiple well- and formation-related variables on potential fluid migration 

(Table 6-4). Based on the simulation results, an offset well pathway can have a greater potential for 

gas release from the production zone into a shallower groundwater unit than the fracture pathway 

discussed in Section 6.3.2.2 (Reagan et al., 2015). This difference is primarily due to the total pore 

volume of the connecting pathway within the offset well; if the offset well pathway has a 

significantly lower pore volume compared to the fracture pathway, this would reduce possible gas 

storage in the connecting feature and increase the speed of buoyancy-dependent migration. 

However, as with the fracture scenario, the gas available for migration in this case is still limited to 

the gas that is initially stored in the hydraulically induced fractures. Accordingly, any incidents of 

gas breakthrough in the model results were limited in both duration and magnitude. 

In their modeling study, Reagan et al. (2015) found that production at the gas well (the well used 

for hydraulic fracturing) also affects the potential upward migration of gas and its arrival times at 

the drinking water formation due to its effect on the driving forces (e.g., pressure gradient). Similar 

to the fracture cases described in Section 6.3.2.2, production in the target reservoir appears to 

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.
Chapter 6 – Well Injection 

6-65 

available for upward migration and by creating a pressure gradient toward the production well. 

Only scenarios without the mitigating feature of gas production result in upward migration into the 

aquifer. This assessment also found a generally downward water flow within the connecting well 

pathway, which is more pronounced when the production well is operating and there is depressurization within the fractures. The producing formation and aquifer permeabilities appear not 

to be significant factors for upward gas migration via this pathway. Instead, Reagan et al. (2015)

found the permeability of the connecting well to be the key factor affecting the migration of gas to 

the aquifer and the water well. Very low permeabilities (less than 1 mD, or 1 × 10−15 m2) for the 

connecting well lead to no migration of gas into the aquifer regardless of the vertical separation 

distance, whereas larger permeabilities presented a greater potential for gas breakthrough. 

Brownlow et al. (2016) also modeled communication with an abandoned well. The modeling 

exercise was based on operator data from the Eagle Ford Shale. Two types of cases were modeled: 

cases with an open (unplugged) abandoned well (which the authors note are known to occur in 

Texas) and cases with an abandoned well that was converted into a water well after the lower 

portion of the well had been filled with drilling mud (a practice allowed in Texas until 1967). The 

modeling results indicated that fluid could potentially migrate up both types of abandoned wells,

with relatively greater flow rates in open abandoned wells and in abandoned wells closer to the 

well used for hydraulic fracturing. Similar to the Reagan et al. (2015) study, the production regime 

was also a key factor; when production and flowback were included in the simulation, they were 

found to inhibit upward migration. Modeled flow rates through the mud-filled well were 

comparable to those found by Reagan et al. (2015) with higher flows predicted through the open 

well. 

A similar study was conducted by Nowamooz et al. (2015), who modeled a hypothetical well in the 

Utica Shale in Quebec. They assumed a 7.9 in (200 mm) wellbore with an approximately 2 in (51 

mm) annulus space filled with intact cement. The researchers varied the permeability of the cement 

from 1 μD (1 × 10−19 m2) to 1 mD (1 × 10−15 m2). The results indicated that, at the highest 

permeability of 1 mD, a flow of methane of 1.02 × 10-2 ft3/day (2.9 x 10-4 m3/d) was possible. This 

was two orders of magnitude higher than the flow when the cement permeability was 1 μD 

(1 × 10−19 m2). The wellbore permeabilities used by Nowamooz et al. (2015) appear to be consistent 

with actual permeabilities observed in the field, which can vary widely. For example, a study of 31 

abandoned oil and gas wells in Pennsylvania found effective permeability values along the 

wellbores in the range of 10−6 to 102 mD (1 × 10−21 to 1 × 10−13 m2) (Kang et al., 2015). 

In the same way that fractures can propagate to intersect offset wells, they can also potentially 

intersect other artificial subsurface structures including mine shafts or solution mining sites. No 

known incidents of this type of migration have been documented. However, the Bureau of Land 

Management (BLM) has identified over 48,000 abandoned mines in the United States and is adding 

new mines to its inventory every year (BLM, 2015). In addition, the Well File Review identified an 

estimated 800 cases where wells used for hydraulic fracturing were drilled through mining voids, 

and an additional 90 cases of drilling through gas storage zones or wastewater disposal zones (U.S. 
Chapter 6 – Well Injection 

6-66 

EPA, 2015n).1,2 The analysis suggests emplacing cement within such zones can be challenging, 

which, in turn, could lead to a loss of zonal isolation (as described in Section 6.2) and create a 

pathway for fluid migration.

6.3.2.4 Migration via Fractures Intersecting Geologic Features

Potential fluid migration via natural, permeable fault or fracture zones in conjunction with

hydraulic fracturing has been recognized as a potential contamination hazard for several decades

(Harrison, 1983). Natural fracture systems have a strong influence on the success of a fracture

treatment, and the topic has been studied extensively from the perspective of optimizing treatment 

design (e.g., Dahi Taleghani and Olson, 2011; Weng et al., 2011; Vulgamore et al., 2007). While 

porous flow in unfractured shale or tight sand formations is assumed to be negligible due to very 

low formation permeabilities (as discussed in Section 6.3.2.1), the presence of small natural 

fractures known as “microfractures” within tight sand or shale formations is widely recognized, and 

these fractures affect fluid flow and production strategies. Naturally occurring permeable faults 

and larger-scale fractures within or between formations can potentially allow for more significant 

flow pathways out of the production zone (Jackson et al., 2013d). Figure 6-7 illustrates the concept 

of induced fractures intersecting with permeable faults or fractures extending out of the target 

reservoir.3

The specific effects of natural fractures on fluid migration, and the mechanisms by which these 

effects occur, are not completely understood. While naturally occurring microfractures can impact 

the growth of induced fractures (e.g., by affecting the tensile strength of a shale layer), studies 

based on modeling and monitoring data generally do not indicate that they contribute to fracture 

growth in a way that could affect the frequency or severity of impacts. Microfractures could affect 

fluid flow patterns near the induced fractures by increasing the effective contact area. Conversely, 

these microfractures could act as capillary traps for the hydraulic fracturing fluid during treatment 

(contributing to fluid leakoff) and potentially hinder hydrocarbon flow due to lower gas relative 

permeabilities (Dahi Taleghani et al., 2013). Ryan et al. (2015) suggested that some natural fracture 

processes/patterns (such as the presence of two subvertical fracture sets) can contribute to 

upward gas migration, while others (such as small fracture sets with low connectivity that are 

confined to individual geologic layers) can preclude it.

In some areas, larger-scale geologic features may affect potential fluid flow pathways. As discussed 

in Text Box 6-3, baseline measurements taken before shale gas development show evidence of 

thermogenic methane in some shallow aquifers, suggesting that, in some cases, natural subsurface 

pathways exist and might allow for naturally occurring migration of gas over geologic time

(Robertson et al., 2012). There is also evidence demonstrating that gas undergoes mixing in 

1 800 wells (95% confidence interval: 10 – 1,900 wells). 

2 90 wells (95% confidence interval: 50 – 100 wells). 

3 Faults and fractures can exhibit a range of permeabilities. For example, permeable (also referred to as “transmissive” or 

“conductive”) faults or fault segments have enough permeability to allow fluids to flow along or across them, while others 

are relatively impermeable and can serve as barriers to flow. These differences in permeability are associated with 

geologic conditions such as rock type, depth, and stress regime. Generally, when researchers refer to the potential for 

migration via natural geologic features, it is assumed that these features are sufficiently permeable to serve as a pathway.
Chapter 6 – Well Injection 

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subsurface pathways (Baldassare et al., 2014; Molofsky et al., 2013; Fountain and Jacobi, 2000). 

Warner et al. (2012) compared recent sampling results to data published in the 1980s and found 

geochemical evidence for migration of fluids through natural pathways between deep underlying 

formations and shallow aquifers―pathways that the authors suggest could lead to contamination 

from hydraulic fracturing activities. In northeastern Pennsylvania, there is evidence that brine from 

deep saline formations has migrated into shallow aquifers over geologic time, preferentially 

following certain geologic structures (Llewellyn, 2014). However, this depends on local geologic 

characteristics and does not appear to happen in all locations; for example, in the Monongahela 

River Basin in West Virginia, shallow groundwater samples did not show evidence of mixing with 

deep brines (Boothroyd et al., 2016). As described in Chapter 7, karst features (created by the 

dissolution of soluble rock) can also serve as a potential pathway of fluid movement on a faster time 

scale. 

Monitoring data show that the presence of natural faults and fractures can affect both the height 

and width of induced hydraulic fractures. When faults are present, relatively larger microseismic 

responses are seen and larger fracture growth can occur, as described below. Rutledge and Phillips 

(2003) suggested that, for a hydraulic fracturing operation in East Texas, pressurizing existing 

fractures (rather than creating new hydraulic fractures) was the primary process that controlled

enhanced permeability and fracture network conductivity at the site. Salehi and Ciezobka (2013)

used microseismic data to investigate the effects of natural fractures in the Marcellus Shale and 

concluded that fracture treatments are more efficient in areas with clusters or “swarms” of small 

natural fractures, while areas without these fracture swarms require more thorough stimulation.

These microseismic data show that swarms of natural fractures within a shale formation can result 

in a fracture network with a larger width-to-height ratio (i.e., a shorter and wider network) than 

would be expected in a zone with a low degree of natural fracturing. 

A few studies have used monitoring data to specifically investigate the effect of natural faults and 

fractures on the vertical extent of induced fractures. A statistical analysis of microseismic data by

Shapiro et al. (2011) found that fault rupture (movement along a fault) from hydraulic fracturing is 

limited by the extent of the stimulated rock volume and is unlikely to extend beyond the fracture 

network. However, as demonstrated by microseismic data presented by Vulgamore et al. (2007), in 

some settings, the fracture network—and, in this case, the possibility of fault rupture—could

extend laterally for thousands of feet. In the Fisher and Warpinski (2012) data set (Section 6.3.2.2), 

the greatest fracture heights occurred when the hydraulic fractures intersected pre-existing faults. 

Similarly, Hammack et al. (2014) reported that fracture growth seen above the Marcellus Shale is 

consistent with the inferred extent of pre-existing faults at the Greene County, Pennsylvania, 

research site (Section 6.3.2.2 and Text Box 6-6). The authors suggested that clusters of 

microseismic events may have occurred where preexisting small faults or natural fractures were 

present above the Marcellus Shale. Viñal (2015) used time-lapse multi-component seismic 

monitoring to monitor the overburden of the Montney Shale during a hydraulic fracturing 

operation in Alberta, Canada. The researchers found increases in the anisotropy in the overburden, 

which they interpreted as fractures being propagated along natural faults out of the shale and into 

the overburden. At a site in Ohio, Skoumal et al. (2015) found that hydraulic fracturing induced a 

rupture along a pre-existing fault approximately 0.6 mi (1 km) from the hydraulic fracturing 
Chapter 6 – Well Injection 

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operation. Using a new monitoring method known as tomographic fracturing imaging, Lacazette 

and Geiser (2013) also found vertical hydraulic fracturing fluid movement from a production well

into a natural fracture network for distances of up to 0.6 mi (1.0 km). However, Davies et al. (2013)

questioned whether this technique actually measures hydraulic fracturing fluid movement.

Modeling studies have also investigated whether hydraulic fracturing operations are likely to 

reactivate faults and create a potential fluid migration pathway into shallow aquifers. Results from

one study suggest that, under specific circumstances, interaction with a permeable fault could 

result in fluid migration to the surface but only on relatively long (ca. 1,000 year) time scales 

(Gassiat et al., 2013). These findings have been disputed in the literature due to certain suggested 

limitations of the study, including the model setup, assumptions, and calibration; unrealistic fault 

representation; lack of constraints on fluid overpressure; and exclusion of the capillary imbibition 

effect (Birdsell et al., 2015b; Flewelling and Sharma, 2015). In response to these critiques, the 

authors stated that their work was a parametric study in which the model geometry, parameter,

and boundary conditions were defined based on data collected from multiple shale gas basins, and

the objective of the study was not to calibrate results to a specific site (Lefebvre et al., 2015). Other 

researchers reject the notion that open, permeable faults coexist with hydrocarbon accumulation

(Flewelling et al., 2013). However, it is unclear whether the existence of faults in low permeability 

reservoirs affects the accumulation of hydrocarbons because, under natural conditions, the flow of

gas may be limited due to capillary tension.

Like the other pathways discussed in this section, other conditions in addition to the physical

presence of a permeable fault or fracture would need to exist for fluid migration to a drinking water

resource to occur. The modeling study conducted by Reagan et al. (2015) and discussed in Section

6.3.2.2 indicates that, if such a permeable feature exists, the transport of gas and fluid flow would 

strongly depend upon the production regime and, to a lesser degree, the features’ permeability and

the separation between the reservoir and the aquifer. In addition, the pressure distribution within

the reservoir (e.g., over-pressurized vs. hydrostatic conditions) will affect the fluid flow through

fractures/faults. As a result, the presence of multiple geologic and well-related factors can increase

the potential for fluid migration into drinking water resources. For example, in the Mamm Creek

area of Colorado (Section 6.2.2.4), mechanical integrity and drilling-related problems likely acted in 

concert with natural fracture systems to result in a gas seep into surface water and shallow 

groundwater (Crescent, 2011). A similar situation occurred in southeastern Bradford County,

Pennsylvania (discussed in Section 6.2), where natural fractures intersected an uncemented casing

annulus and allowed gas to flow from the annulus into nearby domestic wells and a stream 

(Llewellyn et al., 2015). 

Other modeling studies investigating the potential of fluid migration related to existing faults and

fractures have given mixed results. Pfunt et al. (2016) performed modeling based on conditions in 

the North German Basin, i.e., deep geological settings where undisturbed cap rocks are present

between the fractured formation and shallow aquifers. Their modeling indicated that the hydraulic 

fracturing fluid did not reach the near-surface area either during hydraulic fracturing operations or

in the long-term in the presence of highly permeable pathways (fault zones, fractures). Like
Chapter 6 – Well Injection 

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previous modeling studies, the authors found that the injection pressure and permeability of the 

connecting fault are two important factors that control upward fluid migration.

Rutqvist et al. (2013) found that, while somewhat larger microseismic events are possible in the 

presence of faults, repeated events and a seismic slip would amount to a total rupture length of 

164 ft (50 m) or less along a fault, not far enough to allow fluid migration between a deep gas 

reservoir (approximately 6,562 ft or 2,000 m deep) and a shallow aquifer. A follow-up study using 

more sophisticated three-dimensional modeling techniques also found that deep hydraulic 

fracturing is unlikely to create a direct flow path into a shallow aquifer, even when hydraulic 

fracturing fluid is injected directly into a fault (Rutqvist et al., 2015). Similarly, a modeling study 

that investigated potential fluid migration from hydraulic fracturing in Germany found potential

vertical fluid migration up to 164 ft (50 m) in a scenario with high fault zone permeability, although 

the authors note this is likely an overestimate because their goal was to “assess an upper margin of 

the risk” associated with fluid transport (Lange et al., 2013). More generally, results from Rutqvist 

et al. (2013) indicate that fracturing along an initially impermeable fault (as is expected in a shale 

gas formation) would result in numerous small microseismic events that act to prevent larger 

events from occurring (and, therefore, prevent the creation of more extensive potential pathways).

Schwartz (2015) modeled methane flow through a hypothetical permeable fault at a well in 

Germany. Methane flow was modeled through a permeable leakage zone that was 0.1 ft by 13 ft 

(0.03 m by 4 m) with an assumed permeability in the range of approximately 100 D to of 10,000 D 

(1 × 10-10 m2 to 1 × 10-8 m2). The model indicated that methane could reach a drinking water aquifer 

approximately 2,953 ft (900 m) above the gas zone in about a half a day and reach a maximum flow 

after two days. According to the model results, methane entering the aquifer led to an increase in 

pH, the release of negatively charged constituents such as chromium, and the adsorption of 

positively charged ions such as arsenic. Decreasing the permeability of the leakage zone by a factor 

of 100 increased the travel time by a factor of four. In another study, Myshakin et al. (2015)

modeled brine migration through a natural and induced fracture network. Their results indicated 

that the main pathway for vertical migration of hydraulic fracturing fluid to overlying layers is 

through the induced fractures, and not the natural fractures. The location of hydraulic fractures 

relative to each other affects the extent of brine migration into overburden layers; compared to 

single fractures separated by large distances, closely spaced fractures were associated with higher 

pressures in—and, consequently, more brine migration into—overlying layers. 

6.4 Synthesis

In the injection stage of the hydraulic fracturing water cycle, operators inject hydraulic fracturing 

fluids into a well under pressure that is high enough to fracture the production zone. These fluids 

flow through the well and then out into the surrounding formation, where they create fractures in 

the rock, allowing hydrocarbons to flow through the fractures, to the well, and then up the 

production string. 

The production well and the surrounding geologic features function as a system that is often 

designed with multiple elements that can isolate hydrocarbon-bearing zones and water-bearing 

zones, including groundwater resources, from each other. This physical isolation optimizes oil and 
Chapter 6 – Well Injection 

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gas production and can protect drinking water resources via isolation within the well (by the casing 

and cement) and/or through the presence of multiple layers of subsurface rock between the target 

formations where hydraulic fracturing occurs and drinking water aquifers.

6.4.1 Summary of Findings

In this chapter, we consider impacts to drinking water resources to occur if hydraulic fracturing 

fluids or other subsurface fluids affected by hydraulic fracturing enter and adversely impact the 

quality of groundwater resources. Potential pathways for fluid movement to drinking water 

resources may be linked to one or more components of the well and/or features of the subsurface 

geologic system. If present, these potential pathways can, in combination with the high pressures 

under which fluids are injected and pressure changes within the subsurface due to hydraulic 

fracturing, result in the subsurface movement of fluids to drinking water resources. 

The potential for these pathways to exist or form has been investigated through modeling studies 

that simulate subsurface responses to hydraulic fracturing, and demonstrated via case studies and 

other monitoring efforts. In addition, the development of some of these pathways—and fluid 

movement along them—has been documented. It is important to note that, if multiple barriers 

afforded by the well design and the presence of subsurface rock formations are present, the 

development of a pathway within this system does not necessarily result in an impact on a drinking 

water resource.

6.4.1.1 Fluid Movement via the Well 

A production well undergoing hydraulic fracturing is subject to higher stresses during the relatively 

brief hydraulic fracturing phase than during any other period of activity in the life of the well. If the 

well cannot withstand the stresses experienced during hydraulic fracturing operations, pathways 

associated with the casing and cement can form that can result in the unintended movement of 

fluids into the surrounding environment (Section 6.2). 

Multiple barriers within the well, including casing, cement, and a completion assembly can, if 

present, isolate hydrocarbon-bearing formations from drinking water resources located at a 

different depth. However, inadequate construction, defects in or degradation of the casing or 

cement, and/or the absence of redundancies such as multiple layers of casing and proper 

emplacement of cement can allow fluid movement into drinking water resources. Various studies of 

wells in the Marcellus Shale showed failure rates between 3 and 10%, depending on the type of 

failure studied (contamination of drinking water resources may or may not have occurred at these 

wells). The EPA’s Well File Review found that 3% of all hydraulic fracturing jobs involved a 

downhole mechanical integrity failure, which generally resulted in hydraulic fracturing fluid 

entering the annular space between the casing and formation or between two casing strings. 

Ensuring proper well design and mechanical integrity—particularly proper cement placement and 

quality—are important actions for preventing unintended fluid migration along the wellbore. While 

not all of the mechanical integrity failures described above resulted in fluid movement to—or 

contamination of—a drinking water resource, aspects of well design that lead to increased failure 
Chapter 6 – Well Injection 

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rates have the potential to increase the frequency or severity of impacts to drinking water quality 

associated with hydraulic fracturing operations.

6.4.1.2 Fluid Movement within Subsurface Geologic Formations

Potential subsurface pathways for fluid migration to drinking water resources include flow of fluids 

out of the production zone into formations above or below it, fractures extending out of the 

production zone or into other induced fracture networks, intersections of fractures with abandoned 

or active wells, and hydraulically induced fractures intersecting with faults or natural fractures 

(Section 6.3). 

Vertical separation between the zone where hydraulic fracturing operations occur and drinking 

water resources reduces the potential for fluid migration to impact the quality of drinking water 

resources. However, not all hydraulic fracturing operations are characterized by large vertical 

distances between the production zone and drinking water resources. In coalbed methane plays, 

which are typically shallower than shale gas plays, these separation distances can be smaller than 

in other types of formations. Also, in certain areas, hydraulic fracturing is known to take place in 

formations containing water that meets the salinity threshold that is used in some definitions of a 

drinking water resource. 

Lateral separation between wells undergoing hydraulic fracturing and other wells (including active 

and abandoned wells) also reduces the potential for fluid migration to impact drinking water 

resources. While some operators design fracturing treatments to communicate with the fractures of 

another well and optimize oil and gas production, unintended communication between two wells or 

their fracture systems can lead to spills in an offset well, which is an indicator of hydraulic 

fracturing treatments extending beyond their planned design. These well communication incidents, 

or “frac hits,” have been reported in New Mexico, Oklahoma, and a few other locations. Surface 

spills from well communication incidents have also been documented. Based on the available 

information, frac hits most commonly occur on multi-well pads and when wells are spaced less than 

1,100 ft (340 m) apart, but they have been observed at wells up to 8,422 ft (2,567 m) away from a 

well undergoing hydraulic fracturing. 

6.4.1.3 Impacts to Drinking Water Resources 

We identified some example cases in the literature where the pathways associated with hydraulic 

fracturing resulted in an impact on the quality of drinking water resources. 

One of these cases took place in Bainbridge Township, Ohio, in 2007. Failure to cement 

over-pressured formations through which a production well passed—and proceeding with the 

hydraulic fracturing operation without adequate cement and an extended period during which the 

well was shut in—led to a buildup of natural gas within the well annulus and high pressures within 

the well. This ultimately resulted in movement of gas from the production zone into local drinking 

water aquifers (Section 6.2.2.2). Twenty-six domestic drinking water wells were taken off-line and 

the houses were connected to a public water system after the incident due to elevated methane 

levels. 
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Casings at a production well near Killdeer, North Dakota, ruptured in 2010 following a pressure 

spike during hydraulic fracturing, allowing fluids to escape to the surface. Brine and tert-butyl 

alcohol were detected in two nearby monitoring wells. Following an analysis of potential sources, 

the only source consistent with the conditions observed in the two impacted water wells was the 

well that ruptured during hydraulic fracturing. There is also evidence that out-of-zone fracturing 

occurred at the well (Sections 6.2.2.1 and 6.3.2.2).

There are other cases where contamination of or changes to the quality of drinking water resources 

near hydraulic fracturing operations were identified. Hydraulic fracturing remains a potential 

contributing cause in these cases. For example:

• Migration of stray gas into drinking water resources involves many potential routes, 

including poorly constructed casing and naturally existing or induced fractures in 

subsurface formations. Multiple pathways for fluid movement may have worked in concert 

in northeastern Pennsylvania (possibly due to cement issues or sustained casing pressure), 

the Raton Basin in Colorado (where fluid migration may have occurred along natural rock 

features or faulty well seals), and the Wattenberg field in Colorado (where the surface 

casing depth and the presence of uncemented gas zones are major factors in determining 

the likelihood of mechanical integrity failures and contamination). While the sources of 

methane identified in drinking water wells in each study area could be determined with 

varying degrees of certainty, attempts to definitively identify the pathways of migration 

have generally been inconclusive (Text Box 6-3).

• At the East Mamm Creek drilling area in Colorado, inadequate placement of cement allowed 

the migration of methane through natural faults and fractures in the area. This case 

illustrates how construction issues, sustained casing pressure, and the presence of natural 

faults and fractures, in conjunction with elevated pressures associated with hydraulic 

fracturing, can work together to create a pathway for fluids to migrate toward drinking 

water resources (Sections 6.2.2.2 and 6.3.2.4). 

Additionally, there are places in the subsurface where oil and gas resources and drinking water 

resources co-exist in the same formation. Evidence we examined indicates that some hydraulic 

fracturing for oil and gas occurs within formations where the groundwater has a salinity of less 

than 10,000 mg/L TDS. By definition, this results in the introduction of hydraulic fracturing fluids 

into formations that meet both the Safe Drinking Water Act’s salinity-based definition of an 

underground source of drinking water and the broader definition of a drinking water resource 

developed for this assessment. According to the data we examined, these formations are generally 

in the western United States, e.g., near Pavillion, Wyoming. Hydraulic fracturing in a drinking water 

resource may be of concern in the short-term (where people are currently using these zones as a 

drinking water supply) or the long-term (if drought or other conditions necessitate the future use 

of these zones for drinking water).

There are other cases in which production wells associated with hydraulic fracturing are alleged to 

have caused contamination of drinking water resources. Data limitations in most of those cases 
Chapter 6 – Well Injection 

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(including the unavailability of information in litigation settlements resulting in sealed documents)

make it difficult to assess whether or not hydraulic fracturing was a cause of the contamination. 

6.4.2 Factors Affecting Frequency or Severity of Impacts

The multiple barriers within the hydraulic fracturing well and the presence of subsurface lowpermeability geologic formations between the production zone and drinking water resources

isolate fluids from drinking water resources. Because of this, any factors that affect the integrity of

the system comprised of the well and the surrounding geology have the potential to affect the

frequency or severity of impacts on drinking water quality. The primary factors that can affect the

frequency or severity of impacts are: (1) the construction and condition of the well that is being

hydraulically fractured, (2) the amount of vertical separation between the production zone and

formations that contain drinking water resources, and (3) the location, depth, and condition of

nearby wells or natural faults or fractures.

The presence and condition of the well’s casing and cement are key factors that affect the frequency 

or severity of impacts to drinking water resources. Even in wells where there is substantial vertical

separation (e.g., thousands of feet), defects in the well can, in theory, allow fluid movement over

significant vertical distance. For example, fully cemented surface casing that extends through the

base of drinking water resources is a key protective component of the well. Risk evaluation studies

of a limited number of injection wells show that, if the surface casing is not set deeper than the

bottom of the drinking water resource, the risk of aquifer contamination increases a thousand-fold. 

A review of wells that were hydraulically fractured in the Wattenberg field in Colorado showed that

wells with fewer casing and cementing barriers across gas-bearing zones exhibited higher rates of

failures. Most, but not all, wells used in hydraulic fracturing operations have fully cemented surface 

casing.

The absence of or defects in casing or cement can be the result of inadequate design or

construction, including fewer layers of protective casing or when cement is incomplete (i.e., not

present across all oil-gas- or water-bearing formations), of inadequate quality, or improperly 

emplaced. Wells that were constructed pursuant to older, less stringent requirements have a

greater likelihood of exhibiting mechanical integrity problems associated with inadequate design 

and/or construction.

Deviated and horizontal wells may exhibit more casing and cement problems compared to vertical

wells. Some (but not all) studies have shown that sustained casing pressure—a buildup of pressure

within the well annulus that can indicate the presence of leaks—occurs more frequently in deviated

and horizontal wells compared to vertical wells. Cement integrity problems can arise as a result of

challenges in centering the casing and placing the cement in these wells. Absent efforts to ensure

the emplacement of sufficient cement that is of adequate integrity, the increased use of these wells

in hydraulic fracturing operations has the potential to increase the frequency at which associated

cementing problems occur. This, in turn, has the potential to increase the frequency of impacts to

the quality of drinking water resources. 
Chapter 6 – Well Injection 

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Even in optimally designed wells, degradation of the casing and cement as they age or due to the 

cumulative effects of formation or operational stresses exerted on the well over time (e.g., cyclic 

stresses in multi-stage fractures) can impact the mechanical integrity of the well and affect the 

frequency of impacts to drinking water quality. Older wells exhibit more mechanical integrity 

problems compared to newer wells when hydraulically fractured or re-fractured. If mechanical 

integrity issues exist but are not detected and subsequently addressed, hydraulic fracturing fluids 

or other fluids can move into drinking water resources and the concentrations of contaminants in 

those drinking water resources—and therefore the severity of the impact—can increase.

In areas where there is little or no vertical separation between the production zone and drinking 

water resources, there is a greater potential to increase the frequency or severity of impacts to 

drinking water quality. For example, when the vertical separation is relatively small and other 

subsurface pathways (e.g., artificial penetrations) are present, the potential for these pathways to 

provide a more direct link between the production zone and a drinking water resource is greater 

than if there is a large separation. As described above, there are places where hydraulic fracturing 

operations occur in formations meeting the salinity threshold that is used in some definitions of a 

drinking water resource. The practice of injecting hydraulic fracturing fluids into a formation that 

also contains a drinking water resource can affect the quality of that water, because it is likely some 

of that fluid remains in the formation following hydraulic fracturing. The properties (e.g., chemical 

composition, toxicity, etc.) of hydraulic fracturing fluids or naturally occurring fluids that migrate to 

drinking water resources can affect the severity of the impact on the quality of those resources (see 

Chapter 9 for more information on the chemicals used in hydraulic fracturing fluids).

Where the separation between the production zone and drinking water resources is small, and 

where natural or induced fractures that transect the layers between these formations are present, 

there is a potential for increased frequency of impacts to drinking water quality via induced or 

natural fractures or faults. (Impacts via well-related pathways can also be a concern in these 

situations, as described above.) 

Research shows that fractures created during hydraulic fracturing can extend out of the production 

zone, and that the vertical component of fracture growth is generally greater in deeper formations 

than shallow formations. Out-of-zone fracturing could be a concern in deeper formations if there is 

little vertical separation between the production zone and a deep drinking water resource and 

fractures propagate to unintended vertical heights. If out-of-zone fracturing is not detected (e.g., via 

monitoring) and subsequently addressed, the impacts to the quality of drinking water resources 

associated with fluid movement via these induced fractures have the potential to become more 

severe. 

Regardless of the extent of the vertical separation between the production zone and drinking water 

resources, the presence of active or abandoned wells near hydraulic fracturing operations can 

increase the potential for hydraulic fracturing fluids to move to drinking water resources. For 

example, a deficiency in the construction of a nearby well (or degradation of the well’s 

components), can provide a pathway for movement of hydraulic fracturing fluids, methane, or 

brines that might affect drinking water quality. If the fractures intersect an uncemented portion of a 
Chapter 6 – Well Injection 

6-75 

nearby wellbore, the fluids can potentially migrate along that wellbore into any formations where

the well is not cemented.

The frequency of impacts to the quality of drinking water resources may increase where wells are

densely spaced (particularly in shallow hydraulic fracturing operations where more fracture 

propagation is expected to be in the horizontal direction). The frequency of impacts may also be

higher in mature oil and gas fields that pre-date the use of construction/plugging methods that can 

withstand the stresses associated with hydraulic fracturing operations. In these mature fields, wells 

tend to be older so degradation is a concern, and the location or condition of abandoned wells may 

not be documented. Based on the information presented in this chapter, the increased use of

hydraulic fracturing in horizontal wells and in multiple wells on a single pad can increase the

likelihood that these pathways could develop. This, in turn, could increase the frequency at which

impacts on drinking water quality occur. 

See Chapter 10 for a discussion of factors and practices that can reduce the frequency or severity of

impacts to drinking water quality. 

6.4.3 Uncertainties 

Generally, less is known about the occurrence of (or potential for) impacts of injection-related

pathways in the subsurface than for other components of the hydraulic fracturing water cycle, 

which tend to be easier to observe and measure. Furthermore, while there is a large amount of

information available on production wells in general, there is little information that is both specific

to hydraulic fracturing operations and readily accessible across the states to form a national 

picture. 

6.4.3.1 Limited Availability of Information Specific to Hydraulic Fracturing Operations 

There is extensive information available on the design goals for hydraulically fractured oil and gas 

wells (i.e., to address the stresses imposed by high-pressure, high-volume injection), including from 

industry-developed best practices documents. Additionally, many studies have documented how

production wells have historically been constructed, how they perform, and the rates at which they

experience problems that can lead to pathways for fluid movement. However, because of possible

differences in well construction and operational practices, it is unknown how historical well 

performance studies apply to wells used in hydraulic fracturing operations.

Because wells that have been hydraulically fractured must withstand many of the same downhole

stresses as other production wells, we consider studies of the pathways for impacts to drinking

water quality in production wells to be relevant to identifying the potential pathways relevant to

hydraulic fracturing operations. However, without specific data on the as-built construction of wells 

used in hydraulic fracturing operations, we cannot definitively state whether these wells are

consistently constructed to withstand the stresses they may encounter.

There is also, in general, very limited information available on the monitoring and performance of

wells used in hydraulic fracturing operations. Published information is sparse regarding

mechanical integrity tests (MITs) performed during and after hydraulic fracturing, the frequency at
Chapter 6 – Well Injection 

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which mechanical integrity issues arise in wells used for hydraulic fracturing, and the degree and

speed with which identified issues are addressed. There is also little information available

regarding MIT results for the original hydraulic fracturing event in wells built for that purpose, for

wells that are later re-fractured, or for existing, older wells not initially constructed for hydraulic 

fracturing but repurposed for that use. 

These limitations on hydraulic fracturing-specific information make it difficult to provide definitive

estimates of the rate at which wells used in hydraulic fracturing operations experience the types of

mechanical integrity problems that can contribute to the movement of hydraulic fracturing fluids or

other fluids to drinking water resources.

There is also a limited number of peer-reviewed published studies based on groundwater sampling

that provide evidence to assess whether formation brines, hydraulic fracturing fluids, or gas move

in unintended ways through the subsurface during and after hydraulic fracturing. Subsurface

monitoring data (i.e., data that characterize the presence, migration, or transformation of fluids

within subsurface formations related to hydraulic fracturing operations) are scarce relative to the 

tens of thousands of oil and gas wells that are estimated to be hydraulically fractured across the

country each year (see Chapter 3 for more information on the occurrence of hydraulic fracturing in

the United States).

Information on fluid movement within the subsurface and the extent of fractures that develop

during hydraulic fracturing operations is also limited. For example, limited information is available

in the published literature on how flow regimes or other subsurface processes change at sites 

where hydraulic fracturing is conducted. Instead, much of the available research, and therefore the 

literature, addresses how hydraulic fracturing and other production technologies perform to

optimize hydrocarbon production. In addition, much of the published data on fracture propagation

are for shale formations, and no large-scale data sets on fracture growth in other unconventional

formations exist or are publicly available. 

These limitations on hydraulic fracturing-specific information make it difficult to provide definitive 

estimates of the rate at which wells used in hydraulic fracturing operations experience the types of 

mechanical integrity problems that can contribute to unintended fluid movement. 

6.4.3.2 Limited Systematic, Accessible Data on Well Performance or Subsurface Movement 

While the oil and gas industry generates a large amount of information on well performance as part

of operations, most of this is proprietary, or otherwise not readily available to the public in a 

compiled or summary manner. Therefore, no national or readily accessible way exists to evaluate 

the design and performance of individual wells or wells in a region, particularly in the context of

local geology or the presence of other wells and/or hydraulic fracturing operations. Many states 

have large amounts of operator-submitted data, but information about construction practices or the

performance of individual wells is typically not in a searchable or aggregated form that would

enable assessments of well performance under varying settings, conditions, or timeframes.

Although it is collected in some cases, there is no collection, reporting, or publishing of baseline

(pre-drilling and/or pre-fracturing) and post-fracturing monitoring data on a national basis that
Chapter 6 – Well Injection 

6-77 

could indicate the presence or absence of hydraulic fracturing-related fluids in shallow zones and

whether or not migration of those fluids has occurred. (See Chapter 10 for additional discussion of

data limitations.) Ideally, data from groundwater monitoring are needed to complement theories

and modeling on potential pathways and fluid migration.

While some of the types of impacts described above can occur quickly (i.e., on the scale of days or

weeks, as with mechanical integrity problems or well communication events), other impacts (e.g., in 

slow-moving, deep groundwater) may be detectable only on much longer timescales. Without 

comprehensive collection and review of information about how hydraulic fracturing operations

perform, fluid movement could occur without early detection, which could, in turn, increase the 

severity of any resultant impacts to drinking water quality. For example, testing the mechanical

integrity of wells, monitoring the extent of the fractures that form, and conducting pre- and posthydraulic fracturing water quality monitoring can detect fluid movement (or the potential for fluid

movement) and provide opportunities to mitigate or minimize the severity of impacts associated 

with unforeseen events. 

The limited amount of available information also hinders our ability to evaluate how frequently 

drinking water impacts are occurring, the probability that these impacts occur, or to what extent

they are tied to specific well construction, operation, and maintenance practices. This also

significantly limits our ability to evaluate the aggregate potential for hydraulic fracturing

operations to affect drinking water resources or to identify the potential cause of drinking water

contamination in areas where hydraulic fracturing occurs. The absence of this information greatly 

limits the ability to make quantitative statements about the frequency or severity of these impacts. 

6.4.4 Conclusions 

The production well and the surrounding geologic features function as a system that provides

multiple barriers that can isolate hydrocarbon-bearing zones and water-bearing zones, including

drinking water resources. Because of this, factors affecting the integrity of any of these barriers

have the potential to adversely affect the quality of drinking water resources.

We have identified a number of pathways by which hydraulic fracturing fluids can reach and affect

the quality of drinking water resources. These pathways include migration via inadequate casing

and/or cement in the hydraulic fracturing well, fluid movement in the subsurface via fractures 

extending out of the target zone, or vertical fluid movement via other natural or artificial structures.

The primary factors affecting the frequency or severity of impacts to drinking water quality 

associated with hydraulic fracturing operations include the condition of the casing and cement of

the production well and their placement relative to drinking water resources, the extent of the

vertical separation between the production zone and drinking water resources, and the presence

and condition of offset wells or natural faults or fractures near the hydraulic fracturing operation.

There is evidence that, in some cases highlighted in the literature, these pathways have formed and

the quality of drinking water resources has been impacted. We do not know the frequency of such

impacts associated with the injection stage of the hydraulic fracturing water cycle, however. This is

related to the following: the subsurface environment is geologically complex, the relevant
Chapter 6 – Well Injection 

6-78 

production processes cannot be directly observed, and publicly available data that can support an 

evaluation of the impacts of hydraulic fracturing on the quality of drinking water resources is, in 

general, very limited. 
Chapter 7 – Produced Water Handling

7-1 

Chapter 7. Produced Water Handling

Abstract 

Produced water is a byproduct of hydrocarbon production and flows to the surface through the 

production well, along with oil and gas. Operators must store and dispose of (or in some cases treat) 

large amounts of non-potable produced water, either on site or off site, and spills or releases of 

produced water have the potential to impact drinking water resources. Unlike produced water from 

conventional oil and gas production, produced water generated following hydraulic fracturing initially 

contains returned hydraulic fracturing fluids. Much of the hydraulic fracturing fluid remains below 

ground; the median amount of fluid returned to the surface is 30% or less. Up to several million gallons 

of water can be produced from each well, with production generally decreasing with time. 

Produced water contains several classes of constituents: salts, metals, radioactive materials, dissolved 

organic compounds, and hydraulic fracturing chemicals and their transformation products (the result of 

reactions of these chemicals in the subsurface). The concentrations of these constituents change with 

time, as the initially returning hydraulic fracturing fluid blends with formation water. Typically, this 

means that the produced water becomes more saline with time. Produced water composition and 

volume vary from well to well, both among different formations and within formations. A large number 

of organic compounds have been identified in produced water, many of which are naturally occurring 

petroleum hydrocarbons; some are known hydraulic fracturing chemicals. Only a few transformation 

products have been identified, and they include chlorinated organics. 

Spills and releases of produced water with a variety of causes have been documented at different steps 

in the production process. The causes include human error, equipment or container failure (for instance, 

pipeline, tank or storage pit leaks), accidents, and storms. Unauthorized discharges may account for 

some releases as well. An estimated half of the spills are less than 1,000 gal (3,800 L). A small number of 

much larger spills has been documented, including a spill of 2.9 million gal (11 million L). Both shortand long-term impacts to soil, groundwater, and surface from spills have occurred. For many spills, 

however, the impacts are unknown. The potential of spills of produced water to affect drinking water 

resources depends upon the release volume, duration, and composition, as well as watershed and water 

body characteristics.

Data are lacking to characterize the severity and frequency of impacts on a nationwide scale. Suspected 

local-scale impacts often require an extensive multiple lines-of-evidence investigation to determine 

their cause. Further, when investigations do take place, the lack of baseline water quality data can make 

it difficult to determine the cause and severity of the impact. In such cases, additional data are necessary 

to determine the full extent of the impact of releases of produced water.
Chapter 7 – Produced Water Handling

7-2 

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Chapter 7 – Produced Water Handling

7-3 

7. Produced Water Handling

7.1 Introduction 

Water is a byproduct of oil and gas production. After the hydraulic fracturing of the formation is 

completed, the injection pressure is reduced, and a possible inactive period where the well is “shut 

in” is completed, water is allowed to flow back from the well to prepare for oil or gas production.1

This return-flow water may contain chemicals injected as part of the hydraulic fracturing fluid, 

chemicals naturally occurring in the formation, or the products of reactions that take place in the 

formation. Initially this water, sometimes called flowback, is mostly hydraulic fracturing fluid, but 

as time goes on, water chemistry becomes more similar to water associated with the formation. For 

formations containing saline water (brine), the salinity of the returned water increases as time 

passes as the result of increased contact time between the hydraulic fracturing fluid and the 

formation and inclusion of an increased portion of formation water. For this assessment, and 

consistent with industry practice, the term produced water is used to refer to any water flowing 

from the oil or gas well. 

Produced water is piped directly to an injection well or stored and accumulated at the surface for 

eventual management by injection into disposal wells, transport to wastewater treatment plants, 

reuse, or in some cases, placement in evaporation pits or permitted direct discharge. See Text Box 

ES-11 and Section 8.4 for discussion of these management practices. 

Produced water spills and releases can occur due to several causes, including events associated 

with pipelines, transportation, blowouts, and storage. Impacts to drinking water resources can 

occur if this released water enters surface water bodies or reaches groundwater. Such impacts may 

result in the water becoming unfit for consumption, either through obvious taste and odor 

considerations or the constituents in the water exceeding hazard levels (Chapter 9). Once released 

to the environment, transport of chemical constituents depends on the characteristics of the:

• Spill (volume, duration, concentration); 

• Fluid (density as influenced by salinity); 

• Chemicals (volatility, sorption, solubility); and 

• Site-specific environmental characteristics (surface topography and location of surface 

water bodies, the type of the soil and aquifer materials, layering and heterogeneity of 

rocks, and the presence of dissolved oxygen and other factors needed to support 

biodegradation, and the presence of inorganic species that affect metal transport).

This chapter provides characterization of produced water and also provides background 

information for the coverage of wastewater disposal and reuse in Chapter 8. Chapter 7 addresses 

the characteristics of produced water including per-well generation of produced water. Chapter 8 

considers management of this water, now called wastewater, at an aggregate level, and thus 

 

1 There can be no shut-in period at all or it can last several weeks (Stepan et al., 2010). 
Chapter 7 – Produced Water Handling

7-4 

discusses state, regional, and national estimates of treatment volumes. While Chapter 7 considers 

impacts from several types of unintentional releases, Chapter 8 focuses on impacts that are 

associated with wastewater management practices. One specific issue, leakage from pits and 

impoundments, is introduced in Chapter 7 as one of several avenues for accidental releases, with a 

more detailed exploration of the use of pits in wastewater management presented in Chapter 8. 

Chapter 7 begins with a review of definitions for flowback and produced water in Section 7.1.1. 

Definitions are followed by a discussion in Section 7.2 of water volumes per well, first presenting 

data on the volume and percent of hydraulic fracturing fluid returned to the surface and then 

presenting data on the volume of water returned during production. These data all represent the 

response of individual wells. Because of the need to have aggregated volumes for estimating 

wastewater treatment loadings, estimates of total volumes are given in Section 8.2.

Chapter 7 continues with discussion of the chemical composition of produced water (Section 7.3). 

Because the composition of produced water is only known through analysis of samples, laboratory 

methods and their limitations are described in Section 7.3.1. Time-dependent changes in 

composition are discussed via three specific examples in Section 7.3.3, followed by discussion of 

five types of constituents: salts, metals, radioactive materials, organics, and known hydraulic 

fracturing additives in Section 7.3.4. The chemical and geological processes controlling the chemical 

composition of produced water are described in Appendix E. Spatial and temporal trends in the 

composition of produced water are illustrated with examples from the literature and data compiled 

for this report (Section 7.3.5).

The potential for impacts on drinking water resources of produced water releases and spills are 

described based on reported spill incidents (Section 7.4), and examples of spills from specific 

sources and data compilation studies are given in Section 7.4.2. The potential for impacts is 

described using contaminant transport principles in Section 7.6. The chapter concludes with a 

discussion of uncertainties and knowledge gaps, factors that influence the severity of impacts, and 

major findings (Section 7.7).

7.1.1 Definitions

Multiple definitions exist for the terms flowback and produced water. Appendix Section E.1 gives 

examples of definitions used by different organizations. These differing definitions reflect differing 

usage of the terms among various groups and that produced water reflects the continuously 

varying mixture between returning injection fluid and formation water. The majority of produced 

water definitions are fundamentally similar. The following definition is used in this report for 

produced water: any type of water that flows from the subsurface through oil and gas wells to the 

surface as a by-product of oil and gas production. Thus produced water can variously refer to 

returned hydraulic fracturing fluid, formation water alone, or a mixture of the two. 

The term flowback has two major meanings. First is the process used to prepare the well for 

production by allowing excess liquids and proppant to return to the surface. The second use of the 

term is to refer to fluids predominantly containing hydraulic fracturing fluid that return to the 

surface. Because formation water can contact and mix with injection fluids, the distinction between 

returning hydraulic fracturing fluid and formation water is not clear. Definitions of flowback are 
Chapter 7 – Produced Water Handling

7-5 

operational in the sense that they include some characteristic of the oil and gas operation (i.e., 

fluids returning within 30 days). These reflect that during the early phases of operation, a higher 

concentration of chemical additives is expected and later, water is characteristic of the formation. 

Because we use existing literature in our review, we do not introduce a preferred definition of 

flowback, and describe all water flowing from the well as produced water.

7.2 Volume of Hydraulic Fracturing Flowback and Produced Water

Veil (2015) estimated that, in 2012, all types (i.e., from conventional and unconventional 

reservoirs) of U.S. onshore and offshore oil and gas production generated 8.90 x 1011 gal (3.37 x 

1012 L) of produced water. More details and state-level estimates are given in Section 8.2. This 

section presents information on flowback and produced water volume over various time scales, and 

where possible, on a per-well and per-formation basis, because characteristics and volume of 

flowback and produced water vary by well, formation, and time.

The amount of produced water from a well varies and depends on several factors, including 

production, formation, and operational factors. Production factors include the amount of fluid 

injected, the type of hydrocarbon produced (gas or liquid), and the location within the formation. 

Formation factors include the formation pressure, the interaction between the formation and 

injected fluid (capillary forces), and reactions within the reservoir. Operational factors include the 

volume of the fractured production zone that includes the length of well segments and the height 

and width of the fractures. Certain types of problems also influence water production, including 

possible loss of mechanical integrity and subsurface communication between wells, both of which 

can result in an unexpected increase in water production (U.S. GAO, 2012; Byrnes, 2011; DOE, 

2011a; GWPC and ALL Consulting, 2009; Reynolds and Kiker, 2003). 

The processes that allow gas and liquids to flow are related to the conditions along the faces of 

fractures. Byrnes (2011) conceptualized fluid flow across the fracture face as being composed of 

three phases. The first is characterized by forced imbibition of fluid into the reservoir and occurs 

during and immediately following fracture stimulation.1 Second is fluid redistribution within the 

reservoir rock, due to capillary forces. Estimates have shown that 50% or more of fracturing fluid 

could be captured within the Marcellus shale if imbibition drives water 2 to 6 in (5 to 15 cm) into 

the formation (Engelder, 2012; Byrnes, 2011; He, 2011). In the last phase, water flows out of the 

formation when the well is opened and pressure is reduced in the wellbore and fractures. The 

purpose of this phase is to recover as much of the injected fluid as possible (Byrnes, 2011) to allow 

higher oil or gas flow rates. The length of the last phase and, consequently, the amount of water 

removed, depends on factors such as the amount of injected fluid, the permeability and relative 

permeability of the reservoir, capillary pressure properties of the reservoir rock, and the pressure 

near the fracture faces.2 The well can be shut in for varying time periods depending on operator 

scheduling, surface facility construction and connection thereto, or other reasons.

 

1 The displacement of a non-wet fluid (i.e., gas) by a wet fluid (typically water). Adapted from Dake (1978). 

2 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 Dake (1978), when this effective 

permeability is normalized by the absolute permeability, the resulting relationship is known as the relative permeability.
Chapter 7 – Produced Water Handling

7-6 

7.2.1 Flowback of Injected Hydraulic Fracturing Fluid

The amount of water produced by wells within the first few days following fracturing varies from

formation to formation. Wells in the Mississippi Lime and Permian Basin can produce 1 million gal

(3.8 million L) in the first 10 days of production. Wells in the Barnett, Eagle Ford, Granite Wash,

Cleveland/Tonkawa Sand, Niobrara, Marcellus, and Utica Shales can produce 300,000 to 1 million 

gal (1.14 to 3.78 million L) within the first 10 days. Haynesville wells produce less, about 250,000

gal (950,000 L) (Mantell, 2013). Data show that the rate of water produced during the flowback

period decreases as time passes (Ziemkiewicz et al., 2014; Hansen et al., 2013; Hayes, 2009). 

It is not possible to specify precisely the amount of injected fluids that return in the flowback,

because there is not a clear distinction between flowback and produced water, and the indicators

(e.g., salinity and radioactivity, to name two) are not routinely monitored (GWPC and ALL

Consulting, 2009). Rather, flowback estimates usually relate the amount of produced water

measured at a given time after fracturing as a percentage of the total amount of injected fluid.

Estimates of the fraction of injected hydraulic fracturing fluid that returns as flowback are highly

variable (U.S. EPA, 2016d; Vengosh et al., 2014; Mantell, 2013; Vidic et al., 2013; Minnich, 2011; Xu 

et al., 2011). The maxima are less than 85% in all but one of the examples given in Table 7-1, Table

7-2, and Table 7-3, and most of the median values are less than 30%. In some cases, the amount of

flowback is greater than the amount of injected hydraulic fracturing fluid, and the additional water

comes from the formation (Nicot et al., 2014) or from a conductive pathway from an adjacent

formation (Arkadakskiy and Rostron, 2013). See Appendix Section E.2.1 for more details.

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. 

From Mantell (2013). 

Produced water (flowback) 

within the first 10 days 

after completion 

Produced water as a 

percentage of average water 

use per well

Formation

Approx. total average 

water use per well 

(million gal)

Low estimate 

(million gal)

High or only 

estimate 

(million gal)

Low estimate 

(% of total 

water use)

High or only 

estimate (% of 

total water use)

Gas shale plays (primarily dry gas)

Barnetta 3.4 0.3 1.0 9% 29% 

Marcellusa 4.5 0.3 1.0 7% 22%

Haynesville 5.4 -- 0.25 -- 5% 

Liquid plays (gas, oil, condensate)

Mississippi 

Lime

2.1 -- 1.0 -- 48% 
Chapter 7 – Produced Water Handling

7-7 

Produced water (flowback) 

within the first 10 days 

after completion 

Produced water as a 

percentage of average water 

use per well

Formation

Approx. total average 

water use per well 

(million gal)

Low estimate 

(million gal)

High or only 

estimate 

(million gal)

Low estimate 

(% of total 

water use)

High or only 

estimate (% of 

total water use)

Cleveland/

Tonkawa 2.7 0.3 1.0 11% 37% 

Niobrara 3.7 0.3 1.0 8% 27% 

Utica 3.8 0.3 1.0 8% 26%

Granite 

Wash 4.8 0.3 1.0 6% 21% 

Eagle Ford 4.9 0.3 1.0 6% 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.

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 5% – 35% Hayes (2011)

Marcellus Shale 10% – 25% Minnich (2011) Initial flowback

ND–Bakken 25% EERC (2013)

Estimates with reference to specific data evaluation

Short duration

Marcellus Shale 10% Clark et al. (2013) 0 – 10 days

TX―Barnett 20% Clark et al. (2013) 0 – 10 days

TX―Haynesville 5% Clark et al. (2013) 0 – 10 days

AR―Fayetteville 10% Clark et al. (2013) 0 – 10 days

Medium duration

WV―Marcellus 8% Hansen et al. (2013) 30 days

Marcellus Shale 24% Hayes (2011, 2009) Average from 19 wells, 90 

days
Chapter 7 – Produced Water Handling

7-8 

Location–formation

Produced water as 

percentage of injected fluid Reference Comment

Long duration

TX―Barnett ~100%a Nicot et al. (2014) 72 months

WV―Marcellus 10% – 30% Ziemkiewicz et al. (2014) Up to 115 months

TX―Eagle Ford <20% Nicot and Scanlon (2012) Lifetime

Unspecified duration

PA―Marcellus 6% Hansen et al. (2013)

a Approximate median with large variability: 5th percentile of 20% and 90th percentile of 350%.

Table 7-3. Flowback water characteristics for wells in unconventional reservoirs.

Source: U.S. EPA (2016d). The formation-level data used to develop Tables 7-3 and 7-4 appear in Appendix Table E-1. 

Fracturing fluid 

(million gal)

Flowback 

(percent of fracturing fluid returned)

Resource 

type Well type

Weighted 

average Range

Data 

points

Weighted 

average Range

Data 

points

Horizontal 4.2 0.091–24 80,388 7% 0%–580% 7,377

Shale Directional 1.4 0.037–20 340 33% 1%–57% 36

Vertical 1.1 0.015–19 5,197 96% 2%–581% 57

Horizontal 3.4 0.069–12 7,301 12% 0%–60% 75

Tight Directional 0.05 0.046–4 3,581 10% 0%–60% 342

Vertical 1 0.016–4 10,852 4% 0%–60% 130

7.2.2 Produced Water Volumes

Mantell (2013, 2011) described the amount of produced water over the long term as high, 

moderate, or low for several formations. Wells in the Barnett Shale, Cleveland/Tonkawa Sand, 

Mississippi Lime, and the Permian Basin can produce more than 1,000 gal (3,800 L) of water per 

million cubic feet (MMCF) of gas. The most water-productive of these can be as high as 

5,000 gal (19,000 L) per MMCF of gas. As a specific example, a high water producing formation in 

the western United States was described as producing 4,200 gal (16,000 L) per MMCF of gas for the 

life of the well (McElreath, 2011). The well was fractured and stimulated with about 4 million gal 

(15 million L) of water and returned 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 remainder of the first year. The Niobrara, Granite Wash, Eagle 

Ford, Haynesville, and Fayetteville Shales are relatively dry formations (with small amounts of 

naturally occurring formation water) and produce between 500 and 2,000 gal (1,900 to 7,600 L) of 
Chapter 7 – Produced Water Handling

7-9 

produced water per MMCF of gas (Mantell, 2013). The Utica and Marcellus Shales are viewed as 

drier still and produce less than 200 gal (760 L) per MMCF of gas.

Wells producing in various formation show high produced water volume variability, including the 

Barnett Shale, which was attributed by Nicot et al. (2014) to a few wells with exceptionally high 

water production. Some of these wells produced more than the amount of injected fracturing fluid. 

Wells in conventional and unconventional reservoirs produce differing amounts of water. 

Individual hydraulically fractured wells producing gas from the Marcellus Shale produced more 

water than hydraulically fractured wells in conventional wells in Pennsylvania (Lutz et al., 2013). 

However, on a per-unit of gas produced basis, wells producing from the Marcellus Shale generate 

less water (35%), than those in the conventional formations. 

The EPA (2016d) reported characteristics of long-term produced water for hydraulically fractured 

shale and tight formations (Table 7-4). For shale, horizontal wells produced more water (1,100 

gal/day; 4,200 L/day) than vertical wells (500 gal/day; 1,900 L/day). Typically, this would be 

attributed to the longer length of the production zone in horizontal laterals than in vertical wells. 

Table 7-4. Long-term produced water generation rates (gal/day per well) for wells in 

unconventional reservoirs. 

Source: U.S. EPA (2016d). The formation-level data used to develop Tables 7-3 and 7-4 appear in Appendix Table E-1. 

Long-Term Produced Water Generation Rates

(gal per day per well)

Resource type Well type Weighted average Range Data points

Horizontal 1,100 0–29,000 43,893

Shale Directional 820 0.83–12,000 1,493

Vertical 500 4.8–51,000 12,551

Horizontal 980 10–120,000 4,692

Tight Directional 390 15–8,200 10,784

Vertical 650 0.71–2100 34,624

In an example from the Pennsylvania Marcellus Shale, the EPA determined that, for vertical wells in 

unconventional reservoirs, 6% of water came from drilling, 35% from flowback, and 59% from 

long-term produced water; for horizontal wells, the corresponding numbers were 9%, 33%, and 

58% (U.S. EPA, 2016d). This result agrees with the U.S. Department of Energy (DOE, 2011a) who 

concluded that the characteristic small amount of produced water from the Marcellus Shale was 

due either to its low water saturation or low relative permeability to water (see Section 6.3.2.1). For 

these dry formations, low shale permeability and high capillarity cause water to imbibe into the 

formation, where some is retained permanently. 
Chapter 7 – Produced Water Handling

7-10 

7.2.2.1 Time Trends

High rates of water production (flowback) typically occur in the first few months after hydraulic 

fracturing, followed by rates reduced by an order of magnitude (e.g., Nicot et al., 2014). In many 

cases half of the total produced water from a well is generated in the first year. Similarly, the EPA 

(2016d) reported a general rule of thumb that, for unconventional reservoirs, the volume of 

flowback (which occurs over a short period of time) is roughly equal to the volume of long-term 

produced water. These trends in produced water volumes occur within the timeline of hydraulic 

fracturing activities (Section 3.3), and show that the large, initial return volumes of flowback last 

for several weeks, whereas the lower-rate produced water phase can last for years (Figure 7-1). 

Figure 7-1. Generalized examples of produced water flow from five formations. 

Actual produced water flows vary by location, play, basin, and amount of water used for hydraulic fracturing (EWI, 

2015). Figure used with permission.

7.2.2.2 Coalbed Methane

Water is pumped from coal seams to reduce pressure so that gas adsorbed to the surface of the coal 

can flow to the production well (Guerra et al., 2011). Consequently, CBM tends to produce large 

volumes of water early on: more than conventional gas-bearing formations (U.S. GAO, 2012) 

(Figure 7-2). Within producing CBM formations, water production can vary for unknown reasons 

(U.S. GAO, 2012). As an example, data show that CBM production in the Powder River Basin 

produces 16 times more water than that in the San Juan Basin (U.S. GAO, 2012). 
Chapter 7 – Produced Water Handling

7-11 

Figure 7-2. Typical produced water volume for a coal bed methane well in the western United 

States.

Source: Guerra et al. (2011). 

7.3 Chemical Composition of Produced Water

For hydraulically fractured wells, the chemical composition of produced water changes from being 

similar to the injected hydraulic fracturing fluid to reflecting a mixture of hydraulic fracturing 

fluids, naturally occurring hydrocarbons, transformation products, and formation water. Initial 

produced water data show continuous changes in chemical composition and reflect processes 

occurring in the formation (Section 7.3.3). The data presented on longer-term produced water 

represent water that is primarily associated with the formation, rather than the hydraulic 

fracturing fluid (Section 7.3.4). Unlike the hydraulic fracturing fluid, the composition of which may 

be disclosed, compositional data on produced water comes from laboratory analysis of samples. 

Because of this reliance, we first discuss sampling and analysis of produced water, and especially 

note the limitations of existing analytical methods for organic chemicals and radionuclides.1 It is 

important to note that the analytical methods can differ depending on the purpose of the analysis. 

Specifically, advanced laboratory methods have been used to identify unknown organic 

constituents of produced water (Section 7.3.1), routine methods are used for pre-drilling sampling, 

and a combination of methods may be needed for assessing environmental impacts (Section 

7.4.2.5).

7.3.1 Determination of Produced Water Composition

Recent advances in analytical methods for produced water have allowed detection and 

quantification of a broad range of organic compounds, including those associated with hydraulic 

 

1 Chemical components of produced water are described below.
Chapter 7 – Produced Water Handling

7-12 

fracturing fluid (Section 7.3.4.7 and Appendix E.3.5.). These studies make clear that standard 

analytical methods are not adequate for detecting and quantifying the numerous organic chemicals, 

both naturally occurring and anthropogenic, that are now known to occur in produced water 

(Lester et al., 2015; Maguire-Boyle and Barron, 2014; Thurman et al., 2014). Similarly, methods 

commonly applied for the analysis of radionuclides in drinking water may suffer from analytical 

interferences that result in poor data quality (Maxwell et al., 2016; Ying et al., 2015; Zhang et al., 

2015b; Nelson et al., 2014; U.S. EPA, 2014i, 2004b). In these instances, alternative methods that 

have been developed to support the nuclear materials production and waste industry provide more 

reliable approaches to ensure adequate detection limits and avoid sample matrix interferences that 

are anticipated for the high salinity and concentrations of organic constituents that may be present 

in produced water samples.1 Development of advanced or non-routine methods for both organics 

and inorganics (especially radium) suggests that data generated from earlier methods may be less 

reliable that those developed by the new methods (Nelson et al., 2014), and that advanced 

analytical techniques are needed to detect or quantify some analytes. 

The compositional data that follow in this chapter and Appendix E rely on the analytical procedures 

used in measurement and were summarized as noted from numerous produced water studies or 

compilations, such as the U.S. Geological Survey (USGS) produced water database (Blondes et al., 

2014). 

7.3.2 Factors Influencing Produced Water Composition

Several interacting factors influence the chemical composition of produced water: (1) the 

composition of injected hydraulic fracturing fluids, (2) the targeted geological formation and 

associated hydrocarbon products, (3) the stratigraphic environment, and (4) subsurface processes 

and residence time (Barbot et al., 2013; Chapman et al., 2012; Dahm et al., 2011; Blauch et al., 

2009). 

The mineralogy and structure of a formation are determined initially by deposition, when rock 

grains settle out of their transporting medium (Marshak, 2004). Generally, shale forms from clays 

that were deposited in deep, oxygen-poor marine environments, and sandstone can form from sand 

deposited in shallow marine environments (Ali et al., 2010; U.S. EPA, 2004a). Coal forms when 

carbon-rich plant matter collects in shallow peat swamps. In the United States, coal formed in both 

freshwater (northern Rocky Mountains) and marginal-marine environments (Alabama’s Black 

Warrior formation) (NRC, 2010; Horsey, 1981). Consequently, shale and sandstone produced water 

are expected to be saline, and CBM water may be much less so.

7.3.3 Produced Water Composition During the Flowback Period

The chemistry of produced water changes over time, especially during the first days or weeks after 

hydraulic fracturing. Generally, produced water concentrations of cations, anions, metals, naturally 

occurring radioactive material (NORM), and organics increase as time goes on (Barbot et al., 2013; 

Haluszczak et al., 2013; Chapman et al., 2012; Davis et al., 2012; Gregory et al., 2011; Blauch et al., 

 

1 For guidance in planning, implementing, and assessing projects that require laboratory analysis of radionuclides, see 

U.S. EPA (2004b). 
Chapter 7 – Produced Water Handling

7-13 

2009). The causes include precipitation and dissolution of salts, carbonates, sulfates, and silicates; 

pyrite oxidation; leaching and biotransformation of organic compounds; and mobilization of NORM 

and trace elements. Concurrent precipitation of sulfates (e.g., BaSO4) and carbonates (e.g., CaCO3) 

alongside decreases in pH, alkalinity, dissolved carbon, and microbial abundance and diversity 

occur over time after hydraulic fracturing (Orem et al., 2014; Barbot et al., 2013; Murali Mohan et 

al., 2013; Davis et al., 2012; Blauch et al., 2009; Brinck and Frost, 2007). Leaching of organics 

appears to be a result of injected and formation fluids associating with shale and coal strata (Orem 

et al., 2014). Concentrations of organics in CBM produced water decrease with time, possibly due to 

the depletion of coal-associated water through formation pumping (Orem et al., 2007). 

7.3.3.1 Total Dissolved Solids

Produced water total dissolved solids concentrations (TDS) increase by varying degrees because of 

the formation’s geological origin. As an example, TDS concentrations increased to upper bound 

values in samples from four Marcellus Shale gas wells (Chapman et al., 2012) (Figure 7-3). The 

increased TDS was composed of increased sodium, calcium, and chloride (Chapman et al., 2012; 

Blauch et al., 2009). Similarly, TDS in flowback from the Westmoreland County wells started low 

and exceeded that of typical seawater (35,000 mg/L) within three days (Chapman et al., 2012). In a 

similar study, wells with hydraulic fracturing fluid containing less than 1,000 mg/L saw TDS 

concentrations increase above a median value of 200,000 mg/L within 90 days (Hayes, 2009). 

Figure 7-3. TDS concentrations measured through time for injected fluid (at 0 days), and 

produced water samples from four Marcellus Shale gas wells in three southwest Pennsylvania 

counties.

Data from Chapman et al. (2012). 
Chapter 7 – Produced Water Handling

7-14 

7.3.3.2 Radionuclides

Shales and sandstones naturally contain various radionuclides (Sturchio et al., 2001).1 Radium in 

pore waters or adsorbed onto clay particles and grain coatings can dissolve and return in produced 

water (Langmuir and Riese, 1985). Available data indicate that radium and TDS concentrations in 

produced water are positively correlated (Rowan et al., 2011; Fisher, 1998), likely because radium 

remains adsorbed to mineral surfaces when salinity is low, and then desorbs into solution with 

increased salinity (Sturchio et al., 2001). As an example, over the course of 20 days, radium 

concentration in flowback from a Marcellus Shale gas well increased by almost a factor of four 

(Chapman et al., 2012; Rowan et al., 2011) (Figure 7-4).

Figure 7-4. Total radium and TDS concentrations measured through time for injected (day 0), 

and produced water samples Greene County, PA, Marcellus Shale gas wells. 

Data from Rowan et al. (2011) and Chapman et al. (2012). 

7.3.3.3 Dissolved Organic Carbon

Dissolved organic carbon (DOC) concentrations decrease from initial levels in shales and coalbeds 

(Murali Mohan et al., 2013; Orem et al., 2007). This occurs while TDS and chloride concentrations 

are increasing (Barbot et al., 2013; Chapman et al., 2012). DOC sorption, dilution with injected or 

formation water, biochemical reactions, and microbial transformation may all cause decreased 

concentrations of DOC during flowback. Injected organics can include gel polymer formulations, 

namely guar gum; petroleum distillates; and ethyl and ether glycol formulations, which can serve as 

food sources for microbes. (Wuchter et al., 2013; Arthur et al., 2009b; Hayes, 2009). In coalbeds, 

 

1 Hydraulic fracturing fluids typically do not contain radioactive material (Rowan et al., 2011). However, reusing 

produced water can introduce radioactive material into hydraulic fracturing fluid. See Section 7.3.4.6 and PA DEP 

(2015b). 
Chapter 7 – Produced Water Handling

7-15 

water contacting the coal may become depleted in DOC to the degree that when outside water of 

lower DOC is produced, the resulting DOC concentrations in the produced water are reduced (Orem 

et al., 2014). 

(a)

(b) 

Figure 7-5. (a) Increasing chloride (Cl) and (b) decreasing DOC concentrations measured 

through time for samples from three Marcellus Shale gas wells on a single well pad in Greene 

County, PA.

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.

As an example, produced water DOC concentrations decreased from their initial levels twofold from 

the hydraulic fracturing fluid and initial samples (Figure 7-5b) followed by a decrease of 11-fold 
Chapter 7 – Produced Water Handling

7-16 

over nearly 11 months. The DOC leveled off several months after hydraulic fracturing, presumably 

as a result of in situ attenuation processes (Cluff et al., 2014). As DOC was decreasing, chloride 

concentrations increased five- to six-fold. These chloride concentrations increased linearly during 

the first two weeks (Cluff et al., 2014) and then later approached higher levels (Figure 7-5a). The 

pattern in the DOC and chloride levels reflected the changing composition of the produced water—

initially high in DOC from hydraulic fracturing additives and low in salinity, then higher in salinity 

and lower in DOC reflecting the chemistry of formation water. The changing composition of 

produced water suggests that the potential concern for produced water spills also changes: initially 

the produced water may contain more hydraulic fracturing chemicals, and later the concern may 

shift to the impact of high salinity water.

7.3.4 Produced Water Composition

The chemical composition of produced water continues to change after the initial flowback period. 

Produced water may contain a range of constituents, but in widely varying amounts. Generally, 

these can include:

• Salts, including those composed from chloride, bromide, sulfate, sodium, magnesium and 

calcium; 

• Metals including barium, manganese, iron, and strontium; 

• Radioactive materials including radium (radium-226 and radium-228); 

• Oil and grease, and dissolved organics (including BTEX);1

• Hydraulic fracturing chemicals, including tracers and their transformation products; and 

• Produced water treatment chemicals.2

We discuss these groups of chemicals and then conclude by discussing variability within formation 

types and within production zones. 

7.3.4.1 Similarity of Produced Water from Conventional and Unconventional Reservoirs

Produced water generated from unconventional reservoirs is reported to be similar to produced 

water from conventional reservoirs in terms of TDS, pH, alkalinity, oil and grease, TOC, and other 

organics and inorganics (Wilson, 2014; Haluszczak et al., 2013; Alley et al., 2011; Hayes, 2009; 

Sirivedhin and Dallbauman, 2004). Although produced water salinity varies within and among 

shales and tight formations, produced water is typically characterized as saline (Lee and Neff, 2011; 

Blauch et al., 2009). Produced water from coalbeds may have low TDS if the coal source bed was 

formed in freshwater. Saline produced water is also enriched in major anions (e.g., chloride, 

bicarbonate, sulfate); cations (e.g., sodium, calcium, magnesium); metals (e.g., barium, strontium); 

 

1 BTEX is an acronym representing benzene, toluene, ethylbenzene, and xylenes.

2 Some chemicals are added to produced water for the purpose of oil/water separation, improved pipeline flow, or 

equipment maintenance, including prevention of corrosion and scaling in equipment (Cal/EPA, 2016). Generally the 

chemicals serve as clarifiers, emulsifiers, emulsion breakers, floating agents, and oxygen scavengers. Among proprietary 

formulations, a few specific chemicals have been disclosed including low concentrations of benzene, toluene, and 

inorganics (acetic acid, ammonium chloride, cupric sulfate, sodium hypochlorite).
Chapter 7 – Produced Water Handling

7-17 

naturally occurring radionuclides (e.g., radium-226, radium-228) (Chapman et al., 2012; Rowan et 

al., 2011); and organics (e.g., hydrocarbons) (Orem et al., 2007; Sirivedhin and Dallbauman, 2004). 

7.3.4.2 Variability in Produced Water Composition Among Unconventional Reservoirs

Alley et al. (2011) compared geochemical parameters of shale gas, tight gas, and CBM produced 

water. This comparison aggregated data on produced water from original analyses, peer-reviewed 

literature, and public and confidential government and industry sources and determined the 

statistical significance of the results. 

As shown in Table 7-5, Alley et al. (2011) found that of the constituents of interest common to all 

three types of produced water from unconventional reservoirs (calcium, chloride, potassium, 

magnesium, manganese, sodium, and zinc):

1. Shale gas produced water had significantly different concentrations from those of CBM;

2. Shale gas produced water constituent concentrations were significantly similar to those of 

tight gas, except for potassium and magnesium; and

3. Five tight gas produced water constituent concentrations (calcium, chloride, potassium, 

magnesium, and sodium) were significantly similar to those of CBM (Alley et al., 2011). 

The degree of variability between produced waters of these three resource types is consistent with 

the degree of mineralogical and geochemical similarity between shale and sandstone formations, 

and the lack of the same between shale and coalbed formations (Marshak, 2004). Compared to the 

others, shale gas produced water tends to be more acidic, as well as enriched in strontium, barium, 

and bromide. CBM produced water is alkaline, and it contains relatively low concentrations of TDS 

(one to two orders of magnitude lower than in shale and sandstone). It also contains lower levels of 

sulfate, calcium, magnesium, DOC, sodium, bicarbonate, and oil and grease than typically observed 

in shale and sandstone produced waters (Alley et al., 2011; Dahm et al., 2011; Benko and Drewes, 

2008; Van Voast, 2003).1

Table 7-5. Compiled minimum and maximum concentrations for various geochemical 

constituents in produced water from shale gas, tight gas, and CBM produced water.

Source: Alley et al. (2011).

Parameter Unit Shale gasa Tight Gas Sandsb CBMc

Alkalinity mg/L 160−188 1,424 54.9−9,450

Ammonium-N mg/L - 2.74 1.05−59

Bicarbonate mg/L ND−4,000 10−4,040 -

Conductivity μS/cm - 24,400 94.8−145,000

Nitrate mg/L ND−2,670 - 0.002−18.7

 

1 Several regions had low representation in the Alley et al. (2011) data set, including the Appalachian Basin 

(western New York and western Pennsylvania), West Virginia, eastern Kentucky, eastern Tennessee, and 

northeastern Alabama.
Chapter 7 – Produced Water Handling

7-18 

Parameter Unit Shale gasa Tight Gas Sandsb CBMc

Oil and grease mg/L - 42 -

pH SUd 1.21−8.36 5−8.6 6.56−9.87

Phosphate mg/L ND−5.3 - 0.05−1.5

Sulfate mg/L ND−3,663 12−48 0.01−5,590

Radium-226 pCi/g 0.65−1.031 - - 

Aluminum mg/L ND−5,290 - 0.5−5,290

Arsenic mg/L - 0.17 0.0001−0.06

Boron mg/L 0.12−24 - 0.002−2.4

Barium mg/L ND−4,370 - 0.01−190

Bromide mg/L ND−10,600 - 0.002−300

Calcium mg/L 0.65−83,950 3−74,185 0.8−5,870

Cadmium mg/L - 0.37 0.0001−0.01

Chloride mg/L 48.9−212,700 52−216,000 0.7−70,100

Chromium mg/L - 0.265 0.001−0.053

Copper mg/L ND−15 0.539 ND−0.06

Fluorine mg/L ND−33 - 0.05−15.22

Iron mg/L ND−2,838 0.015 0.002−220

Lithium mg/L ND−611 - 0.0002−6.88

Magnesium mg/L 1.08−25,340 2−8,750 0.2−1,830

Manganese mg/L ND−96.5 0.525 0.002−5.4

Mercury mg/L - - 0.0001−0.0004

Nickel mg/L - 0.123 0.0003−0.20

Potassium mg/L 0.21−5,490 5−2,500 0.3−186

Sodium mg/L 10.04−204,302 648−80,000 8.8−34,100

Strontium mg/L 0.03−1,310 - 0.032−565

Uranium mg/L - - 0.002−0.012

Zinc mg/L ND−20 0.076 0.00002−0.59

-, No value available; ND, non-detect. If no range, but a singular concentration is given, this is the maximum concentration.

a n = 541. Alley et al. (2011) compiled data from USGS (2006); McIntosh and Walter (2005); McIntosh et al. (2002) and 

confidential industry documents.

b n = 137. Alley et al. (2011) compiled data from USGS (2006) and produced water samples presented in Alley et al. (2011). 

c Alley et al. (2011) compiled data from Montana GWIC (2009); Thordsen et al. (2007); ESN Rocky Mountain (2003); Rice et al. 

(2000); Rice (1999); Hunter and Moser (1990). 

d SU = standard units.
Chapter 7 – Produced Water Handling

7-19 

7.3.4.3 General Water Quality Parameters

Data characterizing the content of produced water from unconventional reservoirs in 12 shale and 

tight formations and CBM basins were evaluated for this assessment. These reservoirs and basins 

include parts of 18 states, but the data do not allow for comparison of trends over time. 

For most reservoirs, the amount of available general water quality parameter data is variable (see 

Appendix Table E-2 for an example). Average pH levels range from 5.87 to 8.19, with typically 

lower values for shales. Larger variations in average specific conductivity are seen among 

unconventional reservoirs and range from 213 microsiemens (μS)/cm in the Bakken Shale to 

184,800 μS/cm in Devonian sandstones (Appendix Table E-2). Shale and tight formation produced 

waters are enriched in suspended solids, as reported concentrations for total suspended solids and 

turbidity exceed those of coalbeds by one to two orders of magnitude. 

The average dissolved oxygen (DO) concentrations of CBM produced water range from 0.39-1.07 

mg/L (Appendix Table E-3). By comparison, well-oxygenated surface water can contain up to 10 

mg/L DO at 59 °F (15 °C) (U.S. EPA, 2012a). Thus, coalbed produced water is either hypoxic (less 

than 2 mg/L DO) or anoxic (less than 0.5 mg/L DO) and, if released to surface waters, could 

contribute to aquatic organism stress (USGS, 2010; NSTC, 2000). 

7.3.4.4 Salinity and Inorganics

The TDS profile of produced water from unconventional reservoirs is dominated by sodium and 

chloride, with large contributions to the profile from mono- and divalent cations (Sun et al., 2013; 

Guerra et al., 2011). Shale and sandstone produced waters tend to be characterized as sodiumchloride-calcium water types, whereas CBM produced water tends to be characterized as sodium 

chloride or sodium bicarbonate water types (Dahm et al., 2011). Elevated levels of bromide, sulfate, 

and bicarbonate are also present (Sun et al., 2013). Elevated strontium and barium levels are 

characteristic of Marcellus Shale produced water (Barbot et al., 2013; Haluszczak et al., 2013; 

Chapman et al., 2012). Data representing shales and tight formations are presented in Appendix 

Table E-4.

Marcellus Shale produced water salinities range from less than 1,500 mg/L to over 300,000 mg/L, 

as shown by Rowan et al. (2011). By comparison, the average salinity concentration for seawater is 

35,000 mg/L. 

Of the CBM data presented in Appendix Table E-5, differences are evident between the Black 

Warrior and the three western formations (Powder River, Raton, and San Juan). The Black Warrior 

is higher in average chloride, specific conductivity, TDS, TOC, and total suspended solids, and lower 

in alkalinity and bicarbonate than the other three. These differences are due to the saline or 

brackish conditions during deposition in the Black Warrior, and its older geologic age that contrasts 

with the freshwater conditions for the younger western basins. The TDS concentration of CBM 
Chapter 7 – Produced Water Handling

7-20 

produced water can range from 170 mg/L to nearly 43,000 mg/L (range composited from Dahm et 

al. (2011) and Benko and Drewes (2008); see also Van Voast (2003)).1 

7.3.4.5 Metals

The metals content of produced water from unconventional reservoirs varies by well and site 

lithology. Levels of iron, magnesium, and boron were within ranges known for conventional 

produced water (Hayes, 2009). Produced water from unconventional reservoirs may also contain 

low levels of heavy metals (e.g., chromium, copper, nickel, zinc, cadmium, lead, arsenic, and 

mercury as found by Hayes). Data illustrating metal concentrations in produced water appear in 

Appendix Tables E-6 and E-7.

7.3.4.6 Naturally Occurring Radioactive Material (NORM) and Technologically Enhanced 

Naturally Occurring Radioactive Material (TENORM)

Geologic environments contain naturally occurring radioactive material (NORM). Radioactive 

materials commonly present in shale and sandstone sedimentary environments include uranium, 

thorium, radium, and their decay products. Elevated formation uranium levels have been used to 

identify potential areas of natural gas production for decades (Fertl and Chilingar, 1988). Shales 

that contain significant levels of uranium include the Barnett in Texas, the Woodford in Oklahoma, 

the New Albany in the Illinois Basin, the Chattanooga Shale in the southeastern United States, and a 

group of black shales in Kansas and Oklahoma (Swanson, 1955).2 When exposed to the 

environment in produced water, NORM is called technologically enhanced naturally occurring 

radioactive material (TENORM).3 Water soluble forms of TENORM are present in most produced 

water from unconventional reservoirs, but particularly so in Marcellus Shale produced water 

(Rowan et al., 2011; Fisher, 1998). 

Due to insolubility under prevailing reducing conditions encountered within shale formations, only 

low levels of uranium and thorium are found in produced water, typically in the concentrated form

of mineral phases or organic matter (Nelson et al., 2014; Sturchio et al., 2001). Conversely, radium, 

a decay product of uranium and thorium, is known to be relatively soluble within the redox range 

encountered in subsurface environments (Sturchio et al., 2001; Langmuir and Riese, 1985). As 

noted in Section 7.3.3.2, radium and TDS produced water concentrations are positively correlated 

(Rowan et al., 2011; Fisher, 1998); therefore, in formations containing radium, increasing TDS 

concentration indicates likely increasing radium concentration.

 

1 From a similar dataset, Dahm et al. (2011) report TDS concentrations from a composite CBM produced water database 

(n = 3,255) for western basins that often are less than 5,000 mg/L (85% of samples).

2 Marine black shales are estimated to contain an average of 15−60 ppm uranium depending on depositional conditions 

(Fertl and Chilingar, 1988). 

3 The U.S. EPA Office of Air and Radiation’s website (https://www.epa.gov/radiation/technologically-enhanced-naturallyoccurring-radioactive-materials-tenorm) states that 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 contains NORM, because it is not exposed; produced 

water contains TENORM, because it has been exposed to the environment.
Chapter 7 – Produced Water Handling

7-21 

Median values of total radium in the Marcellus Shale ranged from about 1,000 pCi/L to less than 

6,000 pCi/L, which are values far exceeding the industrial discharge limit of 60 pCi/L (Rowan et al., 

2011) (Figure 7-6). In the Marcellus Shale, TENORM levels in produced water from unconventional 

reservoirs exceeded levels from conventional reservoirs levels by factors of 4 to 26 (PA DEP, 

2015b) (Appendix Table E-8). The individual median concentrations in produced water from 

unconventional reservoirs of 11,300 pCi/L gross alpha, 3,445 pCi/L gross beta, and total radium of 

7,180 pCi/L (Appendix Table E-8). TENORM has been identified in hydraulic fracturing fluid, 

presumably due to the reuse of produced water at levels from 2 to 4.5 times lower than produced 

water from unconventional reservoirs (PA DEP, 2015b) (Appendix Table E-8).

Figure 7-6. Data on radium 226 (open symbols) and total radium (filled symbols) for Marcellus 

Shale wells (leftmost three columns) and other formations (rightmost three columns). 

Source: Rowan et al. (2011). The dashed line represents the industrial effluent discharge limit of 60 pCi/L set by the 

Nuclear Regulatory Commission. The black lines indicate the median concentrations, and the number of points in 

each dataset are shown in parentheses. Citations within the figure are provided in Rowan et al. (2011). 

7.3.4.7 Organics

The organic content of produced water varies by well and lithology, but consists of naturally 

occurring and injected organic compounds (Lee and Neff, 2011). Of the organics detected by either 

routine or advanced analytical methods (Section 7.3.1), the majority are naturally occurring 

constituents of petroleum (Appendix Tables H-4 and H-5). These organics may be dissolved in 

water or, in the case of oil production, in the form of a separate or emulsified phase. Several classes 

of organic chemicals have been found in shale gas and CBM produced water, including aromatics, 
Chapter 7 – Produced Water Handling

7-22 

polyaromatic hydrocarbons, heterocyclic compounds, aromatic amines, phenols, phthalates, 

aliphatic alcohols, fatty acids, and nonaromatic compounds (list from Orem et al. (2014), see also: 

Hayes (2009), Benko and Drewes (2008), Orem et al. (2007), and Sirivedhin and Dallbauman 

(2004)). Compounds found in CBM waters included pyrene, phenanthrenone, alkyl phthalates, C12

through C18 fatty acids, and others. Similarly, compounds found in shale gas produced water 

included pyrene and perylene, ethylene glycol, diethylene glycol monodocecyl ether, 2-(2-

butoxyethoxy) ethanol, and others (Orem et al., 2014). Biomarkers—organic molecules 

characteristically produced by life forms, and unique to shale formations—have recently been 

suggested to fingerprint produced water (Hoelzer et al., 2016). More representative examples from 

five coal bed and two shale gas formations with reported concentrations are given in Appendix

Tables E-9, E-11, and E-12, and the complete list of chemicals with CAS registry numbers identified 

by the EPA for this assessment appears in Appendix H. (See Appendix Table H-4 for chemicals with 

EPA-identified CAS numbers and Appendix Table H-5 for chemicals without.) Appendix Table E-13 

lists concentrations of organic chemicals that were identified in three specific studies (Khan et al., 

2016; Lester et al., 2015; Orem et al., 2007). 

7.3.4.8 Hydraulic Fracturing Fluid Additives 

Several chemicals used in hydraulic fracturing fluids have been identified in produced water. 

(Examples are shown in Table 7-6, Appendix Table E-10, and Appendix Tables H-4 and H-5.) Many 

of these chemicals were identified through advanced analytical procedures and equipment, and 

would not be expected to be found by routine analyses. Of note is that phthalates do not occur 

naturally. Their presence in produced water is due to either their use in hydraulic fracturing fluids; 

polyvinyl chloride (PVC) in well adhesives, valves, or fittings; or coatings on laboratory sample 

bottles (Orem et al., 2007).1 Phthalates can also be used in drilling fluids, as breaker additives, or as 

plasticizers (Maguire-Boyle and Barron, 2014; Hayes and Severin, 2012a).2 One of the produced 

water phthalates has been identified as a component of hydraulic fracturing fluid (di(2-ethylhexyl) 

phthalate) (Appendix Table H-2), while others have not, and those may originate from laboratory or 

field equipment.

Table 7-6. Examples of compounds identified in produced water that can be components of 

hydraulic fracturing fluid. 

Appendix Tables H-4 and H-5 list chemicals identified in produced water and indicates those also identified as 

constituents of hydraulic fracturing fluid. Chemical or class designation in this table is taken directly from the text 

of the cited references except where noted, and may or may not reflect the chemical names from the Distributed 

Structure-Searchable Toxicity Database (DSSTox) show in Appendix Table H-4 or other chemicals listed in Appendix 

Table H-5.

Chemical or class Use Reference

2-Butanone Solvent; microbial degradation 

product

Lester et al. (2015)

 

1 Examples include di(2-ethylhexyl) phthalate, diisodecyl phthalate, and diisononyl phthalate (Orem et al., 2007).

2 Specifically fatty acid phthalate esters (Maguire-Boyle and Barron, 2014). 
Chapter 7 – Produced Water Handling

7-23 

Chemical or class Use Reference

2-Butoxyethanol Acid dispersant, solvent, nonemulsifierThacker et al. (2015) 

Acetone Solvent; microbial degradation 

product

Lester et al. (2015)

Cocamidopropyl dimethylamine 

(C-7)

Foaming and lubrication enhancer Lester et al. (2015) 

Di(2-ethylhexyl) phthalatea Derivative of polyvinyl chloride used 

in adhesives, valves, fittings or 

coatings of sample bottles 

Orem et al. (2007)

Diethylene glycol monododecyl

ether

Antifreeze, scale inhibitor, friction 

reducer

Orem et al. (2014)

Dioctadecyl ester of phosphate 

phosphoric acid

Common lubricant Maguire-Boyle and Barron (2014)

Ethylene glycol Antifreeze, scale inhibitor, friction 

reducer

Orem et al. (2014)

Fatty acid phthalate esters (Related to) use in drilling fluids and 

breakers

Maguire-Boyle and Barron (2014)

Fluorocarbons Tracers Maguire-Boyle and Barron (2014)

Hexahydro-1,3,5-trimethyl-1,3,5-

triazine-2-thione

Biocide Orem et al. (2014)

Linear alkyl ethoxylates (C-4 to C-8, 

C-11 to C-14)

Enhancer of surfactant properties Lester et al. (2015); Thurman et al. 

(2014)

Polyethylene glycol carboxylates 

(PEG-C-EO2 to PEG-C-EO10)

Friction reducer, clay stabilizer, 

surfactants

Thurman et al. (2016)

Polyethylene glycols (PEG-EO4 to 

PEG-EO10)

Friction reducer, clay stabilizer, 

surfactants 

Thurman et al. (2016)

Polypropylene glycols (PPG-PO2 to 

PPG PO10)

Friction reducer, clay stabilizer, 

surfactants 

Thurman et al. (2016)

Toluene Solvent, scale inhibitor Thacker et al. (2015)

Triethylene glycol monododecyl 

ether

Antifreeze, scale inhibitor, friction 

reducer

Orem et al. (2014)

Xylenes Solvent, scale inhibitor Thacker et al. (2015)

a Di(2-ethylhexyl) phthalate was named di-2-ethyl hexyl phthalate in Maguire-Boyle and Barron (2014).
Chapter 7 – Produced Water Handling

7-24 

7.3.4.9 Reactions within Formations

The introduction of hydraulic fracturing fluids into the target formation induces a number of 

changes to formation solids and fluids that influence the chemical evolution and composition of 

produced water. These changes can result from physical processes (e.g., rock fracturing and fluid 

mixing); geochemical processes (e.g., introducing oxygenated fluids of composition unlike that of 

the formation); and down hole conditions (elevated temperature, salinity, and pressure) that 

mobilize trace or major constituents into solution.

The creation of fractures exposes new formation surfaces to interactions involving hydraulic 

fracturing fluids and existing formation fluids. Formations in unconventional reservoirs targeted 

for development are composed of detrital, cement, and organic fractions. For example, elements 

potentially available for mobilization when exposed via fracturing include calcium, magnesium, 

manganese, and strontium in cement fractions, and silver, chromium, copper, molybdenum, 

niobium, vanadium, and zinc in organic fractions. 

From organic compounds identified in five flowback samples and one produced water sample from 

the Fayetteville Shale, three possible types of reactions were identified by Hoelzer et al. (2016): 

hydrolysis of delayed acids, oxidant-caused halogenation reactions, and transformation of disclosed 

additives. First, delayed acids are used to “break” gel structures and would be intentionally 

introduced for their ability to cause in-formation reactions. Second, strong oxidants or other 

compounds introduced as breakers, along with elevated temperature and salinity, can trigger 

reactions between halogens (chloride, bromide, and iodide) and methane, acetone and pyrane 

resulting in halomethane compounds. A similar suggestion was made by Maguire-Boyle and Barron 

(2014). Low pH was found to promote oxidation of additives (Tasker et al., 2016). Third, known 

additives may react to form byproducts. Hoelzer et al. (2016) postulate examples from several 

types of compounds, two of these are the formation of benzyl alcohol from the hydraulic fracturing 

additive benzyl chloride, and abiotic and biotic reactions of phenols. In a study that used synthetic 

fracturing fluid, Tasker et al. (2016) reported that surfactants were recalcitrant to degradation 

under high pressure and temperature, which may explain the presence of the surfactant glycols in 

produced water as reported by Thurman et al. (2016) (Table 7-6), and the oxidation of other 

additives (gelling and some friction reducers (Table 5-1)) may explain their absence.

7.3.5 Spatial Trends in Produced Water Composition 

As was reported for the volume of produced water (Section 7.2.2), the composition of produced 

water varies spatially on a regional to local scale according to the geographic and stratigraphic 

locations of each well within a hydraulically fractured production zone (Bibby et al., 2013; Lee and 

Neff, 2011). Spatial variability of produced water content occurs: (1) between plays of different 

rock sources (e.g., coal vs. sandstone); (2) between plays of the same rock type (e.g., Barnett Shale 

vs. Bakken Shale); and (3) within formations of the same source rock (e.g., northeastern vs. 

southwestern Marcellus Shale) (Barbot et al., 2013; Alley et al., 2011; Breit, 2002). 

Geographic variability in produced water content has been established at a regional scale for 

conventional produced water. As an example, Benko and Drewes (2008) demonstrate TDS 
Chapter 7 – Produced Water Handling

7-25 

variability in conventional produced water among fourteen western geologic basins (e.g., Williston, 

San Juan, and Permian Basins). Median TDS in these basins range from as low as 4,900 mg/L in the 

Big Horn Basin to as high as 132,400 mg/L in the Williston Basin based on over 133,000 produced 

water samples from fourteen basins (Benko and Drewes, 2008).1

Average or median TDS of more than 100,000 mg/L has been reported for the Bakken (North 

Dakota, Montana) and Marcellus (Pennsylvania) formations; between 50,000 mg/L and 100,000 

mg/L for the Barnett (Texas), and less than 50,000 mg/L for the Fayetteville (Arkansas) shale 

formations.2 In tight formations, the average TDS was above 100,000 mg/L for the Devonian 

Sandstone (Pennsylvania) and Cotton Valley Group (Louisiana, Texas), between 50,000 mg/L and 

100,000 mg/L for the Oswego (Oklahoma), and less than 50,000 mg/L for the Mesaverde 

Formation (Colorado, New Mexico, Utah, Wyoming). Maximum concentrations above 200,000 mg/L 

have been reported for the Marcellus, Bakken, Cotton Valley Group and Devonian Sandstone 

(Appendix Table E-2).

CBM produced waters had average TDS of less than 5,000 mg/L in the Powder River (Montana, 

Wyoming), Raton (Colorado, New Mexico), and San Juan (Arizona, Colorado, New Mexico, Utah) 

basins; while above 10,000 mg/L in the Black Warrior Basin (Alabama, Mississippi), which as noted 

above are due to the depositional history of these basins (Appendix Table E-3, Section 7.3.2). 

Data further illustrating variability within both shale and tight gas reservoirs, as well as coalbed 

methane fields, at both the formation and local scales are presented and discussed in Appendix 

Section E.3.

7.4 Spill and Release Impacts on Drinking Water Resources

Surface spills of produced water from oil and gas production have occurred across the country and, 

in some cases, have caused impacts to drinking water resources. Released fluids can flow into 

nearby surface waters, if not contained on-site, or infiltrate into groundwater via soil. In this 

section, we first briefly describe the potential for spills from produced water handling equipment. 

Next, we address individually reported spill events. These have originated from pipeline leaks, well 

blowouts, well communication events, and leaking pits and impoundments. We then summarize 

several studies of aggregated spill data, which are based on state agency spill reports.

7.4.1 Produced Water Handling and Spill Potential

Throughout the production phase at oil and certain wet gas production facilities, produced water is 

stored in containers and pits that can contain free phase, dissolved phase, and emulsified crude oil. 

Since the crude oil is not efficiently separated out by the flow-through process vessels (such as 

 

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.

2 Because publications we are comparing may report either average or median values (but not uniformly both), we 

combine average and medians in this paragraph.
Chapter 7 – Produced Water Handling

7-26 

three-phase separators, heater treaters, or gun barrels), this crude oil can remain present in the 

produced water container or pit. 

Produced water can be transferred to surface pits for long-term storage and evaporation. Surface 

pits are typically uncovered, earthen pits that may or may not be lined.1 Unlined pits can lead to 

contamination of groundwater, especially shallow alluvial systems. Recovered fluids can overflow 

or leak from surface pits due to improper pit design and weather events. 

Produced water that is to be treated or disposed of off-site is typically stored in storage tanks or 

pits until it can be loaded into transport trucks for removal (Gilmore et al., 2013). Tank storage 

systems are typically closed loop systems in which produced water is transported from the 

wellhead to aboveground storage tanks through interconnecting pipelines (GWPC and IOGCC, 

2014). Failure of connections and lines during the transfer process or the failure of a storage tank 

can result in a surface release of fluids.

Depending on its characteristics, produced water can be recycled and reused on-site. It can be 

directly reused without treatment (after blending with freshwater), or it can be treated on-site 

prior to reuse (Boschee, 2014). As with other produced water management options, these systems 

also can spill during transfer of fluids. 

7.4.2 Spills of Produced Water

7.4.2.1 Pipeline Leaks

Produced water is typically transported from the wellhead through a series of pipes or flowlines to 

on-site storage or treatment units (GWPC and IOGCC, 2014), or nearby injection wells. Faulty 

connections at either end of the transfer process or leaks or ruptures in the lines carrying the fluid 

can result in surface spills. A field report from PA DEP (2009b) described a leak from a 90-degree 

bend in an overland pipe carrying a mixture of produced water and freshwater between two pits. 

The impact included a “dull sheen” on the water and measured chloride concentration of 11,000 

mg/L. The leak impacted a 0.4 mi (0.6 km) length of a stream, and fish and salamanders were killed. 

Beyond a confluence at 0.4 mi (0.6 km) with a creek, no additional dead fish were found. The 

release was estimated at 11,000 gal (42,000 L). In response to the incident, the pipeline was shut 

off, a dam was constructed for recovering the water, water was vacuumed from the stream, and the 

stream was flushed with fresh water (PA DEP, 2009b). 

Another example of a pipeline release occurred in January 2015, when 70,000 bbls (2,940,000 gal 

or 11,130,000 L) of produced water containing petroleum hydrocarbons (North Dakota 

Department of Health, 2015) were released from a broken pipeline that crosses Blacktail Creek in 

Williams County, ND. The response included placing absorbent booms in the creek, excavating 

contaminated soil, removing oil-coated ice, and removing produced water from the creek. The 

electrical conductivity and chloride concentration in the water along the creek, the Little Muddy 

River, and Missouri River were found to be elevated above background levels, as were samples 

 

1 The use of the terms “impoundments” and “pits” varies and is described in Chapter 8. For the purposes of this section, 

the term “pits” will be generally used to cover all below-grade storage (but not above ground closed or open tanks).
Chapter 7 – Produced Water Handling

7-27 

taken from groundwater recovery trenches. Remediation work on this site continues as of the date

of this writing (August, 2016). 

7.4.2.2 Well Blowouts

Spills of produced water have occurred as a result of well blowouts. Fingerprinting of water from 

two monitoring wells in Killdeer, ND, was used to determine that brine contamination in the two 

wells resulted from a well blowout during a hydraulic fracturing operation. See the discussion in 

Section 6.2.2.1 for more information.

Another example of a well blowout associated with a hydraulic fracturing operation occurred in

Clearfield County, PA. The well blew out, resulting in an uncontrolled flow of approximately 

35,000 gal (132,000 L) of brine and fracturing fluid; some of the liquids reportedly reached a

nearby stream (Barnes, 2010). The blowout occurred during drilling of plugs that were used to

isolate fracture stages from each other. An independent investigation found that the primary cause

of the incident was that the sole blowout preventer on the well had not been properly tested. In 

addition, the company did not have certified well control experts on hand or a written pressure

control procedure (Vittitow, 2010).

In North Dakota, a blowout preventer failed, causing a release of between 50 and 70 bbls per day

(2,100 gal/day or 7,900 L/day and 2,940 gal/day or 11,100 L/day) of produced water and oil

(Reuters, 2014). Frozen droplets of oil and water sprayed on a nearby frozen creek. Liquid flowing

from the well was collected and trucked offsite. A 3-ft (0.9-m) berm was placed around the well for

containment. Multiple well communication events have also led to produced water spills ranging

from around 700 to 35,000 gal (2,600 L to 130,000 L) (Vaidyanathan, 2013a). Well communication 

is described in Section 6.3.2.3.

The Chesapeake Energy ATGAS 2H well, located in Leroy Township, Bradford County, PA,

experienced a wellhead flange failure on April 19, 2011, during hydraulic fracturing operations.

Approximately 10,000 gal (38,000 L) of produced water spilled into an unnamed tributary of

Towanda Creek, a state-designated trout stock fishery and a tributary of the Susquehanna River

(USGS, 2013b; SAIC and GES, 2011). Chesapeake conducted post-spill surface water and 

groundwater monitoring (SAIC and GES, 2011).

Chesapeake concluded that there were short-term impacts to surface waters of a farm pond within 

the vicinity of the well pad, the unnamed tributary, and Towanda Creek following the event (SAIC

and GES, 2011). The lower 500 ft (200 m) of the unnamed tributary exhibited elevated chloride,

TDS, and specific conductance, which returned to background levels in less than a week. Towanda

Creek experienced these same elevations in concentration, but only at its confluence with the

unnamed tributary; elevated chloride, TDS, and specific conductance returned to background levels

the day after the blowout (SAIC and GES, 2011). 

7.4.2.3 Leaks from Pits and Impoundments

Leaks of produced water from on-site pits have caused releases as large as 57,000 gal (220,000 L) 

and have caused surface water and groundwater impacts (Vaidyanathan, 2013b; Levis,
Chapter 7 – Produced Water Handling 

7-28

2011; 2010c; PADEP, 2010). VOCs have been measured in groundwater near the Duncan Oil Field 

in New Mexico downgradient of an unlined pit storing produced water. More example releases 

from pits are described in Section 8.4.5. 

Two of EPA’s retrospective case studies evaluated potential impacts from produced water pits. The 

EPA retrospective case studies were designed to determine whether multiple lines of evidence 

might be found that could specifically link constituent(s) found in drinking water to hydraulic 

fracturing activities using the tiered assessment framework presented in Appendix Section E.6. A 

multiple-lines-of-evidence approach was used to evaluate potential cause-and-effect relationships 

between hydraulic fracturing activities and contaminant presence in groundwater. Such an 

approach is needed, because the presence of a constituent in groundwater that is also found in 

hydraulic fracturing fluids or produced water does not necessarily implicate hydraulic fracturing 

activities as the cause. This is because some constituents of hydraulic fracturing fluids or produced 

water are ubiquitous in society (i.e., BTEX), and some constituents of produced water can be 

present in groundwater as background constituents (i.e., methane, iron, and manganese). 

Elements of the assessment framework include gathering background information, including predrilling sample results; developing a conceptual model of the site; and assessing multiple analytes 

to develop lines of evidence. Development of these requires adherence to sampling and quality 

assurance protocols to generate defensible data. Among many other quality assurance 

requirements, proper well purging and analyses of field and laboratory blanks are needed 

(Appendix Table E-17 and Figure E-15). 

In the EPA’s Retrospective Case Study in Southwestern Pennsylvania: Study of the Potential Impacts of 

Hydraulic Fracturing on Drinking Water Resources (U.S. EPA, 2015j), elevated chloride 

concentrations and their timing relative to historical data suggested a recent groundwater impact 

on a private water well occurred near a pit. The water quality trends suggested that the chloride 

anomaly was related to the pit, but site-specific data were not available to provide a definitive 

assessment of the cause(s) and the longevity of the impact. Evaluation of other water quality 

parameters did not provide clear evidence of produced water impacts. 

In the EPA’s Retrospective Case Study in Wise County, Texas: Study of the Potential Impacts of 

Hydraulic Fracturing on Drinking Water Resources (U.S. EPA, 2015l), impacts to two water wells 

were attributed to brine, but the data collected for the study were not sufficient to distinguish 

among multiple possible brine sources, including reserve pits, migration from underlying 

formations along wellbores, migration from underlying formation along natural fractures and a 

nearby brine injection well. 

To aid in assessing impacts, a number of geochemical indicators and isotopic tracers for identifying 

oil and gas produced water have been identified. These include (Lauer et al., 2016; Warner et al., 

2014a, b): 

 Common ion ratios, including bromide/chloride and lithium/chloride;

 Isotope ratios, especially Strontium isotope ratios (87Sr/86Sr); and
Chapter 7 – Produced Water Handling 

7-29

 Enrichment of certain isotopes: δ18O, δ2H, δ7Li, δ13C-DIC, δ11B.1

For the case study, twelve geochemical indicators, including the bromine/chlorine (Br/Cl) and 

strontium isotope ratios, were considered for the well-water samples.2 The results were used to 

assess whether the likelihood that the observed values originated with produced water (the 

aforementioned sources of brine), sea water, road salt, landfill leachate, sewage/septic tank 

leachate, and animal waste. In each sample evaluated, it was found that the water could have 

originated with one or more of the six sources. Thus these lines of evidence did not allow 

identification of neither a specific source nor a hydraulic fracturing source (Appendix Table E-18). 

A third well experienced similar impacts, and a landfill leachate source could not be ruled out in 

that case. 

The case studies illustrate how multiple lines of evidence were needed to assess suspected impacts 

and that no single constituent or parameter could be used alone to assess potential impacts. 

7.4.2.4 Other Sources 

In the EPA’s Retrospective Case Study in Northeastern Pennsylvania: Study of the Potential Impacts of 

Hydraulic Fracturing on Drinking Water Resources (U.S. EPA, 2014f), a pond was found to be 

impacted due to elevated chloride and TDS, along with strontium ratios (87Sr/86Sr) characteristic of 

Marcellus Shale produced water. Here, the suspected source of the impact was a well pad which had 

a hydrochloric acid spill, a possible produced water spill and been used for temporary storage of 

drill cuttings. The same mulidence fracturing impacts from constituents characteristic of produced 

water (TDS, chloride, sodium, barium, strontium and radium) found in three domestic wells located 

in an area with naturally occurring saline groundwater. Conversely, at a spring with organic 

chemical contamination but no associated chloride or TDS impacts, hydraulic fracturing activities 

were also ruled out. 

An estimated 6,300 to 57,373 gal (24,000 to 217,280 L) of Marcellus Shale produced water was 

discharged through an open valve that drained a tank at XTO Energy Inc.’s Marquardt pad and 

flowed into a tributary of the Susquehanna River in November 2010 (U.S. EPA, 2016e; PA DEP, 

2011c). Overland and subsurface flow of released fluids impacted surface water, a subsurface 

spring, and soil. Five hundred tons of contaminated soil were excavated, and an estimated 8,000 gal 

(30,000 L) of produced water was recovered (Science Applications International Corporation, 

2010). Elevated levels of TDS, chloride, bromide, barium and strontium that indicated a release of 

produced water were present in the surface stream and a spring for roughly 65 days (U.S. EPA, 

2016e). At that time the chloride concentration in the spring dropped below the state surface water 

standard of 250 mg/L. The impact extended a distance of approximately 1,400 ft (440 m) to the 

spring from the release point. Samples were taken in the tributary roughly 500 ft downstream from 

the spring, where chloride concentrations remained below the 250 mg/L standard throughout the 

sampling period, but were above the upstream concentrations (PA DEP, 2011c; Schmidley and 

Smith, 2011). Similarly, the total barium, total and dissolved iron, manganese and alkalinity 

concentrations remained below the Pennsylvania surface water quality standards at the 

downstream monitoring location throughout the monitoring period (Schmidley and Smith, 2011). 

 

1 DIC is dissolved inorganic carbon. 

2 The full list was: Br vs. B, Cl vs. Mg, Cl vs. Br, Cl vs. HCO3,Cl vs. Ca, Cl vs. K, Cl vs. Na, Cl vs. SO4, Cl/Br, Cl/I, K/Rb, 87Sr/86Sr. 
Chapter 7 – Produced Water Handling

7-30 

In Pennsylvania, discharges of brine were made into a storm drain that itself discharges to a 

tributary of the Mahoning River in Ohio. Analyses of the brine and drill cuttings that were 

discharged indicated the presence of contaminants, including benzene and toluene (U.S. 

Department of Justice, 2014). In California, an oil production company periodically discharged 

hydraulic fracturing wastewaters to an unlined sump for 12 days. It was concluded by the 

prosecution that the discharge posed a threat to groundwater quality (Bacher, 2013). These 

unauthorized discharges represent both documented and potential impacts on drinking water 

resources. However, data do not exist to evaluate whether such episodes are uncommon or 

whether they happen on a more frequent basis and remain largely undetected. Other cases of 

unpermitted discharges have been reported by various sources (Caniglia, 2014; Paterra, 2011).1

7.4.2.5 Data Compilation Studies

Three datasets were examined for produced water spill data. These included two published studies: 

a review of spills in Oklahoma that occurred prior to the onset of widespread high-volume 

hydraulic fracturing (Fisher and Sublette, 2005), and an EPA study of spills occurring between 

February 2006 and April 2012 on the well pads of hydraulically fractured wells (U.S. EPA, 2015m). 

The EPA spills study, Review of state and industry spill data: characterization of hydraulic fracturingrelated spills, is described in Text Box 5-10. Because of data availability, EPA’s study was dominated 

by data from Pennsylvania (21% of releases) and Colorado (48% of releases). Several difficulties 

are encountered in compiling and evaluating data on produced water spills and releases. Because 

states have differing minimum reporting levels, more spills are potentially reported in states with 

lower reporting limits.2 

To include data from another state and to give results current to 2015, data from North Dakota 

were reviewed for this assessment.3 Details on the procedures and results for non-produced water 

spills are given in Appendix Section E.5. The North Dakota Department of Health (NDDOH) collects 

data on environmental incidents and separately compiles oil field incidents; information is made 

available to the public at http://www.ndhealth.gov/EHS/Spills/. Of these incidents, most describe a 

release of oil, salt water, or other liquid. Of the remainder, a few describe releases of gas only. 

For the period from November 2012 to November 2013, NDDOH reported 552 releases of produced 

water that were retained within the boundaries of the production or exploration facility and 104 

that were not (North Dakota Department of Health, 2011). Thus, 16% of the releases were not 

contained within facility boundaries and had greater potential for impacting drinking water 

resources.

 

1 Section 8.4 discusses permitted discharges of wastewater.

2 For example, two agencies in the state of California manage different databases that both store information on spills 

associated with oil and gas production (CCST, 2015a). CCST (2015a) reported that the databases contain inconsistencies 

as to the number of spills and the details regarding those spills (e.g., quantity, chemical composition of the wastewater) 

resulting in uncertainty on the impacts spills have on the environment.

3 Wirfs-Brock (2015) presented an analysis of North Dakota spill data through 2013.
Chapter 7 – Produced Water Handling

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7.4.2.6 Frequency of Spills and Releases

The EPA analyzed these data and found that, in recent years (2010-2015), there were between five 

and seven produced water spills per hundred active production wells (Figure 7-7). Spills declined 

between 2014 and 2015 (from 846 to 609), although the number of production wells increased. A 

study of 17 states indicated that there was an overall reduction of 8% in spills from 2014 to 2015, 

and an increase of 9% in Texas (King and Soraghan, 2016). More details on the data analysis are 

given in Appendix Section E.5, which includes results on North Dakota oil and spills of other types, 

including hydraulic fracturing fluids (as noted in Chapter 5).

Figure 7-7. Produced water spill rates (spills per active wells) for North Dakota from 2001 to 

2015 (Appendix Section E.5). 

7.4.2.7 Produced Water Releases—Causes and Sources

The causes and sources identified for releases vary among the three datasets reviewed. North 

Dakota releases were dominated by leaks from various pieces of equipment, followed by “others,” 

and various overflows (Figure 7-8). While the release rate declined from 2014 to 2015, the causes 

remained ranked relatively in the same order; notably fewer releases were attributed to “other” 

and more to equipment failure in 2015. The EPA’s spills study found on- or near-well pad releases 

to be dominated by human error, unknown, and equipment failure (U.S. EPA, 2015m). The earlier 
Chapter 7 – Produced Water Handling

7-32 

Oklahoma study was dominated by overflows, unpermitted discharges, and storms (Figure 7-9).1

Storms can cause releases, as was noted after a major flood in northeastern Colorado that caused 

damage to produced water storage tanks releasing an estimated 43,000 gal (160,000 L) of 

produced water (COGCC, 2013). 

The sources of releases are documented for the Oklahoma and EPA studies (Figure 7-10). The EPA 

cites storage, unknown, and hoses or lines as the major sources for its 225 well-pad releases. The 

earlier Oklahoma study cites unclassified, lines, and tanks as major sources of its 8,874 releases.

Figure 7-8. Number of produced water releases in North Dakota by cause for 2014 and 2015 

(Appendix Section E.5).

 

1 Some of the causes in the three studies may be more similar than they appear, because the categorization used in the 

different studies overlap. For example, the EPA categorized overflows as “human error;” blowouts, vandalism and 

weather as “other;” and corrosion as “equipment failure,” while other studies listed these separately.
Chapter 7 – Produced Water Handling

7-33 

Figure 7-9. Distribution of spill causes in Oklahoma, pre-high volume hydraulic fracturing 

years of 1993-2003 (left) and in the EPA study of spills on production pads (right). 

Data sources: left, Fisher and Sublette (2005); right, U.S. EPA (2015m). 

Figure 7-10. Distribution of spill sources in Oklahoma, pre-high volume hydraulic fracturing 

years of 1993-2003 (left) and in the EPA study of spills on production pads (right). 

Data sources: left, Fisher and Sublette (2005); right, U.S. EPA (2015m). 
Chapter 7 – Produced Water Handling

7-34 

7.4.2.8 The Volumes of Spilled Produced Water

The 2015 North Dakota spills were ranked from by the median volume, which is the level at which 

50% of the spills are below this volume and 50% above (Figure 7-11).1 Of the North Dakota spills in 

2015, the highest median spill volume was caused by a blowout (2,400 gal, 91,000 L, left-most red 

box). The smallest median volume spill is approximately 10 times lower in volume (84 gal, 320 L). 

Spills larger than the median are of interest, because of their potential for impacting drinking water 

resources. The largest volume spill occurred from a pipeline break (2,900,000 gal, 11,000,000 L). 

The EPA spills study found the highest median volume spill was from equipment failure (1,700 gal, 

6400 L), while the highest volume spill was due to container integrity (1,300,000 gal, 4,900,000 L) 

(Figure 7-12). 

Figure 7-11. Volumes of 2015 North Dakota salt water releases by cause (leftmost 13 boxes in 

red), and all causes (last box in blue). 

 

1 These figures are called “box” plots or “box and whisker” plots. The rectangle in the middle represents the range of data 

from the 25th to 75th percentile. The line across the box represents the 50th percentile, also known as the median. Fifty 

percent of the data are below the median. The lines extending above and below the boxes represent the range of data 

from minimum to maximum. These concepts are illustrated in Appendix Figure E-6. 
Chapter 7 – Produced Water Handling

7-35 

Figure 7-12. Volumes of produced water spills reported by the EPA for 2006 to 2012 by cause 

(the five left most boxes in red), source (the second five boxes in yellow), and all spills (blue). 

Calculated from Appendix B of U.S. EPA (2015m). 

From the analyses, half of the spills are less than 1,000 gal (3,800 L) (EPA) and 340 gal (1,300 L) 

(North Dakota) (Figure 7-12, Figure 7-13, and medians in Table 7-7). The medians for the 

Oklahoma study were higher (overall 1,700 gal or 6,400 L; see Table 7-7 for yearly values) (Fisher 

and Sublette, 2005). These occurred in a different state and over an earlier time period, so a direct 

connection with the recent North Dakota and EPA results has not been made.

The skewed nature of the distributions are noted by the mean values being considerably higher 

than these medians (see Figure 7-13). In each case, this is caused by a small number of large spills. 

For 2015 in North Dakota, for example, there were 12 releases of 21,000 gal (79,000 L) or more; 5 

of 42,000 gal (160,000 L) or more; and one of greater than 420,000 gal (1,600,000 L) (Appendix 

Table E-15). The largest spills from these data sets ranged from 1,000,000 gal (3,800,000 L) to 

2,900,000 gal (11,000,000 L).

The EPA results give insight into recovery and reuse. Of the volume of spilled produced water, 16% 

was recovered for on-site use or disposal, 76% was reported as unrecovered, and the rest was 

unknown. The fewest spills occurred from wells and wellheads, but these spills had the greatest 

median volumes. Failure of container integrity was responsible for 74% of the volume spilled (U.S. 

EPA, 2015m). 
Chapter 7 – Produced Water Handling

7-36 

Figure 7-13. Median, mean, and maximum produced water spill volumes for North Dakota 

from 2001 to 2015.
Chapter 7 – Produced Water Handling

7-37 

Table 7-7. Summary of produced water release volumes. 

Sources: U.S. EPA (2015m), Fisher and Sublette (2005), and Appendix Section E.5.

 Number Minimum 25th percentile Median Mean 75th percentile Maximum

Study Year(s) Total Quantified (gal) (gal) (gal) (gal) (gal) (gal)

Oklahoma 1993-2002 7,916 2,365 0.0 630 1,700 7,000 4,200 3,400,000

1993 373 161 0.4 420 1,500 3,900 4,200 46,000

1994 844 333 0.4 420 1,600 5,400 4,200 84,000

1995 913 333 0.0 420 1,500 3,700 4,200 63,000

1996 880 333 4.2 630 2,100 6,500 4,200 420,000

1997 806 270 0.4 630 1,900 6,000 4,200 120,000

1998 825 236 2.1 798 4,900 2,100 4,200 105,000

1999 886 218 10.5 840 2,100 6,600 4,200 120,000

2000 853 155 4.2 840 2,100 5,600 5,040 210,000

2001 826 144 21.0 840 2,100 31,000 6,510 3,400,000

2002 710 182 0.8 630 1,700 5,500 3,276 130,000

U.S. EPA 2006-2012 225 2.1 420 1,008 10,920 2,982 1,344,000

North Dakota 2001 97 21.0 168 420 2,646 2,520 42,000

2002 110 4.2 210 756 2,604 2,100 25,200

2003 128 2.1 126 504 3,150 2,562 58,800

2004 159 10.5 126 420 2,478 2,100 88,200

2005 184 5.0 126 420 2,142 1,680 54,600

2006 226 5.0 126 420 3,150 1,680 189,000

2007 248 0.4 210 420 2,814 2,100 210,000
Chapter 7 – Produced Water Handling

7-38 

 Number Minimum 25th percentile Median Mean 75th percentile Maximum

Study Year(s) Total Quantified (gal) (gal) (gal) (gal) (gal) (gal) 

North Dakota, cont. 2008 248 8.4 84 504 2,520 2,058 54,600

2009 208 2.1 126 630 2,100 2,100 27,300

2010 255 0.1 126 840 2,478 2,310 34,020

2011 381 2.1 126 336 2,436 1,680 58,800

2012 543 7.1 84 336 2,310 1,260 84,000

2013 700 2.1 126 378 3,402 1,428 714,000

2014 846 0.8 84 336 3,528 1,470 1,008,000

2015 609 0.8 84 336 7,560 1,386 2,940,000
Chapter 7 – Produced Water Handling

7-39 

7.4.2.9 Environmental Receptors and Transport 

Data from the EPA (U.S. EPA, 2015m) were used to show that some spills were known to impact 

environmental receptors: soil (141 spills, 340,000 gal, or 1.3 million L); surface water (17 spills, 

170,000 gal, or 640,000 L); surface water and soil (13 spills); and groundwater (1 spill, 130 gal, or 

490 L).1 Although 1 spill was identified as reaching groundwater, the possible groundwater impact 

of 107 of the spills was unknown. 

In summary, 18 produced water spills reached surface water or groundwater, accounting for 8% of 

the 225 cases and accounting for approximately 170,000 gal (640,000 L) of produced water. Spills 

with known volumes that reached a surface water body ranged from less than 170 gal (640 L) to 

almost 74,000 gal (280,000 L), with median of 5,900 gal (22,000 L). In 30 cases, it is unknown 

whether a spill of produced water reached any environmental receptor.

An assessment conducted by the California Council on Science and Technology (CCST, 2015a) states 

that between January 2009 and December 2014, 575 produced water spills were reported to the 

California Office of Emergency Services of which nearly 18 percent impacted waterways (CCST, 

2015a). These spills occurred in areas where production from both unconventional and 

conventional reservoirs occurs. Additional studies of spill impacts are presented in Appendix 

Section E.5.3.

Studies of Environmental Transport of Released Produced Water

The processes that affected the fate and transport of spilled produced water (Figure 7-14) are the 

same as those processes that impact the fate and transport of spilled chemicals (Section 5.8). 

Produced water spills differ from the chemical spills as they are always primarily spills of water 

containing multiple chemicals. Additionally, produced water of high salinity is denser than water 

and may alter transport and transformation properties of the chemicals and soils.2 If a spill occurs 

prior to treatment in an oil and water separator, the produced water can be spilled along with oil. In 

the environment, oil is transported as a separate phase liquid as it is immiscible with water. The oil 

phase may become trapped (similarly to how oil is trapped in oil reservoirs) and serve as a slowly 

dissolving source of hydrocarbons to the environment.

For example, Whittemore (2007) described a site with relatively little infiltration due to moderate 

to low permeability of silty clay soil and low permeability of underlying shale units. Thus, most, but 

not all, of the historically surface-disposed produced water at the site flowed into surface drainages. 

Observed historic levels of chloride in receiving waters resulted from the relative balance of 

produced water releases and precipitation runoff, with higher concentrations corresponding to low 

stream flows. Persistent surface water chloride contamination was attributed to slow flushing and 

discharge of contaminated groundwater.

1 Quoted volumes. 

2 Appendix Section E.7 describes the estimation of chemical properties for organic chemical constituents of produced 

water for baseline conditions of low TDS. Elevated salinity, as is common for produced water, would alter these values.
Chapter 7 – Produced Water Handling

7-40 

Figure 7-14. Schematic view of transport processes occurring during releases of produced 

water.

Because it is denser than freshwater, saline produced water can migrate downward through 

aquifers. Whittemore (2007) reported finding oilfield brine with a chloride concentration of 32,900 

mg/L at the base of the High Plains aquifer. Where aquifers discharge to streams, saline stream 

water has been reported, although at reduced concentrations (Whittemore, 2007), likely due to 

diffusion within the aquifer and mixing with stream water. The stream flow rate, in part, 

determines mixing of substances in surface waters. High flows are related to lower chemical 

concentrations, and vice versa, as demonstrated for bromide in the Allegheny River (States et al., 

2013). 

7.5 Roadway Transport of Produced Water

Produced water is transported to treatment and disposal sites via pipeline, roadways, or railroad 

tankers. Accidents during transportation of hydraulic fracturing produced water are a possible 

mechanism leading to potential impacts to drinking water as truck-related releases have been 

reported. Nationwide data are not available, however, on the number of such accidents that result 

in impacts. 

Crash rate estimates for Texas showed that commercial motor vehicle (CMV) crashes were 

correlated with oil and gas development activities over a recent period of increased oil and gas 

development (Quiroga and Tsapakis, 2015). As an example of the results, the number of new wells 
Chapter 7 – Produced Water Handling

7-41 

in the Permian Basin increased (by 61%) and so did rural CMV crashes (by 52%). For the Barnett 

Shale region, the number of new wells decreased (by 49%), and so did rural CMV crashes (by 34%). 

The correlations were strongest for the rural areas with oil and gas development (Permian and 

Eagle Ford).

Based on scenarios presented in Appendix Section E.8, the EPA estimated for this assessment the 

number of releases from truck crashes as having a chance of occurrence ranging between 1:110 and 

1:13,000 over the lifetime of a producing well. The wide range of these estimates reflects both 

variable (distance and volume transported) and uncertain (crash rate) quantities. At 5,300 gal (20 

m3) per truckload, the volume from an individual spill would be low relative to the typical volume 

of water produced from a well. Several limitations are inherent in this analysis, including differing 

rural road and highway accident rates, differing transport distances, and differing amounts of 

produced water transported. Further, the estimates present an upper bound on impacts, because 

not all releases would reach or impact drinking water resources. 

As for other types of impacts to drinking water resources, local effects can be significant despite the 

generally small numbers. For example, a brine-truck spill in Ohio resulted in concern for impacts to 

a drinking-water-source reservoir (Tucker, 2016). 

7.6 Synthesis

Produced water is a by-product of oil and gas production and is that water that comes out of the 

well after hydraulic fracturing is completed and injection pressure is reduced. Produced water may 

contain hydraulic fracturing fluid, water from the surrounding formation, and naturally present 

hydrocarbons. Initially the chemistry of produced water reflects that of the hydraulic fracturing 

fluid. With time, the chemistry of the produced water becomes more similar to the water in the 

formation. Produced water is directly re-injected or stored at the surface for eventual reuse or 

disposal. Impacts to drinking water resources from produced water have been shown where spilled 

produced water entered surface water bodies or aquifers.

7.6.1 Summary of Findings

The volume and composition of produced water vary geographically, both within and among 

different production zones and with time and other site-specific factors. In most cases, there are 

high initial flow rates of produced water that last for a few weeks, followed by lower flow rates 

throughout the duration of gas production. The amount of fracturing fluid returned to the surface 

varies, and typically is less than 30%. In some formations (e.g., the Barnett Shale), the ultimate 

volume of produced water can exceed the volume of hydraulic fracturing fluid because of an inflow 

of water. 

Knowledge of the composition of produced water comes from analysis of samples. Analysis of an 

individual sample is made much easier if the hydraulic fracturing and any equipment maintenance 

chemicals have been disclosed. Much of the chemical loading of produced water comes from 

naturally occurring material, both organic and inorganic, in the formation along with 

transformation products. As such, knowledge of produced water composition is uniquely 
Chapter 7 – Produced Water Handling

7-42 

dependent on sampling and analysis, which requires appropriate analytical methods. These are 

methods that can deal especially with high levels of TDS. Recently developed laboratory methods 

have greatly expanded the knowledge of organic chemicals in shale-gas and CBM produced waters, 

but these methods rely on advanced equipment and techniques. Routine methods of laboratory 

analysis do not detect many of the organic constituents of produced water.

The composition of produced water changes with time as the hydraulic fracturing fluid contacts the 

formation and mixes with the formation water. Typically it becomes more saline and more 

radioactive, if those constituents are present in the formation, while containing less DOC. The 

changing composition of produced water suggests that the potential concern for produced water 

spills also changes: initially the produced water may contain more hydraulic fracturing chemicals, 

later the concern may shift to the impact of high salinity water. Although varying within and 

between formations, shale and tight gas produced water typically contains high levels of TDS 

(salinity) and associated ionic constituents (bromide, calcium, chloride, iron, potassium, 

manganese, and sodium). Produced water can also contain toxic materials, including barium, 

cadmium, chromium, lead, mercury, nitrate, selenium, and BTEX. CBM produced water can have 

lower levels of salinity if its coal source was deposited under fresh water conditions, or if 

freshwater inflows to coal beds dilutes the formation water (Dahm et al., 2011). Many organic 

compounds have been identified in produced water. Most of these are naturally occurring 

constituents of petroleum. With the advent of advanced analytical techniques, more hydraulic 

fracturing fluid chemicals have been identified in produced water. These include some known 

tracer compounds, but others are known to exist whose identities have not yet been determined. 

Work has been done to identify environmentally benign tracers for assessing impacts, but these 

tracers have not been fully developed. Despite the presence in produced water of known hydraulic 

fracturing chemicals, the majority of organic and inorganic constituents of produced water come 

from the formation and cannot be minimized through actions of the operator. Throughout the 

formation-contact time, reactions occur between the constituents of the fracturing fluid and the 

formation.

Produced water spills have occurred across the country. From evaluation of data from across the 

United States and a focused study of North Dakota, the median produced water spill ranges from 

336 to 1,000 gal (1,300 to 3,800 L). Although half of the spills are smaller than the median spill size, 

small numbers of much higher volume spills occur. In 2015, there were 12 spills in North Dakota 

greater than 21,000 gal (80,000 L), and one of 2,900,000 gal (11,000,000 L). From 2010 to 2015, 

there were approximately 5 to 7 produced water spills per hundred operating production wells. 

The major causes identified for these spills are container and equipment failures, human error, well 

communication, blowouts, pipeline leaks, and unpermitted discharges. Section 7.4.2 described 

impacts that were both of short and long term duration. 

Highway transportation of produced water has resulted in crashes, but the impacts from these are 

unknown. Analysis of Texas crashes shows that as the oil and gas development activities increase, 

so do crashes, especially in rural areas. The EPA estimated the chance of a crash releasing produced 

water to range from 1:110 to 1:13,000. 
Chapter 7 – Produced Water Handling

7-43 

7.6.2 Factors Affecting the Frequency or Severity of Impacts

The potential of spills of produced water to affect drinking water resources depends upon the 

release volume, duration, and composition, as well as watershed and water body characteristics. 

Larger spills of greater duration are more likely to reach a nearby drinking water resource than are 

smaller spills. Small releases, however, can impact resources where there are direct conduits from a 

source to receptor, such as fractures in rock. The composition of the spilled fluid also impacts the 

severity of a spill, as certain constituents are more likely to affect the quality of a drinking water 

resource. 

Potential impacts to water resources from hydraulic fracturing related spills are expected to be 

affected by watershed and water body characteristics. For example, overland flow is affected by 

surface topography and surface cover. Infiltration of spilled produced water reduces the amount of 

water threatening surface water bodies. However, infiltration through soil can lead to groundwater 

impacts. Releases from pits can directly impact drinking water resources. 

7.6.3 Uncertainties

The volume and some compositional aspects of produced water are known from published sources. 

The amount of hydraulic fracturing fluid returned to the surface is not well defined, because of the 

imprecise distinction between flowback and produced water. With regard to composition, TENORM 

and organics have the most limited data. Most of the available data on TENORM has come from the 

Marcellus Shale, where concentrations are typically high in comparison to the limited data available 

from other formations. Many organic constituents of produced water have been identified, and 

many of them are naturally occurring petroleum hydrocarbons. As methods improve and more data 

are collected, an increasing number of hydraulic fracturing fluid chemicals are being identified in 

produced water. Little is known concerning subsurface transformations and is reflected in only a 

few transformation products have been positively identified. Halogenation of organics has been 

noted, though.

Nationwide data on spills of produced water are limited in two primary ways: the completeness of 

reported data cannot be determined, and individual states’ reporting requirements differ (U.S. EPA, 

2015m). Therefore, the total number of spills occurring in the United States, their release volumes, 

and associated concentrations can only be estimated because of these underlying data limitations. 

Spills vary in volume, duration, and composition, and most spill response focusses on immediate 

clean up, so several aspects of spills are not precisely characterized. The volume released is often a 

rough estimate, in part, because the spilled liquid spreads across the scene and is inherently 

difficult to measure. Simple measurements are often used to characterize the spill, rather than 

determining chemical concentrations (e.g., measuring electrical conductivity). As a consequence the 

suite of chemicals, and their concentrations, potentially impacting drinking water resources are 

usually unknown. Thus, the severity of impacts to drinking water resources is not usually well 

quantified. 

Spills can originate from blowouts, well communication, aboveground or underground pipeline 

breaks, leaking pits, failed containers, human error (including unpermitted discharges, failure to 
Chapter 7 – Produced Water Handling

7-44 

detect spills, and failure to report spills) or unknown causes. The difference between these causes 

affects the location and size of the spill or release. For example, a container that fails may release a 

small amount of produced water, and be located on the well pad. A pipeline break may occur at a 

distance away from the well pad and release a larger amount of water from a bigger source (i.e., a 

pit). In addition, the factors governing transport of spilled fluid to a potential receptor vary by site: 

the presence and quality of secondary or emergency containment and spill response; the rate of 

overland flow and infiltration; the distance to a surface water body or drinking water well; and 

transport and fate processes. Impacts to drinking water resources from spills of produced water 

depend on environmental transport parameters, which can, in principle, be determined but are 

unlikely to be known or adequately specified in advance of a spill. 

Because some constituents of produced water are constituents of natural waters (e.g., bromide in 

coastal surface waters) or can be released into the environment by other pollution events (e.g., 

benzene from gasoline releases, bromide from coal mine drainage), baseline sampling prior to 

impacts is one way to increase the certainty of an impact determination. Further sampling and 

investigation can be used to develop the linkage between a release and a documented drinking 

water impact. Appropriate sampling and analysis protocols, using quality assurance procedures, 

are essential for developing data that can withstand scrutiny. The EPA’s northeastern Pennsylvania 

case study illustrates that the analytes that can be used to distinguish among types of water vary 

depending on the specifics of the situation. No single constituent or parameter could be used alone 

to assess impacts, and multiple lines of evidence were needed to assess the suspected impacts. 

7.6.4 Conclusions

Produced water has the potential to affect the quality of drinking water resources if it enters into a 

surface water or groundwater body used as a drinking water resource. This can occur through 

spills at well pads or during transport of produced water. Specific impacts depend upon the spill 

itself, the environmental conditions surrounding the spill, water body and watershed 

characteristics, and the composition of the spilled fluid. The impacts from the majority of spills and 

releases is generally localized in extent as only the largest spills and releases impact large areas.
Chapter 8 – Wastewater Disposal and Reuse

8-1 

Chapter 8. Wastewater Disposal 

and Reuse

Abstract 

This chapter addresses the practices and related impacts on drinking water resources that take place 

during the final stage of the hydraulic fracturing water cycle. This stage encompasses the management 

of wastewater, including disposal, reuse in hydraulic fracturing operations, or other uses. For this 

assessment, wastewater is defined as produced water from hydraulically fractured oil and gas wells that 

is managed by any of a number of strategies. The constituents of concern in hydraulic fracturing 

wastewaters that are most frequently noted include high total dissolved solids (TDS), chloride, bromide, 

and radionuclides (radium in particular). Other alkaline earth metals (e.g., barium), organics, and

suspended solids, may be of concern as well. 

Most hydraulic fracturing wastewater is managed by injection into Class II disposal wells. There are also 

“aboveground” management practices, which include reuse in subsequent hydraulic fracturing 

operations; treatment at a centralized waste treatment facility followed by reuse or discharge to surface 

water or a publicly owned treatment works; evaporation; irrigation; and direct discharge (under limited 

conditions). These practices can affect both surface water and groundwater. 

Impacts on surface water arise from discharges of inadequately treated wastewater. In particular, 

bromide and iodide found in highly saline wastewaters can contribute to disinfection byproduct 

formation in downstream drinking water systems. If not removed during treatment, radium, metals, and 

organic compounds can also be discharged. Factors affecting the frequency and severity of impacts on 

surface waters include the wastewater’s composition, its volume, and the processes used to treat it 

(common wastewater treatment processes do not significantly reduce the high TDS content in hydraulic 

fracturing wastewaters). In addition, site-specific factors such as local hydrology, size of the receiving 

water body, and other activities taking place in a watershed can affect the severity of the impact.

Pits and impoundments used for storage or disposal can impact surface water or groundwater through 

spills, leaks, and infiltration through soils. The frequency and severity of such impacts depend on pit 

construction and maintenance as well as proximity to drinking water resources. Unlined pits or those 

with compromised liners can cause long-lasting impacts on groundwater. Depth to the water table, soil 

properties, and the contaminants in the wastewater also affect the likelihood of impacts. 

Characterizing the impacts from wastewater management associated with hydraulic fracturing is 

challenging given gaps in the data. Specifically, there are limited data on the wastewater volumes 

managed, on the influent and effluent concentrations and volumes from facilities that treat wastewater 

from hydraulic fracturing operations, and on wastewater residual characteristics and management of 

those residuals. Further, there is inadequate monitoring of drinking water resources for specific 

contaminants associated with hydraulic fracturing wastewater. However, the data that are available 

have shown that management of hydraulic fracturing wastewater through aboveground practices has 

affected the quality of water resources.
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8-2 

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Chapter 8 – Wastewater Disposal and Reuse

8-3 

8. Wastewater Disposal and Reuse

8.1 Introduction 

The final stage of the hydraulic fracturing water cycle encompasses disposal and reuse of hydraulic 

fracturing wastewater. For the purposes of this assessment, “hydraulic fracturing wastewater” is 

defined as produced water from hydraulically fractured oil and gas wells that is being managed 

using practices that include, but are not limited to, reuse in subsequent hydraulic fracturing

operations, treatment and discharge, and injection into disposal wells.12,3 Although the term 

“wastewater” is generally used in this chapter, when more specific information about a wastewater 

is known (e.g., a source indicates the wastewater is flowback), that information is also noted.

Wells producing from oil and gas reservoirs generate produced water during the course of their 

productive lifespan. This produced water includes the often large volumes of flowback generated 

immediately after fracturing in deep wells with long horizontal sections. Flowback estimates vary 

by formation and are noted in Section 7.2.1 to range from about 300,000 to 10 million gal (1.14 to 

37.8 million L) per well (Mantell, 2013; U.S. GAO, 2012). This large volume of initial flowback 

necessitates having a wastewater management strategy in place before hydraulic fracturing is 

initiated. Also, the longer-term generation of produced water requires ongoing wastewater 

management. 

The majority of wastewater generated from all oil and gas operations in the United States is 

managed via Class II injection wells (Veil, 2015). Injection may be for either disposal or enhanced 

recovery. As hydraulic fracturing activity expands or diminishes, choices regarding disposal 

practices can change in a given region due to factors such as the quality and volume of the fluids; 

regulations; available infrastructure; and the feasibility and cost of treatment, reuse, and disposal 

options. 

Several articles have noted potential effects of hydraulic fracturing wastewater on water resources

(Vengosh et al., 2014; Olmstead et al., 2013; Rahm et al., 2013; States et al., 2013; Vidic et al., 2013; 

Rozell and Reaven, 2012; Entrekin et al., 2011). One study used probability modeling that indicated 

water pollution risk associated with gas extraction in the Marcellus Shale is highest for the 

wastewater disposal aspects of the operation (Rozell and Reaven, 2012). These concerns arise from 

 

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 flowback or produced 

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. 

2 Disposal wells are Underground Injection Control (UIC) Class II wells, including those used for disposal (Class IID), 

enhanced oil recovery (Class IIR), and hydrocarbon storage (Class IIH).

3 The term “reuse” is sometimes used to imply no treatment or basic treatment (e.g., media filtration) for the removal of 

constituents other than total dissolved solids (TDS), while “recycling” is sometimes used to convey more extensive 

treatment (e.g., reverse osmosis (RO)) to remove TDS (Slutz et al., 2012). In this document, the term “reuse” will be used 

to indicate use of wastewater for subsequent hydraulic fracturing, regardless of the level of treatment.
Chapter 8 – Wastewater Disposal and Reuse

8-4 

the elevated concentrations of chloride, bromide, radionuclides, and other constituents of concern 

found in many hydraulic fracturing wastewaters. 

This chapter provides follow-on to Chapter 7, which discusses the per-well volumes of produced 

water (Section 7.2) and composition (Section 7.3), as well as the processes involved in its 

generation and impacts from a number of types of spills and releases. In this chapter, discussions 

are provided on management practices for hydraulic fracturing wastewater, available wastewater 

production information, and estimated aggregate volumes of wastewater generated for several 

states with active hydraulic fracturing (Section 8.2). As a complement to information on the 

composition of wastewaters in Chapter 7, Section 8.3 presents brief information on wastewater 

constituents and their relevance to wastewater management. Management methods used in recent 

years and their potential impacts on drinking water resources are described (Section 8.4). Based on 

background information provided in the earlier sections of the chapter, Section 8.5 discusses 

documented and potential impacts on drinking water resources from particular constituents, and a 

final synthesis discussion is provided (Section 8.6).1 

8.2 Volumes of Hydraulic Fracturing Wastewater

This section provides a general overview of aggregate wastewater quantities generated in the 

course of hydraulic fracturing and subsequent oil and gas production, including estimates at 

regional and state levels. It also discusses methodologies used to produce these estimates and the 

associated challenges. (Chapter 7 provides a more in-depth discussion of the processes affecting 

produced water volumes and presents some typical per-well values and temporal patterns.) Wells 

also generate drilling fluid waste. Compared to produced water, however, drilling fluid wastewater

can constitute a relatively small portion of the total wastewater produced (e.g., <10% in 

Pennsylvania during 2004-2013) (U.S. EPA, 2016d) and is not discussed further in this assessment. 

Wastewater volume can be relevant to treatment costs, reuse options, and disposal capacities. IHS 

Global Insight suggests that as a general rule of thumb, the amount of flowback produced in the 

days or weeks after hydraulic fracturing is roughly comparable to the amount of produced water 

generated long-term over a span of years, which can vary considerably among wells (IHS, 2013). 

Thus, on a local level, operators can anticipate a relatively large volume of wastewater in the weeks 

following fracturing, with slower subsequent production of wastewater. 

Wastewater volumes will most likely vary in the future as the amount and locations of hydraulic 

fracturing activities change and as existing wells age and move into the later phases of their 

production cycles. Substantial increases in wastewater production have occurred during times of 

increasing hydraulic fracturing activity. For instance, the average annual volume of wastewater 

 

1 This chapter makes use of background information collected by the EPA’s Office of Water (OW) as part of the 

development of its recent pretreatment standards for wastewater from unconventional oil and gas formations (U.S. EPA, 

2016d). The pretreatment standards apply to wastewater from crude oil and natural gas produced by a well drilled into 

shale and tight formations. Coalbed methane is beyond the scope of those standards. In this chapter, we consider 

wastewater generated by the hydraulic fracturing of those unconventional oil and gas formations included in the 

background research done by OW. But we also consider wastewater generated by hydraulic fracturing in coalbed 

methane and conventional formations. 
Chapter 8 – Wastewater Disposal and Reuse

8-5 

generated by all gas production (both shale gas and conventional) in Pennsylvania quadrupled from 

the 2001-2006 period to the 2008-2011 period (Wilson and Vanbriesen, 2012). 

However, although the total volume of wastewater might be expected to generally increase and 

decrease as oil and gas drilling and production changes, it is not necessarily a direct correlation. 

Data from the Pennsylvania Department of Environmental Protection (PA DEP) (PA DEP, 2016b) 

show trends in volumes of wastewater compared to gas produced from wells in the Marcellus Shale 

in Pennsylvania (Figure 8-1). Although the data show some variation, they demonstrate a general 

positive correlation between the volume of wastewater and the amount of produced gas until early 

2015. At that time, Baker Hughes weekly rig counts also began to drop, declining from 85 in early 

January 2014 to 24 in early June 2016 (Baker Hughes, 2016). This suggests that a decline in overall 

drilling activity (generally a measure of new wells) can be associated with a decline in wastewater 

production, although the exact timing depends on whether there is a time delay between drilling 

and completion of a well and the start of production from that well. 

Figure 8-1. Wastewater (i.e., produced water and fracturing fluid waste) and produced gas 

volumes from unconventional (as defined by PA DEP) wells in Pennsylvania from January 

2010 through June 2016. 

Source: PA DEP (2016b). 

Estimates of produced water compiled by Veil (2015) indicate that although oil and gas production 

in the United States increased by 29% and 22%, respectively, between 2007 and 2012, produced

water volumes increased by less than 1%. There may be a number of factors contributing to this, 

including as noted by Veil (2015), a number of uncertainties associated with produced water 
Chapter 8 – Wastewater Disposal and Reuse

8-6 

estimates. First, wastewater generation varies from well to well, as do oil and gas production (see 

Chapter 7, Figure 7-1 for discussion of wastewater/produced water decline curves). The rates of 

decline in both wastewater volume and hydrocarbon production also vary among reservoirs. 

Additionally, some wells are drilled and completed but are not immediately put into production. 

Relationships between hydraulic fracturing activity, hydrocarbon production, and produced water 

volumes are likely reservoir- (and maybe production zone-) specific, and existing wells and 

production need to be considered to anticipate wastewater management needs. 

8.2.1 National Level Estimate

Veil (2015) estimated that in 2012, U.S. onshore and offshore oil and gas production generated 

889.59 billion gal (21.18 billion bbls) of produced water. This national-level estimate represents 

total oil and gas wastewater (from all oil and gas resources, and from wells hydraulically fractured 

and wells not hydraulically fractured). The estimate was compiled through a state-by-state analysis 

of survey data obtained from oil and gas agencies in the 31 states with active oil and gas production 

as well as the Department of Interior and U.S. EPA. However, Veil notes several issues with the data 

used for these estimates, including variability among states in data reporting, availability, and 

completeness. These issues may result in underestimation of the volumes of water produced (U.S. 

GAO, 2012). See Section Error! Reference source not found. for more discussion on methods of 

estimating wastewater volumes. 

8.2.2 Regional/State Level Estimates

A limited number of studies have described the geographic variability in oil and gas wastewater 

volumes. Veil (2015) reported that the top ten states nationwide for wastewater production in 

2012 included Texas (35% of total), California (15% of total), Oklahoma (11% of total), and 

Wyoming (11% of total). A study by the Bureau of Land Management (BLM) (Guerra et al., 2011) 

states that in 2008, more than 80% of all oil and gas wastewater was generated in the western 

United States, with Texas producing the highest volume and Wyoming the second highest. The BLM 

report notes substantial wastewater from CBM wells, in particular those in the Powder River Basin 

(Wyoming). Figure 8-2 summarizes the wastewater volumes for these western states, 

demonstrating the wide variability from state to state (likely reflecting differences in the number of 

oil and gas production wells/production activity and reservoir geology). Although the authors do 

not identify all wastewater contributions from production involving hydraulic fracturing, the 

regions with established oil and gas production are likely to have methods and infrastructure 

available for management of hydraulic fracturing wastewater.
Chapter 8 – Wastewater Disposal and Reuse

8-7 

Figure 8-2. Wastewater quantities in the western United States (billions of gal per year).

Data from Guerra et al. (2011).

In the Marcellus region, waste data made public by the PA DEP have enabled analyses of 

wastewater volumes and trends since 2009. Estimates of produced water (including flowback or 

“fracing fluid waste” as well as “produced fluid”) by Wunz (2015) and Shale Alliance for Energy 

Research Pennsylvania (SAFER PA, 2015) for 2014 are 1.73 and 1.64 billion gal (41.19 MMbl and 

39.05 MMbl, respectively). The estimate compiled for this assessment is 0.65 billion gal (15.48 

million bbls) for the first half of 2014 (Table 8-1). Variations among estimates reflect, among other 

factors, challenges in working with a dynamic database for which changes and corrections are 

ongoing. 

Table 8-1 presents estimates of the volumes of hydraulic fracturing wastewater generated and the 

associated numbers of wells in North Dakota, Ohio, Pennsylvania, Texas (injected flowback only), 

and West Virginia. The data shown in this table were compiled for this assessment (except for West 

Virginia) and come primarily from records of produced water made publicly available on state 

websites.1 These states are represented in Table 8-1 because the produced water volumes 

associated with hydraulic fracturing were readily identifiable. The data show that the increase in 

 

1 Data used for Table 8-1 were downloaded from state agency websites and compiled as needed (in either Microsoft Excel 

or Microsoft Access) for each state except West Virginia. Once compiled, data were filtered if needed and summed to 

produce estimates of wastewater production by year and a count of the numbers of wells generating the wastewater. Data 

were downloaded up through 2014. (Note that 2014 data for Pennsylvania and Texas are for partial years.) Differences in 

the years presented for the states are due to differences in data availability from the state agency databases. For West 

Virginia, data are from a report by Hansen et al. (2013) that compiled available flowback data from West Virginia.
Chapter 8 – Wastewater Disposal and Reuse

8-8 

the number of wells producing wastewater and the volumes of wastewater produced are generally 

consistent with the timing of the expansion of high-volume hydraulic fracturing and track with the 

increase in horizontal wells seen in Figure 3-20. 

Several states with mature oil and gas industries (California, Colorado, New Mexico, Utah, and 

Wyoming) make produced water volumes publicly available by well as part of their oil and gas 

production data, but they do not directly indicate which wells have been hydraulically fractured. 

Some states (Colorado, Utah, Wyoming, and New Mexico) specify the producing formation or the 

basin along with volumes of hydrocarbons and produced water. Determining volumes of hydraulic 

fracturing wastewater for these states is challenging because there is a possibility of either 

inadvertently including wastewater from wells not hydraulically fractured or of missing volumes 

that should be included. This may be a particular problem where state terminology regarding what 

constitutes an unconventional resource or hydraulically fractured well is ambiguous or possibly 

different from other states. Appendix Table F-1 provides estimates of wastewater volumes in 

California, Colorado, New Mexico, Utah, and Wyoming in regions where hydraulic fracturing activity 

is taking place, along with notes on data limitations. The data in Table 8-1 and Appendix Table F-1 

illustrate the challenges in both compiling a national estimate of hydraulic fracturing wastewater 

and comparing wastewater production among states due to dissimilar data types, presentation, and 

availability. 

8.2.3 Estimation Methodologies and Challenges

Compiling and comparing data on wastewater production at the wide array of oil and gas locations 

in the United States presents challenges associated with data reporting and availability. Different 

approaches have been used to estimate state-specific and national wastewater volumes. Data from 

state agency websites and databases can be a ready source of information, whether publicly 

available and downloadable or provided directly by agencies upon request. 

Veil (2015) notes that the reported volumes of produced water (e.g., reported by well in state 

production data) can be inaccurate or imprecise because produced water is not monitored 

continuously. Therefore, reported volumes may be estimates. Other issues such as data 

transcription errors or extrapolation of data can also affect reported volumes (Veil, 2015). 

Using produced water volumes from state records to estimate the volume of wastewater regionally 

or nationally presents additional challenges due to a lack of consistency in data collection, 

availability, usability, completeness, and accuracy (Malone et al., 2015; Veil, 2015; U.S. GAO, 2012). 

Due to what are sometimes significant differences in the types of data collected and the 

mechanisms, formats, and definitions used, data cannot always be directly compared from state to 

state. This makes it difficult to aggregate volume data, and estimates may be better and more useful 

at a local or state level. Larger-scale estimates across regions or between states should be 

interpreted carefully. 
Chapter 8 – Wastewater Disposal and Reuse

8-9 

Table 8-1. Estimated volumes (millions of gal) of wastewater based on state data for selected years and numbers of wells 

producing fluid.

State Basin

Principal 

lithologies Data type 2000 2004 2008 2010 2011 2012 2013 2014 Comments

North Dakota Williston Shale Produced 

water 

2 3 130 790 1,900 4,500 8,500 9,700 From North Dakota Oil and 

Gas Commission websitea

. 

Data provided for six 

members of the Bakken

Shale. Produced water 

includes flowback (reports 

are submitted within 30 days 

of well completion.) 

Wells 161 152 844 2,083 3,303 5,036 6,913 8,039

Ohio Appalachian Shale Primarily 

flowback 

- - - - 3 29 110 - Data from Ohio DNR Division 

of Oil and Gasb

. Utica data for 

2011 and 2012. Utica and 

Marcellus data for 2013. 

Brine is noted by agency to 

be mostly flowback.

Wells - - - - 9 86 400 -

Pennsylvania Appalachian Shale Flowback 

plus 

produced 

water (% 

flowback; % 

produced 

water)

- - - 180

(51%; 

49%)

740

(46%; 

54%)

1,100

(36%; 

64%)

1,300

(27%; 

73%)

650

(32%; 

68%)

Waste data from PA DEPc. 

Second half of 2010 and first 

half of 2014. Data described 

as unconventional as defined 

by PADEP. Separate codes 

are provided by PA DEP for 

flowback and produced 

water.

Wells - - - 1,232 2,434 4,039 5,015 5,150
Chapter 8 – Wastewater Disposal and Reuse

8-10 

State Basin

Principal 

lithologies Data type 2000 2004 2008 2010 2011 2012 2013 2014 Comments

Texas Unspecified 

(entire state)

Shale, 

Sandstone

Flowback - 

injected 

volumes

- - - - 490 2,200 3,100 2,000 Waste injection data from 

Texas Railroad Commissiond

. 

Monthly totals are provided 

for entire state. Oct - Dec for 

2011, full years for 2012 and 

2013, and Jan - Oct for 2014

West Virginia Appalachian Shale Flowback - 

Estimated 

total 

disposed

- - - 120 110 59 - - Estimates from Hansen et al. 

(2013).

e

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/production#ARCH1. 

c PA DEP Oil and Gas Reporting website, 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;jsessionid=J3cgVHhK9nkwPrC7ZcWNMgyzF9LCYyR1NmvDy3F

1QQ5wqXfcGNGN!1841197795?fromMain=yes&sessionId=143075601021612. Texas state data provide an aggregate total amount of flowback injected for the past few years. 

(Data on brine volumes injected do not differentiate hydraulically fractured wells and, therefore, well counts are not presented here.) These values are interpreted as estimates 

of generated flowback as based on reported quantities of “fracture water flow back” injected into Class IID wells. 

e West Virginia flowback estimates from Hansen et al. (2013) are based on state data. Well counts that are explicitly associated with the flowback and total disposed volumes 

were not available. 
Chapter 8 – Wastewater Disposal and Reuse

8-11 

To compile estimates of the production and management of hydraulic fracturing wastewater, there 

are additional challenges. Reporting of wastewater volumes may or may not include information 

that helps determine whether the producing well was hydraulically fractured (e.g., an indicator of 

resource type or formation). It also might not be clear whether volumes listed as ‘produced water’ 

include the flowback component. Some states (e.g., Colorado and Pennsylvania) include information 

on disposal and management methods along with production data, and others do not.

Given the limitations of comparing state databases, some studies have generated estimates of 

wastewater volume using water-to-gas and water-to-oil ratios along with the reports of 

hydrocarbon production (Murray, 2013). The reliability of any wastewater estimates made using 

this method would need to be evaluated in terms of the quality, timeframe, and spatial coverage of 

the available data, as well as the extent of the area to which the estimates will be applied. Water-tohydrocarbon ratios are empirical estimates. Because these ratios show a wide variation among 

formations, reliable data are needed to formulate a ratio in a particular region.

Another approach to estimating wastewater volumes would entail multiplying per-well estimates 

of produced water production rates by the numbers of wells in a given area. Challenges associated 

with this approach include obtaining accurate estimates of the number of new and existing wells, 

along with accurate estimates of per-well water production both during the flowback period and 

during the production phase of the well’s lifecycle. In particular, it can be challenging to correctly 

match per-well wastewater production estimates, which will vary by formation, with counts of 

wells, which may or may not be clearly associated with specific formations. Temporal variability in 

wastewater generation would also be difficult to capture and would add to uncertainty. Such an 

approach, however, may be attempted for order of magnitude estimates if the necessary data are 

available and reliable. 

8.3 Wastewater Characteristics 

Along with wastewater volumes, wastewater characteristics and the characteristics of residuals 

produced during treatment or storage are important for understanding the potential impacts of 

management and disposal of hydraulic fracturing wastewater on drinking water resources. This 

section provides brief highlights on several important constituents known to exist in hydraulic 

fracturing wastewaters and residuals. Chapter 7 provides more in-depth detail on the chemistry of 

produced water, and Chapter 9 discusses reference values and health effects associated with 

hydraulic fracturing wastewater constituents. 

8.3.1 Wastewater

Wastewater composition is the result of naturally-occurring constituents originating in the 

formation solids and fluids as well as chemicals associated with the fracturing fluid. Discussion in 

this chapter focuses on constituents in hydraulic fracturing wastewater for which adequate 

information is available to assess documented and potential impacts on drinking water resources. 

There may also be unknown constituents in wastewaters for which analyses have not been 

performed. This is due, in part, to a lack of information on fracturing fluid ingredients identified as 

confidential business information (CBI). In addition, there are uncertainties about how fracturing 
Chapter 8 – Wastewater Disposal and Reuse

8-12 

fluid ingredients are degraded or removed in the subsurface. (See Chapter 5, Section 5.8 for a 

discussion of processes that can cause chemicals to degrade or transform in the subsurface.) 

8.3.1.1 Total Dissolved Solids and Inorganics

Hydraulic fracturing wastewaters are generally high in total dissolved solids (TDS), especially those 

from shales and tight formations, with TDS values ranging from less than 1,000 mg/L to hundreds 

of thousands of mg/L (Section 7.3.4.4). The TDS in wastewaters from shale formations is typically 

dominated by sodium and chloride and may also include elevated concentrations of bromide, 

bicarbonate, sulfate, calcium, magnesium, barium, boron, strontium, radium, organics, and heavy 

metals (Chapman et al., 2012; Rowan et al., 2011; Blauch et al., 2009; Orem et al., 2007; Sirivedhin 

and Dallbauman, 2004). 

Within each formation, the minimum and maximum values presented in Section 7.3.4.4 suggest 

spatial variation in TDS content that may need to be accommodated when considering management 

strategies such as reuse or treatment. In contrast to shales and sandstones, TDS values for 

wastewater from CBM formations are generally lower, with reported concentrations ranging from

approximately 150 mg/L to 62,000 mg/L (DOE, 2014b; Dahm et al., 2011) (Appendix Table E-3). 

This results in fewer treatment challenges and a wider array of management options. 

Constituents commonly found in TDS from hydraulic fracturing wastewaters may have potential 

health impacts or create treatment burdens on downstream drinking water systems if discharged 

at high concentrations to drinking water resources. Bromide, for example, can contribute to the 

increased formation of disinfection byproducts (DBPs) during drinking water treatment (Hammer 

and VanBriesen, 2012); see Section 8.5.1. 

8.3.1.2 Organics

Less information is generally available about organic constituents in hydraulic fracturing 

wastewaters than about inorganic constituents, but there are now several studies reporting 

analyses of organic constituents (Chapter 7). The organic content in flowback waters can vary 

based on the chemical additives (e.g., biocides, antiscalants, gelling agents, breakers) used in 

hydraulic fracturing fluids and the chemistry of the formation, but the organics generally include 

polymers, oil and grease, volatile organic compounds (VOCs), and semi-volatile organic compounds 

(SVOCs) (Akob et al., 2016; Walsh, 2013; Hayes, 2009). Examples of other constituents detected 

include alcohols, naphthalene, acetone, and carbon disulfide, compounds that may be remnants of 

hydraulic fracturing fluid chemicals (Hayes and Severin, 2012b; Hayes, 2009) (Appendix E). 

Wastewater associated with CBM wells may have high concentrations of aromatic and halogenated 

organic contaminants potentially requiring treatment depending on how the wastewater will be 

managed (Pashin et al., 2014; Sirivedhin and Dallbauman, 2004). Concentrations of BTEX (benzene, 

toluene, ethylbenzene, and xylenes) in CBM produced waters are lower than in shale produced 

waters (Appendix Table E-9). 

New research is focusing on transformation products generated in the subsurface; experimental 

work by Kahrilas et al. (2015) suggests that the biocide glutaraldehyde can be present in 

wastewaters along with its transformation products. Low molecular weight organic acids such as 
Chapter 8 – Wastewater Disposal and Reuse

8-13 

acetate, formate, and pyruvate have been detected in Marcellus wastewater, indicating microbial 

degradation of organic compounds in the fracturing fluid or formation (Akob et al., 2015). 

8.3.1.3 Radionuclides

Radionuclides are constituents of concern in some hydraulic fracturing wastewaters, with most of 

the available data obtained for the Marcellus Shale in Pennsylvania (Appendix Table E-8). Results

from a United States Geological Survey (USGS) report (Rowan et al., 2011) indicate that the 

predominant radionuclides in Marcellus Shale wastewater are radium-226 and radium-228. 

Radionuclides in produced fluids are considered ‘technologically enhanced naturally-occurring 

radioactive material’ (TENORM) because they have been exposed to the accessible environment.1 

Although data regarding radionuclides in wastewater from formations other than the Marcellus 

Shale are limited, there is information on the naturally occurring radioactive material (NORM) in 

the formations themselves.2 In particular uranium and thorium can be found in certain organic-rich 

black shales. High uranium content has been measured in the Marcellus, Barnett, Woodford, and 

other black shales (Swanson, 1955) (Section 7.3.4.6). Radium-226 and -228 are decay products of 

uranium and thorium and are soluble (Sturchio et al., 2001; Langmuir and Riese, 1985). Therefore 

wastewater from shales with high concentrations of uranium and thorium can contain radium, 

especially where TDS concentrations are also high (Rowan et al., 2011; Sturchio et al., 2001; Fisher, 

1998). Section 7.3.3.2 provides further information on radionuclides in produced waters and in 

formations.

8.3.2 Constituents in Residuals

Depending on the wastewater and the treatment processes used, treatment residuals can consist of 

sludges, spent media (used filter materials), or brines. Residuals may require further treatment 

(e.g., dewatering sludges) prior to disposal (see Section 8.4.7 for further discussion on management 

of residuals). Residuals can contain constituents such as total suspended solids (TSS), TDS, metals, 

radionuclides, and organics. These constituents will be concentrated in the residuals, with the 

degree of concentration depending on the type of treatment employed. Processes such as 

electrodialysis and mechanical vapor recompression have been found to yield residuals with TDS 

concentrations in excess of 150,000 mg/L after treating waters with influent TDS concentrations of 

approximately 50,000 – 70,000 mg/L (Hayes et al., 2014; Peraki and Ghazanfari, 2014). 

Also, TENORM in wastewaters can cause residual wastes to have gamma radiation emissions 

(Kappel et al., 2013). A laboratory study by Zhang et al. (2014b) estimated that the barium sulfate 

solids precipitated during treatment to remove barium and strontium from Marcellus Shale 

wastewater would also contain between 2,571 and 18,087 pCi/g of radium due to coprecipitation. 

Another similar study using mass balances calculated that sludge from a sulfate precipitation 

 

1 Technologically Enhanced Naturally Occurring Radioactive Material (TENORM) is defined by the EPA as naturally 

occurring radioactive materials (NORM) that have been concentrated or exposed to the accessible environment as a result 

of human activities such as manufacturing, mineral extraction, or water processing.

2 Naturally Occurring Radioactive Materials (NORM) are radioactive materials found in nature that have not been moved 

or concentrated by human activities.
Chapter 8 – Wastewater Disposal and Reuse

8-14 

process would have an average radium concentration of 213 pCi/g (Silva et al., 2012). In sludge 

from lime softening processes, Silva et al. (2012) estimated a radium-226 concentration of 58 

pCi/g, a level that would necessitate disposal as a low-level radioactive waste. 

8.4 Wastewater Management Practices and Their Potential Impacts on 

Drinking Water Resources

Operators have several strategies for management of hydraulic fracturing wastewaters (Figure 

8-3), with the most common choice being disposal via Class IID wells (Veil, 2015; Clark et al., 2013; 

Hammer and VanBriesen, 2012). Other practices include reuse in subsequent hydraulic fracturing 

operations (with varying levels of treatment), treatment at a centralized waste treatment facility 

(CWT) (often followed by reuse), evaporation (in arid regions), irrigation (with no discharge to 

waters of the United States), and direct discharge for livestock or agricultural use (allowed west of 

the 98th meridian). Up until 2011, treatment of unconventional oil and gas wastewaters (as defined 

by PA DEP) at publicly owned treatment works (POTWs) was a common practice for wastewater 

management in the Marcellus region (Lutz et al., 2013); this is discussed further in Text Box 8-1. 

The methods shown in Figure 8-3 represent wastewater management strategies, not all of which 

would be used at the same facility. Descriptions of incidents of unpermitted disposal and resulting 

legal actions have also been publicly reported (Chapter 7). However, such events are not generally 

described in the scientific literature, and the prevalence of this type of activity is unclear. Additional 

sources of information about potential impacts exist, but some records are sealed (e.g., litigation 

records) and are not publicly accessible.

Figure 8-3. Schematic of wastewater management strategies. 

Gray lines indicate management strategies that involve injection, either for reuse or disposal, and blue lines 

indicate management strategies that lead to other end points such as discharge, evaporation, landfills, or other 

uses. 
Chapter 8 – Wastewater Disposal and Reuse

8-15 

Each of the wastewater management strategies can potentially lead to impacts on drinking water

resources during some phase of their execution. Such impacts include, but are not limited to:

accidental releases during transport (Chapter 7); discharges of treated wastewaters from CWTs or

POTWs where treatment for certain constituents has been inadequate; migration of constituents to

groundwater due to leakage from pits or land application of wastewaters; leakage from pits that

reach surface waters (Chapter 7, Section 8.4.5); inappropriate management of liquid or solid

residuals (e.g., leaching from landfills); or accumulation of constituents in sediments near outfalls of

CWTs or POTWs that are treating or have treated hydraulic fracturing wastewater.1 

A reliable census of oil and gas wastewater management practices nationwide is difficult to

assemble due to a lack of consistent and comparable data among states. In addition, we do not

know how often operators use more than one wastewater management strategy at a site (e.g.,

evaporation and injection), further complicating the tracking of wastewater management. As part of

a data survey conducted by Veil (2015), some state agencies provided estimates of oil and gas

wastewater volumes handled by several management practices (Table 8-2). These estimates 

illustrate how widespread injection for both enhanced recovery and for disposal is for managing oil 

and gas wastewater. The data also show regional differences in reuse and other practices. For 

hydraulic fracturing wastewaters, Table 8-3 illustrates nationwide variability in the primary 

wastewater management methods using qualitative and quantitative sources. Similar to Table 8-2, 

Table 8-3 shows disposal via underground injection predominates in most regions, and reuse is 

predominant in the Marcellus Region. (Table 8-3 does not include wastewater management in areas 

of CBM production.) 

Management choices are affected by cost and a number of directly and indirectly related factors,

including the chemical properties of the wastewater; the volume, duration, and flow rate of the

wastewater generated; the feasibility of each option; the availability of necessary infrastructure;

local, state, and federal regulations (Text Box 8-2); and operator discretion (U.S. GAO, 2012; NPC,

2011a). The economics (such as transport, storage, and disposal costs) and availability of treatment

and disposal methods are of primary importance (U.S. GAO, 2012). For wastewater composition,

there is limited information on the degradation or removal of fracturing fluid ingredients in the

subsurface. Chemical disclosure requirements vary among states, and some fracturing fluid

ingredients are claimed to be CBI. Therefore, the possible presence of unknown chemical 

constituents in wastewater contributes to uncertainty about the effectiveness and potential impacts

of management strategies, particularly with regard to treatment efficacy.

1 The term surface water as used in this assessment refers to surface waters that meet the definition of waters of 

the United States under the CWA (House Bill No. 1950, 2011). 
Chapter 8 – Wastewater Disposal and Reuse

8-16 

Table 8-2. Estimated percentages of wastewater managed by practice and by state.

Source: Veil (2015). Estimates do not identify interstate transport (e.g., wastewater transported from PA to OH or WV for injection into disposal wells). Thus, 

there may have been some double counting of volumes in both the generating and receiving states.

Management 

practice Percentage of produced water managed by practice and state (%)

AR CA CO NM ND OH OK PA TX UT WV WY

Injection for 

enhanced oil 

recovery

22 46 32 50 d 18 4.0 47 0 48 40 27 73

Injection for 

disposal 76 20 32 50 d 56 91 47 12 37 47 25 27

Surface 

discharge 0 2 10 no data 0 0 0 2.3 5.0 f 6 0 uncertain

Evaporation 0 21 9.0 no data 0 0 0 0 0 0 uncertain

Offsite 

commercial 

disposal

0.1 a 9 5.7 c no data 26

Included in 

injection 

for disposal

6.0 e 0 10 e 7 g 28 h uncertain

Beneficial 

reuse

1.1 b no data 12 b no data 0 5.0 0 

85

(includes 

reuse for 

HF)

Est. 15-20

(flowback 

fluid) 

0.5 uncertain uncertain

a Land farm. 

b Reuse for HF.

c Pits.

d Assumes even split with injection for enhanced oil recovery and injection for disposal.

e Injection.

f Fresh produced water. 

g Evaporation ponds.

h Disposal wells.
Chapter 8 – Wastewater Disposal and Reuse

8-17 

Table 8-3. Management practices for wastewater from unconventional oil and gas resources. 

Source: U.S. EPA (2016d). 

Basin Formation

Resource 

type Reuse

Injection for 

disposal

CWT 

facilities Notes

Available 

datab 

Michigan Antrim Shale gas XXX Qualitative

Appalachian 

Marcellus/Utica (PA) Shale gas XXX XX XX Limited disposal wells in east Quantitative

Marcellus/Utica (WV) Shale gas/oil XXX XX X Quantitative

Marcellus/Utica (OH) Shale gas/oil XX XXX X Mixed

Anadarko

Granite Wash Tight gas XX XXX Xa Mixed

Mississippi Lime Tight oil X XXX Reuse/recycling limited but is being 

evaluated Qualitative

Woodford, Cana, Caney Shale gas/oil X XXX Xa Qualitative

Arkoma Fayetteville Shale gas XX XX Xa Few existing disposal wells; new CWT 

facilities are under construction Mixed

Fort Worth Barnett Shale gas X XXX Xa

Reuse/recycle not typically used due to 

high TDS early in flowback and abundance 

of disposal wells

Mixed

Permian Avalon/Bone Springs, 

Wolfcamp, Spraberry

Shale/tight 

oil/gas X XXX Xa Mixed

TX-LA-MS Salt Haynesville Tight gas X XXX

Reuse/recycle not typically used due to 

high TDS early in flowback and abundance 

of disposal wells

Mixed

West Gulf Eagle Ford, Pearsall Shale gas/oil X XXX X Mixed

Denver Julesburg Niobrara Shale gas/oil X XXX X Mixed

Piceance; Green 

River Mesaverde/Lance Tight gas X XX X Also managed through evaporation to atmosphere in ponds in this region Qualitative
Chapter 8 – Wastewater Disposal and Reuse

8-18 

Basin Formation

Resource 

type Reuse

Injection for 

disposal

CWT 

facilities Notes

Available 

datab 

Williston Bakken Shale oil X XXX Reuse/recycling limited but is being 

evaluated Mixed

a CWT facilities identified in these formations are all operator-owned.

b This column indicates the type of data the EPA based the number of Xs on. In most cases, the EPA used a mixture of qualitative and quantitative data sources along with 

engineering judgment to determine the number of Xs.

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. Blanks indicate the 

management practices have not been documented in the given location.
Chapter 8 – Wastewater Disposal and Reuse

8-19 

The availability and use of wastewater management strategies in a region can change over time as 

oil and gas production increases or decreases, regulations change, costs shift, and technologies

evolve. Text Box 8-1 and Figure 8-4 illustrate shifting wastewater management practices in 

Pennsylvania as gas development in the Marcellus Shale increased and concerns over high-TDS 

discharges prompted a regulatory response. Reuse has increased substantially at well sites in 

Pennsylvania (labeled as “Reuse HF” in Figure 8-4) and wastewater management at CWTs has 

moved toward more facilities that provide wastewater for reuse and do not discharge (termed 

“zero-discharge facilities”). The estimated total reuse rate in Pennsylvania was 80% in 2012 and 

90% in 2013 (PA DEP, 2015a). In contrast, wastewater disposal data in areas of Colorado where 

hydraulic fracturing takes place show a steady use of injection wells, an increase in surface water 

discharges, and a decrease in the use of on-site pits for evaporation since 2000 (Figure 8-5). 

Another factor influencing reuse is the pace of hydraulic fracturing in the area. When hydraulic 

fracturing is active, demand for reuse is high. Some formations that are hydraulically fractured such 

as the Marcellus Shale and the Utica Shale are still in the early stages of development, with large 

potential resources not yet developed. For these plays, the need for wastewater treatment and/or 

reuse may remain high for decades to come, and the long-term wastewater management needs 

must be considered and addressed (SAFER PA, 2015).1 

Researchers have developed optimization models to aid in the minimization of wastewater 

management costs as a part of comprehensive water management planning. For example, Yang et 

al. (2014) suggest an approach for reusing flowback in scheduled hydraulic fracturing events to 

minimize the operational costs of transportation, treatment, storage, and wastewater disposal.

Another modeling study proposes an approach to minimize the total cost of water usage and 

wastewater treatment and disposal by optimizing capital costs (such as the costs of treatment units 

and storage pits) and operating costs for flowback management, treatment, storage, reuse, and 

wastewater disposal (Lira-Barragan et al., 2016). 

Text Box 8-1. Temporal Trends in Wastewater Management – Experience of Pennsylvania.

Gross natural gas withdrawals from shale formations in the United States increased 518% between 2007 and 

2012 (EIA, 2014b). This production increase has led to larger volumes of wastewater requiring appropriate 

management (Vidic et al., 2013; Gregory et al., 2011; Kargbo et al., 2010). The rapid increase in wastewater 

generated from hydraulically fractured oil and gas wells has led to many changes in wastewater disposal 

practices in the oil and gas industry. Changes have been most evident in Pennsylvania, which has experienced 

a more than 1,400% increase in natural gas production since 2000 (EIA, 2014b). 

Lutz et al. (2013) estimated that total wastewater generation in the Marcellus region increased 570% 

between 2004 and 2013. The authors concluded that this increase has created stress on the existing 

wastewater disposal infrastructure. In 2010, concerns arose over elevated TDS in the Monongahela River 

(Text Box 8-1 is continued on the following page.)

 

1 As noted in Chapter 3, oil and gas prices influence new drilling activity. However, the links between oil and gas prices 

and the generation of wastewater (as a byproduct of production) appear to be less direct. 
Chapter 8 – Wastewater Disposal and Reuse

8-20 

Text Box 8-1 (continued). Temporal Trends in Wastewater Management – Experience of 

Pennsylvania 

basin, and studies linked high TDS (and, in particular, high bromide levels) to elevated DBP levels in drinking 

water systems (PA DEP, 2011a). In response, PA DEP amended Chapter 95 Wastewater Treatment 

Requirements under the Clean Streams Law for new discharges of TDS in wastewaters. This regulation is also 

informally known as the 2010 TDS regulation. The regulation disallowed any new direct discharges to 

streams as well as direct disposal at POTWs of hydraulic fracturing wastewater and set limits on treated 

discharges from new CWTs of 500 mg/L TDS, 250 mg/L chloride, 10 mg/L barium, and 10 mg/L strontium. 

Existing discharges were exempt. 

In April 2011, PA DEP announced a request that by May 19, 2011, gas drilling operators voluntarily stop 

transporting wastewater from shale gas extraction (i.e., unconventional resources as defined by PA DEP) to 

the eight CWTs and seven POTWs that were exempt from the 2010 TDS regulation.1 Follow-up letters from 

PA DEP to the owners of the wells specified that the role of bromides from Marcellus Shale wastewaters in the 

formation of total trihalomethanes (TTHM) was of concern due to the their potential public health impacts 

(PA DEP, 2011a). 

In response to the request, the oil and gas industry in Pennsylvania accelerated the switch of wastewater 

deliveries from POTWs to CWTs for better removal of metals and suspended solids (Schmidt, 2013). Effluent 

sampling at two POTWs that had accepted Marcellus Shale wastewater showed that concentrations of 

bromide, chloride, barium, strontium, and sulfate dropped after the April 2011 request (Ferrar et al., 2013); 

data based on two sampling events, one before and one after May 2011). 

Between early and late 2011, although reported wastewater production more than doubled, Marcellus Shale 

drilling companies in Pennsylvania reduced their use of CWTs that were exempt from the 2010 TDS

regulation by 98%, and direct disposal of Marcellus Shale wastewater at POTWs was “virtually eliminated” 

(Hammer and VanBriesen, 2012). 

Along with the decreased discharges from POTWs, there has been increased reuse of wastewater in the 

Marcellus Shale region. From 2008-2011, reuse of Marcellus wastewater for hydraulic fracturing increased, 

POTW treatment volumes decreased, tracking of wastewater improved, and wastewater transportation

distances decreased (Rahm et al., 2013). Maloney and Yoxtheimer (2012) analyzed data from 2011 and found

that reuse of flowback increased to 90% by volume. Eight percent of flowback was sent to CWTs. Brine water, 

which was defined as formation water, was reused (58%), disposed via injection well (27%), or sent to CWTs 

(14%). Of all the fluid wastes in the analysis, brine water was most likely to be transported to other states 

(28%). Maloney and Yoxtheimer (2012) also concluded that wastewater disposal to municipal sewage 

treatment plants declined nearly 100% from 47,221 bbls in the first half of 2011 to 408 bbls in the second

half. 

 

1 An unconventional formation was defined in 2011 by the state of Pennsylvania as “A geological shale formation existing 

below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be 

produced at economic flow rates or in economic volumes except by vertical or horizontal wellbores stimulated by 

hydraulic fracture treatments or by using multilateral wellbores or other techniques to expose more of the formation to 

the wellbore.” The EPA defines unconventional oil and gas as crude oil and natural gas produced by a well drilled into a 

shale and/or tight formation (including, but not limited to, shale gas, shale oil, tight gas, and tight oil). For the purpose of 

the rule, the definition of UOG does not include CBM (U.S. EPA, 2016d). 
Chapter 8 – Wastewater Disposal and Reuse

8-21 

Figure 8-4. Percentages of total unconventional wastewater (as defined by PA DEP) managed 

via various practices for the second half of 2009 through the first half of 2014. 

The volume sent to POTWs in 2013 was 0%. Note also that a majority of wastewater sent to CWTs is subsequently 

reused, so that when combined with “Reuse HF,” the total reuse rate was approximately 90% in 2013. “Reuse HF” 

indicates on-site reuse. Source: Waste data from PA DEP (2015a). 

Text Box 8-2. Regulations Affecting Wastewater Management. 

Regulations affect wastewater management options and vary geographically as well as over time. At the 

Federal level, the EPA has promulgated national technology-based regulations, known as effluent limitations 

guidelines and standards (ELGs), for the oil and gas extraction industry, which can be found in 40 U.S. Code of 

Federal Regulations (CFR) Part 435. These ELGs do not apply to CBM discharges which are subject to 

technology based limits developed by permit writers on a case-by-case “best professional judgment” basis. 

The Onshore subcategory of the oil and gas, ELGs 40 CFR 125.3, Subpart C, prohibits the discharge of 

wastewater pollutants to waters of the United States from onshore oil and gas extraction facilities, with one 

exception in the arid west as discussed below. This “zero-discharge standard” means that, unless the 

exception applies, oil and gas wastewater pollutants cannot be discharged directly to waters of the United 

States. Operators have met this requirement through underground injection, reuse, or transfer of wastewater 

to POTWs and/or CWTs. The EPA finalized a rule in June 2016 that would prohibit operators from sending

wastewater from unconventional oil and gas extraction to POTWs. Operators can continue to send 

wastewater to CWTs, which are subject to regulation under a separate set of ELGs in 40 CFR Part 437. 

In addition, Subpart E of the oil and gas ELGs establishes an exception to the zero discharge standard west of 

the 98th meridian (the arid western portion of the continental United States), allowing discharges of 

produced water from onshore oil and gas extraction facilities to waters of the United States if the produced 

water has a use in agriculture or wildlife propagation when discharged into navigable waters. The term “use 

in agricultural or wildlife propagation” means that: (1) the produced water is of good enough quality to be 

used for wildlife or livestock watering or other agricultural uses; and (2) the produced water is actually put to

(Text Box 8-2 is continued on the following page.)
Chapter 8 – Wastewater Disposal and Reuse

8-22 

Text Box 8-2 (continued). Regulations Affecting Wastewater Management. 

such use during periods of discharge (40 CFR 135.51(c)). Produced water discharged under this exception 

must not exceed an oil and grease concentration of 35 milligrams per liter (mg/L). Subpart E does not allow 

for discharge from sources other than produced water (i.e., drilling muds, drill cuttings, produced sands) to 

waters of the United States.

In addition to the technology-based limitations discussed above, the Clean Water Act (CWA) and the EPA’s 

implementing regulations also require that permits include more stringent limits as necessary to meet 

applicable water quality standards. CWA Section 301(b)(1)(C); 40 CFR 122.44(d)(1). 

Figure 8-5. Management of wastewater in Colorado in regions where hydraulic fracturing is 

being performed. 

See footnote for details on disposal codes.1 Production data from Colorado Oil and Gas Conservation Commission 

(COGCC, 2015). 

The following sections provide an overview of hydraulic fracturing wastewater management 

methods, with some discussion of the geographic and temporal variations in practices and their 

impacts on drinking water resources. In addition to currently used treatment and disposal 

methods, this section also briefly describes past treatment of hydraulic fracturing wastewater at 

 

1 Codes for wastewater disposal from COGCC are described by Veil (2015) as follows:

• Commercial disposal facility: water sent to commercial pits.

• On-site pit: most water evaporates, or excess water is hauled to disposal wells.

• Central disposal pit: Central facilities owned by a single producer to handle water from multiple wells (some 

recycled, much is injected).

• Injected on lease: Injected into wells, roughly half for enhanced recovery.

• Surface discharge: water is either fresh or treated to acceptable standards and discharged to surface water.
Chapter 8 – Wastewater Disposal and Reuse

8-23 

POTWs. More in-depth descriptions of treatment technologies applicable to hydraulic fracturing 

wastewater are available in Appendix F.

8.4.1 Underground Injection

Oil- and gas-related wastewater may be disposed of via Class II injection wells (disposal wells are 

referred to as Class IID whereas enhanced recovery wells are referred to as Class IIR) regulated by 

the UIC Program under the SDWA.1 Nationwide, injection wells receive a large percentage of 

wastewater from the oil and gas industry, including wastewater associated with hydraulic 

fracturing. Veil (2015) estimates that in 2012, U.S. oil and gas production from onshore wells 

generated over 863 billion gal (20.56 billion bbls or 3.27 trillion L) of produced water, and of that 

volume, information on management was available for 97%. The study estimated that about 93% 

was injected into Class II wells, with about 47% injected into Class IID wells and 46% injected into 

Class IIR wells.2 

The above national estimates are for the oil and gas industry as a whole. A good national estimate of 

the amount of hydraulic fracturing wastewater injected into Class II wells is difficult to develop due 

to lack of available information and data on injection of hydraulic fracturing wastewater. 

Management of hydraulic fracturing wastewater is not well tracked or made publicly available in 

many states (Pennsylvania being a notable exception). The local availability of Class IID wells along 

with generally low reuse rates, however, are consistent with Class IID wells being a primary means 

of wastewater management in many areas with hydraulic fracturing activity. 

According to recently released data from 2012 and 2013, there are about 26,400 active Class IID 

wells in the United States, with more than 65% of these located in Texas, Oklahoma, and Kansas 

(Table 8-4). In Pennsylvania, on the other hand, there are currently nine operating disposal wells, 

and only three of these are commercially operated wells (at one facility) (SAFER PA, 2015). The 

location and number of Class IID wells is in part determined by geology (including depth and 

permeability of geologic formations appropriate for injection), permitting, and historical demand 

for disposal of oil and gas wastewater. The large Class IID well capacity in Texas, for example, is 

consistent with the availability of formations with suitable geology and the demand for wastewater 

disposal associated with a mature and active oil and gas industry. In contrast, injection plays a 

relatively small role in Marcellus Shale wastewater management in Pennsylvania—about 10% in 

2013 and the first half of 2014 (PA DEP, 2015a). 

 

1 States may be given federal approval to run a UIC program under SDWA. UIC Class II wells include those used for 

disposal (Class IID), enhanced oil recovery (Class IIR), and hydrocarbon storage (Class IIH). 

2 Because some states surveyed by Veil (2015) do not distinguish between volumes injected for disposal versus enhanced 

recovery, assumptions and analyses were used in the study to estimate the two types of injection in some states. 
Chapter 8 – Wastewater Disposal and Reuse

8-24 

Table 8-4. Distribution of active Class IID wells across the United States. 

Data are primarily from 2012 and 2013. Source: U.S. EPA (2016d). 

Geographic region 

(from the EIA) State

Number of active 

disposal wellsa 

Average disposal 

rate per well

(gpd/well)b 

State disposal 

rate (MGD)

Alaska Alaska 45 182,000 8.2

East Illinois 1,054 —c —c

Michigan 772 16,200 13

Florida 14 246,000 3.4

Indiana 208 7,950 1.7

Ohio 190 8,570 1.6

West Virginia 64 6,970 0.45

Kentucky 58 4,650 0.27

Virginia 12 17,500 0.21

Pennsylvania 9 6,380 0.057

New York 10d 33.7 0.00034

Gulf Coast/Southwest Texas 7,876 52,100 410

Louisiana 2,448 40,300 99

New Mexico 736 48,600 36

Mississippi 499 24,200 12

Alabama 85 53,300 4.5

Mid-Continent Kansas 5,516 25,600 140

Oklahoma 3,837 35,900 140

Arkansas 640e 25,400 16

Nebraska 113 19,100 2.2

Missouri 11 2,270 0.025

Iowa 3 —c —c

Northern Great Plains North Dakota 395 53,300 21

Montana 199 32,700 6.5

South Dakota 15 17,400 0.26
Chapter 8 – Wastewater Disposal and Reuse

8-25 

Geographic region 

(from the EIA) State

Number of active 

disposal wellsa 

Average disposal 

rate per well

(gpd/well)b 

State disposal 

rate (MGD)

Rocky Mountains Wyoming 335 107,000 36

Colorado 292 48,800 14

Utah 118 83,400 9.8

West Coast California 826 86,800 72

Nevada 10 54,600 0.55

Oregon 9 —c —c

Washington 1 —c —c

Total 26,400 41,300 1,050

Abbreviations: gpd—gal per day; MGD—million gal per day.

a Number of active disposal wells is based primarily on data from 2012 to 2013.

b Typical injection volumes per well are based on historical annual volumes for injection for disposal divided by the number of

active disposal wells during the same year (primarily 2012 to 2013 data). c Disposal rates and volumes are unknown.

d These wells are not currently permitted to accept extraction wastewater from production in unconventional reservoirs. 

e Only 24 of the 640 active disposal wells in Arkansas are in the northern half of the state, close to the Fayetteville Shale. 

The decision to inject hydraulic fracturing wastewater into Class IID wells depends in part on cost, 

including transportation costs. Therefore, the distance between the production well and a disposal 

well is an important consideration. For oil and gas producers, underground injection is a low cost 

management strategy unless significant trucking is needed to transport the wastewater to a 

disposal well (U.S. GAO, 2012). 

Evaluation of documented or potential impacts on drinking water resources associated with 

disposal at Class IID injection wells is outside of the scope of this assessment. However, disposal 

wells play a significant role in the overall management of hydraulic fracturing water nationwide, 

and their availability and capacity are integral factors in determining which wastewater 

management strategies are used by operators in a given region. Should the feasibility of managing 

wastewater via underground injection become limited or less economically advantageous, 

operators will need to adjust their wastewater management programs. They may evaluate and 

implement other local practices such as sending wastewater to a CWT for treatment and discharge 

or reuse. 

Recent events and studies, for example, have documented a link between wastewater injection and 

seismic activity in some locations in several states, including Oklahoma, Colorado, New Mexico, 

Arkansas, and Ohio (Weingarten et al., 2015; Wong et al., 2015). The Oklahoma Geological Survey

(Andrews and Holland, 2015) “considers it very likely that the majority of recent earthquakes, 

particularly those in central and north-central Oklahoma, are triggered by the injection of produced 

water in disposal wells.” Walsh and Zoback (2015) correlated wastewater injection from 
Chapter 8 – Wastewater Disposal and Reuse

8-26 

production wells (including hydraulically fractured wells) into Oklahoma’s Arbuckle formation to 

the steep increase in seismic events observed in that state. Farther west, in the Raton Basin of 

southern Colorado and northern New Mexico, Rubinstein et al. (2014) presented several lines of 

evidence linking injection well disposal of CBM produced water to seismic events. Horton (2012)

attributed a swarm of earthquakes in Northern Arkansas to hydraulic fracturing wastewater 

injection, and in a study evaluating multiple states in the mid-continent region, Weingarten et al. 

(2015) demonstrated a relationship between Class II wells (including both Class IID and Class IIR 

wells) and seismicity. 

The local availability of Class IID wells and the capacity to accept large volumes of wastewater 

could be affected by these recent findings concerning seismic activity associated with injection (U.S. 

EPA, 2014c). Between 2011 and 2016, some state UIC programs modified their Class II wastewater 

injection regulations and permitting requirements. At least eight states (Arkansas, Colorado, 

Illinois, Kansas, Ohio, Oklahoma, Texas, and West Virginia) consider an assessment of seismicity in 

their Class II programs and have regulatory provisions for banning or shutting injection wells 

and/or modifying injection volumes and pressures if evidence indicates that a well is near a fault 

and/or is contributing to seismic activity. 

As an example, Oklahoma has recently taken steps to reduce the risk of induced seismicity by 

implementing a regional strategy intended to reduce wastewater injection in certain regions (OCC 

OGCD, 2016). These actions affect over 10,000 square miles and 600 wastewater injection wells in 

western and central Oklahoma. The measures are intended to reduce wastewater injection in the 

area by 40% below 2014 totals, which will affect wastewater management and disposal practices 

across this large area.1

In terms of potential impacts on drinking water resources, Class IID facilities are subject to the 

same general considerations regarding wastewater storage and handling as other wastewater 

management sites and facilities (e.g., CWTs). Changes in surface water or groundwater quality due 

to general wastewater handling at these facilities may be another factor affecting wastewater 

management practices in some locations or regions. For example, Kell (2011) identified eight 

groundwater contamination incidents in Texas between 1993 and 2008 due to water releases from 

storage facilities associated with Class II well sites. A recent study by the United States Geological 

Survey documented impacts on surface water from hydraulic fracturing wastewater at a Class II 

disposal well site in central West Virginia (Akob et al., 2016). Water samples collected downstream 

from the facility were indicative of wastewater from hydraulic fracturing operations handled at the 

site. The authors documented elevated specific conductance and elevated TDS, sodium, chloride, 

barium, bromide, strontium, and lithium concentrations, and different strontium isotope ratios 

compared to those found in upstream, background waters. The study concluded that activities at 

the wastewater facility have affected water quality in a nearby stream. The pathways for the 

movement of wastewater into the local stream include several possibilities (e.g., leaks from storage 

ponds and tanks, transportation activities, previous site history). 

 

1 For additional information on strategies and initiatives regarding wastewater injection and inducted seismicity, see the 

following: KDHE (2014), States First Initiative (2014), and U.S. EPA (2014c). 
Chapter 8 – Wastewater Disposal and Reuse

8-27 

8.4.2 Publicly Owned Treatment Works

POTWs are designed to treat local municipal wastewater and indirect discharges from industrial 

users. POTWs are also used to treat wastewater and other wastes from oil and gas operations in 

some eastern states. Although this is not a common method of treatment for oil and gas 

wastewaters in the United States, the scarcity of injection wells for waste disposal in Pennsylvania 

drove the need for disposal alternatives (Wilson and Vanbriesen, 2012). When development of the 

Marcellus Shale began, POTWs were used to treat wastewater originating from these oil and gas 

wells (Kappel et al., 2013; Soeder and Kappel, 2009). However, elevated concentrations of 

constituents in wastewater from the Marcellus region (halides, heavy metals, organic compounds, 

radionuclides, and salts) can pass through the treatment processes commonly used in POTWs and 

be discharged to receiving waters (Cusick, 2013; Kappel, 2013; Lutz et al., 2013; Schmidt, 2013). In 

addition, sudden, extreme salt fluctuations can disturb POTW biological treatment processes 

(Linarić et al., 2013; Lefebvre and Moletta, 2006). 

The annual reported volume of oil and gas wastewater treated at POTWs in the Marcellus Shale 

region peaked in 2008 and has since declined significantly (Figure 8-6). As discussed in Text Box 

8-1, this was in response to an April 2011 request from PA DEP asking operators to cease sending 

Marcellus Shale wastewater to 15 POTWs and CWTs that were exempt from the 2010 TDS 

regulation (Rahm et al., 2013). Although operators complied with the request in May 2011, nonMarcellus oil and gas produced water continued to be processed at these facilities (Ferrar et al., 

2013; Lutz et al., 2013; Wilson and Vanbriesen, 2012).1 In August 2016, the EPA finalized 

pretreatment standards prohibiting discharges of unconventional wastewater pollutants to POTWs 

(U.S. EPA, 2016d). 

Figure 8-6. Oil and gas wastewater volumes discharged to POTWs from 2001-2011 in the 

Marcellus Shale. (“Conventional” is indicated by the authors as non-Marcellus wells and 

described as vertically drilled to shallower depths in more porous formations.) 

Due to an unrecoverable data loss at the PA DEP, records for 2007 were not available. Source: Lutz et al. (2013). 

 

1 POTWs in Pennsylvania have likely been accepting waste considered conventional by Pennsylvania but unconventional 

by others based on the EPA’s broader definition (Text Box 8-1). 
Chapter 8 – Wastewater Disposal and Reuse

8-28 

8.4.3 Centralized Waste Treatment Facilities 

A CWT facility is generally defined as one that accepts industrial materials (hazardous or nonhazardous, solid, or liquid) generated at another facility (off-site) for treatment or recovery (EPA, 

2000). (Wastewater may also be treated at on-site mobile or semi-mobile facilities; see Appendix F 

for additional information.) The decision to treat hydraulic fracturing wastewater at a CWT and the 

level of treatment used depends upon several factors, such as a lack of proximity to Class II disposal 

wells; whether the wastewater might be reused for additional hydraulic fracturing jobs; the water 

quality needed if it will be reused; whether the treated wastewater can be discharged under the 

Subpart E agricultural and wildlife use exception in the arid west; and the water quality needed if it 

will be discharged to the waters of the United States. As a group, CWTs that accept oil and gas 

wastewater offer a wide variety of treatment capabilities and configurations (Text Box 8-3 and 

Appendix F).

Text Box 8-3. Wastewater Treatment Processes. 

The constituents prevalent in hydraulic fracturing wastewater include TDS, TSS, radionuclides, organic 

compounds, and metals (Section 8.3 and Chapter 7). If the ultimate disposal or use of the wastewater 

necessitates treatment, a variety of technologies can be employed to remove or reduce these constituent 

concentrations. 

The most basic treatment needed for oil and gas wastewaters, including those from hydraulic fracturing 

operations, is separation to remove TSS and oil and grease. This is accomplished through separation 

technologies including settling, skimming, hydrocyclones, dissolved air or induced gas flotation, media 

filtration, or biological aerated filters (Igunnu and Chen, 2014; Duraisamy et al., 2013; Barrett, 2010; 

Shammas, 2010). 

Other treatment processes that may be used include media filtration after chemical precipitation for hardness 

and metals (Boschee, 2014); adsorption technologies for organics, heavy metals, and some anions (Igunnu 

and Chen, 2014); a variety of membrane processes (microfiltration, ultrafiltration, nanofiltration, reverse 

osmosis (RO)); and distillation technologies for metals and organics (Drewes et al., 2009). 

Advanced processes, such as RO, or distillation methods, such as mechanical vapor recompression (MVR), are 

needed if the system requires significant reduction in TDS (Drewes et al., 2009; LEau LLC, 2008; Hamieh and 

Beckman, 2006). However, RO is typically only capable of treating TDS concentrations less than 35,000 mg/L 

(Shaffer et al., 2013), whereas distillation can effectively treat higher TDS waters (Hayes et al., 2014; Drewes 

et al., 2009). Extremely high TDS waters may require a series of advanced treatment processes, which can be 

very costly. 

An emerging technology in hydraulic fracturing wastewater treatment is electrocoagulation, which has been 

used in mobile treatment systems to remove organics, TSS, and metals (Halliburton, 2014; Igunnu and Chen, 

2014). 

Appendix F provides more in-depth descriptions of technologies used to treat for hydraulic fracturing 

wastewaters and the constituents they remove. Also, Appendix Table F-4 provides an overview of influent 

and effluent results and removal percentages for constituents of concern at oil and gas treatment facilities 

reported in the literature (both conventional and unconventional) and the specific technology(ies) used to 

remove them. Section 8.4.7 discusses solid and liquid residuals, including treatment-related wastes. 
Chapter 8 – Wastewater Disposal and Reuse

8-29 

The treated effluent from a CWT can be reused in hydraulic fracturing operations (also called zerodischarge), discharged directly to a receiving water under a National Pollutant Discharge 

Elimination System (NPDES) permit, discharged indirectly to a POTW, or a combination of these. 

Some CWTs may be configured so that they can either (1) partially treat the waste stream to suit 

the needs of operators who reuse it or (2) use more advanced treatment (i.e., TDS removal) if the 

treated wastewater will be discharged. Generally, the former option is less costly for the CWT, and 

some facilities that have permits to discharge do not do so continuously, opting to direct as much of 

the wastewater as possible for reuse. There are also CWTs permitted to discharge that do not have 

TDS removal capabilities. However, these facilities must still meet TDS discharge limits specified by 

their state. Appendix F contains additional information on treatment configurations, including 

examples of processes at several facilities treating oil and gas wastewater. 

Facilities discharging treated wastewater to waters of the United States or POTWs are regulated 

under the Clean Water Act (CWA). For zero-discharge facilities, some states, including Pennsylvania 

and Texas, have adopted regulations to control permitting of these facilities or to encourage 

treatment and reuse. The PA DEP issues permits that allow zero-discharge CWTs to treat and 

release water back to oil and gas industries for reuse (see the Eureka Resources Facility in 

Williamsport, PA listed in Appendix Table F-6 as an example of a zero-discharge facility).1 

In developing this assessment, we looked at NPDES permit information for several CWTs in the 

eastern United States treating wastewater from the Marcellus region and one near the Fayetteville 

Shale in Arkansas. The facilities include those with and without TDS removal capabilities, and some 

are undergoing upgrades to implement TDS removal. Some of the permits reviewed for this 

assessment are current, and others are expired and may be in the process of renewal. The permits 

require monitoring (with or without limits) for a range of constituents that may include chloride, 

TDS, TSS, total strontium, total barium, oil and grease, heavy metals, 5-day biological oxygen 

demand (BOD5), and a range of organic compounds (e.g., phenol, cresol, BTEX, phthalates), with the 

specific constituents varying by permit. Sample types for the facilities are generally 24-hour 

composites. The newer permits set limits for several important constituents such as chloride, TDS, 

TSS, total barium, total strontium, oil and grease, and a number of heavy metals. Bromide is 

generally either not included or is required to be reported but with no limit specified. However, 

limits on TDS will reduce bromide concentrations. Some permits require monitoring for total 

radium, uranium, and gross alpha, but no limits are specified. Note that these facilities do not 

necessarily discharge consistently because treated wastewater can be sent for reuse. 

Although there are CWTs serving hydraulic fracturing operations throughout the country, the 

majority serve Marcellus Shale operations in Pennsylvania (Boschee, 2014). Of the 74 CWT facilities 

identified by the EPA (U.S. EPA, 2016d) as having accepted or having the ability to accept hydraulic 

fracturing wastewater (not counting facilities treating CBM wastewater), 40 are located in 

Pennsylvania (Table 8-5). Most are zero-discharge facilities, and many do not have treatment 

processes for TDS removal. Although several Pennsylvania facilities are permitted to discharge, 

Wunz (2015) found few that currently discharge (two CWTs in Pennsylvania, one in West Virginia, 

 

1 The facility is also permitted for indirect discharge to the Williamsport Sewer Authority.
Chapter 8 – Wastewater Disposal and Reuse

8-30 

Table 8-5. Number, by state, of CWT facilities that have accepted or plan to accept wastewater from unconventional oil and gas 

activities. 

Source: U.S. EPA (2016d). 

State Unconventional 

formation(s) served

Zero discharge CWT 

facilitiesa 

CWT facilities that discharge 

to a surface water or POTWa 

CWT facilities with multiple 

discharge optionsa 

Total known 

facilities

Non-TDS 

removal

TDS 

removal

Non-TDS 

removal

TDS 

removal

Non-TDS 

removal

TDS 

removal

AR Fayetteville 2 0 0 0 0 1 3

CO Niobrara, Piceance Basin 3 (1) 0 0 0 0 0 3

ND Bakken 0 1 (1) 0 0 0 0 1

OH Utica, Marcellus 10 (7) 0 1 0 0 0 11

OK Woodford 2 0 0 0 0 0 2

PA Utica, Marcellus 22 7(3) 8 0 0 3 (1) 40

TX Eagle Ford, Barnett, Granite Wash 1 3 0 0 0 0 4

WV Marcellus, Utica 4 (2) 0 0 0 1 1 6

WY Mesaverde and Lance 0 2 0 0 0 2 4

Total 44 13 9 0 1 7 74

a Information is current as of 2014; it is possible that since 2014, some listed CWT facilities have closed and/or new CWT facilities not listed have begun operation. The number

of facilities includes those that have not yet opened but are under construction, pending permit approval, or are in the planning stages. Facilities that are not accepting hydraulic 

fracturing wastewater but plan to accept it in the future are noted parenthetically and not included in the sum of total known facilities. Facilities handling CBM wastewater are 

not represented here.
Chapter 8 – Wastewater Disposal and Reuse

8-31 

and one in Ohio). According to EPA research (U.S. EPA, 2016d), the number of CWT facilities serving 

operators in the Marcellus and Utica Shales has increased since the mid-2000s, growing from 

roughly five in 2004 to over 40 in 2013. A similar trend has been noted for the Fayetteville Shale 

region in Arkansas, where there are fewer Class IID injection wells compared to the rest of the state 

(U.S. EPA, 2016d). 

In other regions, a small number of newer facilities have emerged in the last several years, most 

often with TDS removal capabilities. In Texas, for example, two zero-discharge facilities with TDS 

removal capabilities are available to treat wastewater from the Eagle Ford Shale (beginning in 2011 

and 2013), and one zero-discharge facility with TDS removal is located in the Barnett Shale region 

(operational since 2008). In Wyoming, there are four facilities in the region of the Mesaverde/Lance 

formations that started operating between 2006 and 2012. Two are zero-discharge facilities, and 

two have multiple discharge options; all are capable of TDS removal (U.S. EPA, 2016d). 

Few states maintain a comprehensive list of CWT facilities, and the count provided by the EPA (U.S. 

EPA, 2016d) includes facilities that do not currently but plan to accept wastewater from 

unconventional formations. Therefore, the data in Table 8-5 do not precisely reflect the number of 

facilities currently handling hydraulic fracturing wastewaters. Other sources indicate either use of, 

or interest in, development of treatment facilities in other regions such as the Barnett Shale region 

(Hayes and Severin, 2012b), the Fayetteville (Veil, 2011), and other areas in Texas and Wyoming 

(Boschee, 2014, 2012). In addition, news releases and company announcements indicate that other 

wastewater treatment facilities are being planned (Greenhunter, 2014; Geiver, 2013; Purestream, 

2013; Alanco, 2012; Sionix, 2011). 

Use of specific types of CWTs has and will continue to shift due to drivers such as availability and 

cost of other disposal options (e.g., disposal wells), operator demand for reuse and the associated 

quality needed, developments in treatment, treatment costs, and regulatory changes. Practices in 

Pennsylvania over the last several years provide such an example. Between 2010 and 2013, the 

percentage of Marcellus wastewater treated at CWTs dropped from 52% to 20% (Figure 8-4), and 

the percentage of wastewater reused on-site rose to 65%, reflecting a shift in practice among 

operators. Among the percentage of the wastewater sent to CWTs, the portion sent to zerodischarge facilities for subsequent reuse rose from 10% to 65%. This is consistent with an 

increased emphasis on reuse in Pennsylvania. (See Section 8.4.4 for a discussion on reuse as a 

waste management practice.) 

8.4.3.1 Relationship to Potable Surface Waters 

Figure 8-7 shows the relationship between Pennsylvania potable water supplies and the CWTs that 

lie in their upstream watersheds. These surface waters, including streams, rivers, and waterbodies 

(e.g., lakes and reservoirs) have been evaluated by the PA DEP for attainment of a designated use of 

potable water supply as per the CWA Section 305(b) reporting and Section 303(d) listing. Ninetyfour percent of the waterbodies and 98% of the streams and rivers were attaining their designated 

use in 2016. These stream segments may or may not currently have intakes for drinking water 

treatment plants. The map also shows the locations and types of CWTs that either currently accept 

unconventional oil and gas wastewater (as defined by PA DEP) or have accepted such wastewater 
Chapter 8 – Wastewater Disposal and Reuse

8-32 

Figure 8-7. Map showing Pennsylvania surface water designated as potable water supplies and upstream CWTs. 

Surface waters are colored orange to red to indicate the number of CWTs located in the upstream watershed. Blue surface waters have no upstream CWTs, 

and light gray lines show those not designated as potable water supplies. Symbols show the locations of CWTs that currently accept or have accepted 

unconventional oil and gas wastewater. Data sources: U.S. EPA (2016d), U.S. EPA (2016f), and PA DEP (2016b).
Chapter 8 – Wastewater Disposal and Reuse

8-33 

within approximately the last five years.1 CWTs represented include both dischargers (direct and 

indirect) as well as zero-discharge facilities. For some facilities, we were not able to determine if the 

facility was zero-discharge or if it has a NPDES permit. The surface waters have been color-coded to 

indicate the number of CWTs that are located upstream. Darker red indicates more CWTs located in 

the upstream watershed, while blue indicates no upstream CWTs. Softer grey lines show portions of 

the stream network not designated for potable water supply. The thickness of the line indicates the 

size of the stream or river, categorized by the “stream order” designation.

The map provides a general illustration of how CWTs are situated within catchments in

Pennsylvania, showing their spatial and general hydrologic relationships to streams that can serve

as potable water supplies. The map shows that a given stream or waterbody may have a number of

CWTs upstream, potentially contributing to combined impacts on surface water if there are spills or

inadequately treated discharges. Note that the upstream catchment areas are large for the major 

rivers. Therefore, some rivers, such as the Ohio or Susquehanna, have as many as 15 or 16 

upstream CWTs, although most are located far away. The map does not represent the effects of 

dilution on either discharges or spills; such an evaluation would necessitate currently unavailable 

data required to do a complete analysis of water quality. Note that many of the CWTs are zerodischarge facilities, and those that are permitted to discharge may do so intermittently. However, 

the storage and handling of wastewater at CWTs could impact nearby surface water through leaks 

and spills. 

To more completely place these facilities in a watershed context, other types of discharges that 

could be occurring upstream should be taken into consideration. Impacts from hydraulic fracturing 

wastewater may be more problematic if there are additional pollutant sources within the 

watershed, increasing the cumulative effects of discharges and spills. For example, an EPA source 

apportionment study (U.S. EPA, 2015o) evaluated the relative contributions of bromide, chloride, 

nitrate, and sulfate from CWTs primarily treating hydraulic fracturing wastewater to the Allegheny 

River Basin and to two downstream public water system intakes. The study considered that the 

Allegheny River and its tributaries also receive runoff and discharges from an array of sources that 

include acid mine drainage and mining operations, coal-fired electric power stations, industrial 

wastewater treatment plants, and POTWs. It was concluded that CWTs treating oil and gas 

wastewater and coal-fired power plants with flue gas desulfurization were the primary 

contributors of bromide and chloride at the intakes (see Section 8.5.1 for further discussion), while 

nitrate and sulfate contributions were from POTWs and Acid Mine Drainage (U.S. EPA, 2015o). 

8.4.3.2 Potential Impacts from CWTs

The potential impacts of managing hydraulic fracturing wastewater at CWTs depend on whether 

the CWT adequately treats for constituents of concern prior to discharge to surface water or a 

POTW, and whether treatment residuals are managed appropriately. Historically, CWTs have not 

1 The list of CWTs used to develop this map is based on best available data, including information in the technical 

development document supporting the new EPA unconventional oil and gas effluent limitation guidelines (U.S. EPA, 

2016d) as well as data from PA DEP waste records. This information was supplemented with other publicly available 

descriptions of the facilities. The information may, however, not be complete, and the symbols may not definitively reflect 

the discharge status of a facility.
Chapter 8 – Wastewater Disposal and Reuse

8-34 

included processes to treat for constituents that are difficult to remove, such as the high 

concentrations of TDS found in wastewater from unconventional reservoirs. As a result, impacts on 

drinking water resources have included increased suspended solids and chloride concentrations 

downstream of discharging facilities that were accepting hydraulic fracturing wastewater 

(Olmstead et al., 2013) and elevated bromide concentrations and radium concentrations in CWT 

effluent (Warner et al., 2013a); see Sections 8.5.1 and 8.5.2. In addition, spills and leaks can occur in 

pits or impoundments associated with the storage of treated wastewater at CWTs (impacts related 

to spills and leaks from pits and impoundments are discussed in Section 8.4.5). Wastewater being

transported by truck or pipeline to and from a CWT can also present a vulnerability for spills or 

leaks (Easton, 2014) (Chapter 7).

While selection of appropriate treatment processes is critical for CWTs that discharge to surface 

waters, there are also two important issues related to completeness of treatment that can have an 

impact. First, there may be unknown constituents in the wastewater. The effectiveness of treatment 

cannot be evaluated for constituents for which the wastewater has not been tested. This makes it 

challenging to know the degree to which effluent from a CWT is protective of public health. Second, 

even an efficient treatment process may not be able to reduce the concentrations of some 

constituents to levels that allow for discharge to a drinking water resource if influent 

concentrations are so high that they exceed the capabilities of the treatment technology(ies) to 

meet those discharge limits. For example, a facility described by Kennedy/Jenks Consultants (2002)

removed a high percentage of boron (88%), but the effluent concentration of 1.9 mg/L (average 

influent concentration of 16.5 mg/L) was not low enough to meet California’s action level of 1 

mg/L. Thus, the influent concentration must be considered together with removal efficiency to 

determine whether the effluent quality will meet the requirements dictated by end use or by 

regulations.

Relatively few studies describe the ability of individual treatment processes to remove constituents 

from hydraulic fracturing wastewater. For this assessment, simple estimated effluent 

concentrations were calculated for several combinations of unit treatment processes, wastewater 

constituents, and influent concentrations (details are given in Appendix Table F-3). The purpose of 

the analysis was to illustrate the relative capabilities of a number of treatment processes and not to 

represent a complete treatment system. As an example, the estimates suggest that if wastewater 

contains radium with a concentration in the thousands of pCi/L, a 95% removal rate with chemical 

precipitation may result in an effluent that exceeds 100 pCi/L. Treatment of the same wastewater 

via distillation or reverse osmosis could result in effluent concentrations in the tens of pCi/L. This 

analysis suggests that attention should be paid to the capabilities of a planned treatment system for 

the full range of anticipated wastewater compositions. 

To gain a better understanding of impacts, the USGS has conducted sampling for a wide array of 

water quality parameters in surface water and groundwater in the Monongahela River Basin in 

West Virginia to establish baseline water-quality conditions (Chambers et al., 2014). Future water 

quality sampling can be compared to this baseline to assess impacts from hydraulic fracturing 

activities. To address past impacts, Pennsylvania, having experienced water quality impacts on 

receiving streams due to discharges of high-TDS effluent modified their regulations to address 
Chapter 8 – Wastewater Disposal and Reuse

8-35 

these issues by setting water quality standards for CWT dischargers (Mauter and Palmer, 2014; 

Shaffer et al., 2013). (See Text Box 8-1.) 

8.4.4 Wastewater Reuse for Hydraulic Fracturing

The reuse of hydraulic fracturing wastewater for subsequent hydraulic fracturing operations has 

increased in some regions of the country in recent years (Boschee, 2014, 2012; Gregory et al., 2011; 

Rassenfoss, 2011).1 This practice is driven by factors that include cost (including treatment costs), 

the lack of availability of other management options (e.g., Class II disposal wells), and changes to 

state regulations (Boschee, 2014; Shaffer et al., 2013). Wastewater quality is a consideration; some 

constituents pose challenges for reuse and may necessitate treatment. For example, high 

concentrations of barium and sulfate can lead to scaling, and the presence of some constituents in 

wastewater can hinder crosslinking (Akob et al., 2016; Boschee, 2014). Hydraulic fracturing fluid 

formulations that can use high TDS waters (e.g., as high as 150,000 mg/L to over 300,000 mg/L) 

facilitate reuse with minimal treatment (Boschee, 2014; Mauter and Palmer, 2014). See Chapter 5 

for more information regarding the chemical composition of hydraulic fracturing fluids and 

Appendix F for more discussion of considerations for reuse. 

Reuse can be accomplished by blending either untreated or minimally treated hydraulic fracturing 

wastewater with fresh water to lower the TDS content (Boschee, 2014). Wastewater may be reused 

at a site with multiple wells, eliminating the need for transport to a CWT (Lester et al., 2015; Easton, 

2014). Alternatively, wastewater can be treated at a CWT and then taken by operators for mixing 

with other water sources for reuse (Easton, 2014). Flowback may be preferable to later-stage 

produced water for reuse because of its lower TDS concentration. Also, it is typically generated in 

larger quantities from a single location as opposed to water produced later on, which is generated 

in smaller volumes over time from many different locations (Barbot et al., 2013; Maloney and 

Yoxtheimer, 2012). Reuse can reduce the costs associated with water acquisition and produced 

water management. Such economic and logistical benefits can be expected to inform ongoing 

wastewater management decisions.

Costs can be the most significant driver for reuse. For example, the costs of transporting 

wastewater from the generating well to the treatment facility and then to the new well can be 

weighed against the costs for transport to alternative locations (e.g., a disposal well). Trucking large 

quantities of water can be relatively expensive—from $0.01 to $0.19 per gallon ($0.50 to $8.00 per 

bbl)—rendering on-site treatment technologies and reuse economically competitive in some 

settings (Dahm and Chapman, 2014; Guerra et al., 2011). Reuse rates may also be driven by 

wastewater production rates compared to the demand for reuse, with both production and demand 

increasing in a region if more wells go into production or decreasing as plays mature (Lutz et al., 

2013; Hayes and Severin, 2012b; Slutz et al., 2012). Other logistics to consider include proximity of 

the water sources for aggregation and sequencing of completion schedules (Mauter and Palmer, 

 

1 Reused hydraulic fracturing wastewater is discussed in Chapter 4 of this report (Water Acquisition) as well as in this 

chapter, though in a different context. The wastewater reuse rate described in this chapter is the amount or percentage of 

generated hydraulic fracturing wastewater that is managed through use in subsequent hydraulic fracturing operations. In 

contrast, Chapter 4 discusses reused wastewater as a source water and as one part of the base fluid for new fracturing 

fluid. 
Chapter 8 – Wastewater Disposal and Reuse

8-36 

2014). A small survey by Mauter and Palmer (2014) indicates that the scheduling of well 

completions is complex, requiring optimization of labor, contractual issues, equipment usage, and

water storage capacity among other factors. Boschee (2014) notes that in the Permian Basin, older

conventional wells are linked by pipelines to a central disposal facility, facilitating movement of

treated water to areas where it is needed for reuse. Companies drilling fewer wells or located in 

more remote areas may find reuse difficult because of challenges in consolidating wastewater from

their wells or accessing wastewater from centralized facilities.

Regulations may also encourage reuse. For example, in 2013, the Texas Railroad Commission 

adopted rules eliminating the need for a permit when operators reuse on their own lease or

transfer the fluids to another operator for reuse (Rushton and Castaneda, 2014). Any information

on wastewater management practices in Texas that becomes available for the years after 2013 will 

allow evaluation of whether reuse has in fact increased.

A summary of reuse practices throughout the United States is hampered by the limited amount of

data available for many regions of the country. However, current data indicate that extensive reuse

takes place in the Marcellus region. Several studies using data from PA DEP data show that total 

reuse rates of oil and gas wastewater in Pennsylvania have risen over the last several years to

between 85 and 90% (Table 8-6). This includes wastewater sent to CWTs to treat for reuse as well 

as reuse at the well sites without transfer to a CWT (labeled as “Reuse HF” in Figure 8-4). In

particular, reuse of Marcellus wastewater at well sites in Pennsylvania has risen from about 8% in 

the second half of 2010 to nearly 70% in the first half of 2014 (PA DEP, 2015a). Schmid and

Yoxtheimer (2015) report more recent data stating that in 2014, approximately 85% of Marcellus

hydraulic fracturing wastewater was reused. Of that amount, 78% occurred on-site, and 22% was

via CWTs.

Table 8-6. Estimated percentages of reuse of hydraulic fracturing wastewater.

Play or basin Source and year 2008 2009 2010 2011 2012 2013 2014

East Coasta

Marcellus, PA Rahm et al. (2013) 9 8 25 – 48 67 – 80

Marcellus, PA Ma et al. (2014) 15 - 20 90

Marcellus, PA Shaffer et al. 

(2013) 90

Marcellus, PA Schmid and 

Yoxtheimer (2015) 85

Marcellus, PA Hansen et al. 

(2013) 9 6 20 56

Marcellus, PA Maloney and 

Yoxtheimer (2012) 71.6

Marcellus, PA Tiemann et al. 

(2014) 72 87
Chapter 8 – Wastewater Disposal and Reuse

8-37 

Play or basin Source and year 2008 2009 2010 2011 2012 2013 2014

Marcellus, PA Rassenfoss (2011)

~67 

(general 

estimate) 

96 (one 

company)

Marcellus, PA Wendel (2011) 75-85 90

Marcellus, PA Lutz et al. (2013) 13 (prior to 2011) 56

Marcellus, PA 

(SW region) Rahm et al. (2013) ~10 ~15 ~25-45 ~70-80

Marcellus, PA 

(NE region) Rahm et al. (2013) 0 0 ~55-70 ~90-100

Marcellus, WV Hansen et al. 

(2013) 88 73 65 (partial year)

Gulf Coast and Midcontinent

Fayetteville Veil (2011)

20 (single 

company 

target)

Barnett

Rahm and Riha 

(2014), Nicot et al. 

(2012)

5 (general 

estimate –

appears 

to cover 

recent 

years)

Eagle Ford Nicot and Scanlon 

(2012) 0 

20 

(estimate 

based on 

interviews)

East Texas Nicot and Scanlon 

(2012) 5 

Haynesville Horner et al. 

(2014) 0 

Haynesville Rahm and Riha 

(2014)

5 (general 

estimate –

appears 

to cover 

recent 

years)
Chapter 8 – Wastewater Disposal and Reuse

8-38 

Play or basin Source and year 2008 2009 2010 2011 2012 2013 2014

West Coast and Upper Plains

DenverJulesburg 

(Weld County), 

CO

Sumi (2015) 54 (flowback only)

Bakken Horner et al. 

(2014) 0 

a Studies focusing on the Marcellus Shale use waste data reports from PA DEP. 

Reuse in the Marcellus region is higher in the northeastern part of Pennsylvania than in the 

southwestern portion where easier access to Class IID wells in Ohio makes disposal by injection 

more feasible (Rahm et al., 2013). Outside of the Marcellus region, reuse rates are lower. Ma et al. 

(2014) note that only a small amount of reuse is occurring in the Barnett Shale. Reuse has not yet 

been pursued aggressively in New Mexico or in the Bakken (North Dakota) (Horner et al., 2014; 

LeBas et al., 2013). Other sources, however, indicate growing interest in reuse, as evidenced in 

specialized conferences (e.g., “Produced Water Reuse Initiative 2014” on produced water reuse in 

Rocky Mountain oil and shale gas plays), and available state-developed information on reuse (e.g., 

fact sheet by the Colorado Oil and Gas Conservation Commission) (Colorado Division of Water 

Resources et al., 2014). 

If hydraulic fracturing activity slows in an area that is currently reusing wastewater, demand for 

the wastewater may decrease and wastewater management practices may shift. Analysis by Wunz 

(2015) and data in Figure 8-1 suggest a decline in wastewater production in Pennsylvania. Wunz 

(2015) also notes that in the future, there could be a trend of more wastewater coming from latestage produced water and less from flowback as more wells are in the production phase and fewer 

wells are being fractured. If the demand drops relative to production due to fewer wells being 

drilled and fractured, then the “excess” produced water will need to be managed by other means. 

Alternatives to reuse may include increased transport to disposal wells (e.g., those in Ohio), 

development of more disposal wells in Pennsylvania, or advanced treatment and discharge to 

surface water via CWTs that have TDS removal capabilities (SAFER PA, 2015; Wunz, 2015; Silva et 

al., 2014a). 

8.4.4.1 Potential Impacts from Reuse

For companies employing reuse as a wastewater management strategy, surface spills and leaks can

occur during wastewater transport to and from a treatment facility or from storage tanks/pits

located at the treatment facility or at the well site. Releases may be due to failed infrastructure such

as tank or pipe ruptures, from natural disasters such as floods or earthquakes, or incidents such as

overfills, improper operations, or vandalism (CCST, 2015a; NYSDEC, 2011). If the spill or leak is not 

contained or otherwise mitigated, these releases could reach groundwater or surface water 

(CCST, 2015a; NYSDEC, 2011). See Chapter 7 for more discussion on types of spills associated with 
Chapter 8 – Wastewater Disposal and Reuse

8-39 

hydraulic fracturing activities, including storage and transport. See Section 8.4.5 for discussion of 

storage pits and associated impacts on drinking water resources. 

With reuse there is the potential for accumulation of dissolved solids such as salts and TENORM in 

the wastewater over successive reuse cycles (see Section 7.3.4.6 and Section 8.5.2 for more 

information about TENORM). Because wastewater is often reused with minimal treatment, 

constituents resulting from time spent in the subsurface remain in the wastewater and can increase 

during additional hydraulic fracturing. This potentially concentrated wastewater can pose a bigger 

issue if a breach occurs in an on-site pit or tank storing this wastewater while awaiting reuse 

(Section 8.4.5; Chapter 7).

The issue of concentrating contaminants during reuse has not yet been quantitatively evaluated in 

the literature. Also, it is not known how much this problem would be mitigated due to the dilution 

of wastewater when reused as new fracturing fluid. Estimates of the percentages of reused 

wastewater in new fracturing fluids in Pennsylvania range from about 2% in 2009 to as much as 

22% in 2013 (SRBC, 2016; Schmid and Yoxtheimer, 2015) (Chapter 4). However, data from 

Pennsylvania’s TENORM study (PA DEP, 2015b) showed radium in some hydraulic fracturing fluids, 

presumably from a reused wastewater component. As reused wastewater continues to accumulate 

contaminants, the water will eventually need to be managed, either through treatment or injection. 

8.4.5 Storage and Disposal Pits and Impoundments

The use of pits and impoundments as part of a wastewater management strategy is a historic as 

well as current practice in the oil and gas industry. These structures are either used for temporary 

storage (on-site at oil and gas production wells or off-site at CWTs or disposal wells) or they are 

intended for permanent disposal (evaporation or percolation). There are a variety of terms to 

describe these structures depending upon their use (Richardson et al., 2013); “pits,” 

“impoundments,” and “reserve pits” are some of the more common terms associated with 

wastewater management. The terms “impoundment” or “pond” are often used to refer to large area 

holding structures and are also used by some states for specific applications such as holding 

“freshwater” for fracturing fluid formulation (Quaranta et al., 2012). Definitions and terminology 

are not standardized and vary from state to state (Richardson et al., 2013). For the purposes of this 

section, the nomenclature will defer to the term used by the original author/regulating authority.

States govern the use and permitting of pits under their jurisdiction. Regulations vary from state to 

state regarding the circumstances in which pits can be used (e.g., chemical composition of the fluid),

how they should be constructed, and whether they must be lined (e.g., proximity to drinking water

resources and/or chemical composition of the fluid) (Richardson et al., 2013). Most states restrict

the use of wastewater pits in environmentally sensitive areas. To avoid contamination events, some

states are moving toward requiring closed loop systems (i.e., tanks) or injection wells rather than 

using pits for hydraulic fracturing wastewater storage. For example, Pennsylvania has modified

their regulations (published October 8, 2016) to ban the use of pits for temporary storage of

unconventional (as defined by PA DEP) wastewaters; many operators have already moved to 

closed-loop systems (PA DEP, 2016a). This development is particularly notable because of 
Chapter 8 – Wastewater Disposal and Reuse

8-40 

Pennsylvania’s heavy reliance on reuse for wastewater management, necessitating both on-site and 

off-site storage.

8.4.5.1 Locations and Numbers of Pits

The locations and number of existing pits (both for storage and for disposal) are not well 

documented in all states, and in the data found, pits associated with hydraulic fracturing operations 

were not specifically identified. With respect to larger pits for storage or disposal of wastewater, 

some states (e.g., Utah and Oklahoma) provide locational data on their websites. In 2016, the state 

of California began posting the number of active and inactive oil field produced water “ponds” 

(defined as unlined surface impoundments), both permitted and unpermitted, on their website. The 

July 2016 posting showed that 64% (682) of the 1,065 unlined ponds identified in the Central 

Valley and Central Coast of California were active. Of the active ponds, 21% (144) were not 

permitted (CA Water Board, 2016). Active ponds are primarily found in the southern San Joaquin 

Valley (CCST, 2015a). The EPA Region 8 conducted a survey of pits associated with oil and gas 

operations in Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming from 1996 

through 2002. Results indicated there were approximately 28,000 pits at that time (U.S. EPA, 

2003b). 

In the absence of an inventory of pits in Pennsylvania, the organization SkyTruth led an effort using 

volunteers to produce a map of pits believed to be associated with drilling and hydraulic fracturing 

the Marcellus Shale (Manthos, 2014). The identification of pits was based on USDA aerial imagery

taken in 2005, 2008, 2010, and 2013. SkyTruth acknowledges the uncertainties associated with 

identifying pits based on aerial images and volunteer labor. They have described their methodology 

as including multiple reviewers and QA/QC procedures. The study cannot differentiate ponds for 

drilling fluids and fracturing fluids from those for wastewater. Their preliminary findings indicate 

that the estimated number of ponds rose from 11 in 2005 to 529 in 2013, with the structures 

themselves increasing in size from a median size of 3,713 ft2 (345 m2) in 2005 to 66,844 ft2 (6,210 

m2 in 2013. SkyTruth also notes that impoundments are not permanent and that of 581 ponds 

delineated in 2010, only 116 of them were found in the images from 2013. 

Evaporation ponds, referred to as Commercial Oil Field Waste Disposal Facilities (COWDFs), are a

waste management strategy most commonly used in the western states such as Utah, Wyoming,

and Colorado (USFWS, 2014). According to a 2016 list of approved COWDFs posted by the Utah

Division of Oil, Gas, and Mining (Utah Division of Oil, 2016), 20 facilities in Utah are approved to

accept produced water. All are in the eastern part of the state where the Uinta and Paradox basins

are found (unconventional shale formations). The Wyoming Department of Environmental Quality 

website, accessed in 2016, lists 35 active COWDFs (WDEQ, 2016b). The increase in hydraulic 

fracturing activity in Wyoming has resulted in significant increase in wastewater disposed of in

COWDFs (USFWS, 2014). Data from the Colorado Oil & Gas Conservation Commission includes

eight active evaporation pits, five of which are unlined (COGCC, 2016). Ninety-five other active pits

are listed in Colorado, with descriptors such as “production,” “multi-well pit,” “skim,” or “produced 

water.” Seventy-one of these are unlined, and 22 have synthetic liners. Eleven pits are located in 
Chapter 8 – Wastewater Disposal and Reuse

8-41 

Garfield County, where there is hydraulic fracturing activity. The Colorado data do not distinguish

pits at centralized commercial facilities from on-site pits.

8.4.5.2 Unlined Storage Pits and Percolation Pits

Whether an unlined pit is designed and intended to percolate wastewater into the ground for

disposal or if it is built for storage, it provides a pathway for wastewater to infiltrate into the 

subsurface and potentially reach groundwater. Such pits have been used historically for

conventional oil and gas wastewater. More recently, they have received wastewater in areas where

hydraulic fracturing takes place. States such as Montana and Wyoming allow unlined pits to be used

for storage if the quality of the waste fluid meets specified limits and the pit is not in close

proximity to environmentally sensitive areas such as drinking water resources, wetlands, and 

floodplains (Kuwayama et al., 2015b; Richardson et al., 2013). 

In the past, several states have allowed unlined pits designed to dispose of wastewater via

percolation into the subsurface. For example, until July 2015, percolation pits were permitted for

wastewaters from hydraulically fractured wells in the Central Valley Region in California (Grinberg,

2016). The California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources

(DOGGR) listed “evaporation-percolation” as the management method for almost 60% (190 million

gal) of the wastewater generated via well stimulation in Kern County between 2011 and 2014

(CCST, 2015a). However, according to DOGGR’s 2015 report addressing well stimulation activities

in Kern County from January 1, 2014 through September 30, 2015, evaporation/percolation was

not employed as a disposal option during that period (98% of the produced water was disposed of

via operator-owned Class II injection wells, 1.75% was disposed of via commercial Class II injection

wells, and 0.16% was reused).

While the practice of disposal via percolation pits has been discontinued in most states, as of July

2016, Wyoming’s regulations still allow the use of percolation for disposing produced water

specific to CBM operations in the Powder River Basin. To be permitted, the operator must

demonstrate that the disposed fluid will comply with water quality standards of the Department of

Environmental Quality (WYOGCC, 2015). 

8.4.5.3 Evaporation Ponds

Evaporation is a simple water management strategy involving transporting wastewater to a pond

or pit with a large surface area and allowing passive evaporation of the water from the surface 

(NETL, 2014; Clark and Veil, 2009). As discussed above, this disposal option, often referred to as a

COWDF, is practical for drier climates of the western United States. Evaporation ponds have been

used for oil and gas wastewater disposal in Montana, Colorado, Utah, New Mexico, and Wyoming 

(Veil et al, 2004). However, New Mexico no longer allows the use of pits for disposal (NM EMNRD 

OCD, 2013), and in Montana, evaporation ponds are no longer allowed because they do not put 

extracted water to a beneficial use (NRC, 2010). Figure 8-8 shows an example of a lined evaporation 

pit in Montana (DOE, 2006). 
Chapter 8 – Wastewater Disposal and Reuse

8-42 

Figure 8-8. Lined evaporation pit in the Battle Creek Field (Montana). 

Source: DOE (2006). Reproduced with permission from ALL Consulting.

As the water component of the wastewater is subject to evaporation, the fluid remaining in the 

pond becomes concentrated, and a sludge layer is formed. Remaining residual brines in the pond 

can be collected and disposed of via an underground injection well, and the solids can be taken to a 

landfill (see Section 8.4.7 for more details). In cold, dry climates, a freeze-thaw evaporation method 

has also been used to purify water from oil and gas wastewater (Boysen et al., 1999). 

Nowak and Bradish (2010) describe the design, construction, and operation of two large 

commercial evaporation facilities in Southern Cross, Wyoming and Danish Flats, Utah. Each facility 

includes 14,000 gal (53,000 L) three-stage concrete receiving tanks, a sludge pond, and a series of 

five-acre (20,234 m2) evaporation ponds connected by gravity or force-main underground piping. 

The Wyoming facility, which opened in 2008, consists of two ponds with a total capacity of 

approximately 84 million gal (2 million bbls or 318 million L). The Utah facility, open since 2009, 

consists of 13 ponds with a total capacity of approximately 218.4 million gal (5.2 million bbls or 

826.6 million L). Each facility receives 0.42 to 1.47 million gal (10,000 to 35,000 bbls; 1.59 million 

to 5.56 million L) of wastewater per day from oil and gas production companies in the area. 

Evaporation ponds or pits are subject to state regulatory agency approval and must meet state 

standards for water quality and quantity (Boysen et al., 2002). 

8.4.5.4 Impacts and Potential Impacts from Pits and Impoundments

Pits containing hydraulic fracturing wastewater have the potential to impact drinking water 

resources if spills and overflows cause runoff to surface water or if wastewater percolates through 

the soil and reaches groundwater. In addition to contaminants in the wastewater itself, wastewater 
Chapter 8 – Wastewater Disposal and Reuse

8-43 

that reaches groundwater may mobilize constituents in pit bottoms or soils, and it may also reach 

hydrologically connected surface water. These impacts are amplified with increasing 

pit/impoundment size (Quaranta et al., 2012). Percolation may be accidental (through tears or 

improper installation of liner) or by design in unlined pits (Sumi, 2004). 

Compromised pit liners can result in leaks, and extreme weather events, such as floods, can cause 

pits to overflow. An analysis of three state databases (New Mexico, Oklahoma, and Colorado) where 

pits and tanks have been used for storage of hydraulic fracturing wastewater found that for pits, the 

most common causes of spills were from overflows and liner malfunctions (Kuwayama et al., 

2015b). For instance, of the 106 pit-related spills reported in New Mexico between 2000 and 2014, 

33% were due to overflows and 26% were caused by liner malfunctions. Of the 62 tank spills 

reported, 44% were due to leaks, and 27% were related to overfilling (Kuwayama et al., 2015b). 

The types of constituents in pits that may be of concern from such events include VOCs, metals, 

TDS, oil, and TENORM (Kuwayama et al., 2015b). 

Operational factors also influence potential impacts from pits and impoundments. These can 

include water level management (influent, seepage, spillage), the length of time water is stored in 

the pit/impoundment, the composition of the water, the local climate (rainfall and/or evaporation),

and the transmission method (piped or delivered in an open channel) (NRC, 2010). 

Construction and Capacity Issues

Construction requirements typically include specifications for features that can reduce the potential

for impacts on groundwater or surface water. These can include liner specifications, depth to

groundwater, secondary containment, setback requirements, freeboard, leak detection, and water

quality monitoring (Kuwayama et al., 2015b).1,2 For example, in a 2012 review of 19 states with 

shale gas development or potential for shale gas development, many states had setback 

requirements for pits in sensitive areas including surface water, wetlands, and floodplains. As of 

December 2015, however, 12 of the 19 states surveyed did not include setback requirements in 

their regulations. Many states did address the vertical separation of pits from the water table (e.g., 

20 in (0.5 m) to seasonal high water table in PA; 10 ft (3 m) in WY; 50 ft (15 m) in NM) (Kuwayama 

et al., 2015b). 

Despite construction standards, impacts on groundwater or surface water due to overflows, liner 

breaches, and other construction issues have been documented. In 2007 in Knox County, Kentucky, 

retention pits holding hydraulic fracturing flowback fluids overflowed into Acorn Fork Creek during 

the development of four natural gas wells (CCST, 2015a; Papoulias and Velasco, 2013). The incident 

caused the pH of the creek to drop from 7.5 to 5.6 and the conductivity to increase from 200 to 

35,000 μS/cm. In addition, organics and metals including iron and aluminum formed precipitates in 

the stream. Fish and aquatic invertebrates were killed or distressed in the area of the stream 

affected by the release (Papoulias and Velasco, 2013). 

1 Setback is the distance between the pit and a stream, lake, building, or other feature or structure that needs protection.

2 Freeboard is the vertical distance between the level of the water in an impoundment and the overflow elevation (an 

outfall or the lowest part of the berm).
Chapter 8 – Wastewater Disposal and Reuse

8-44 

Similarly, in 2009, Marcellus wastewater stored in an impoundment from a hydraulic fracturing 

operation in Washington County, Pennsylvania overflowed the bank of the impoundment and 

reached surface water (a tributary of Dunkle Run) (CCST, 2015a). NRC (2010) reported continuous 

overfilling of an impoundment in the Powder River Basin (Wyoming) with CBM produced water, 

resulting in significant erosion of a seasonal water channel. The CBM operator was required 

through litigation to manage flows to the impoundment to prevent overflows. The literature did not 

report specific impacts on groundwater or surface water from the Pennsylvania or Wyoming 

incidents.

In Pennsylvania in 2010, pit liner failure was reported to have impacted groundwater through 

leakage of Marcellus wastewater from six impoundments (Colaneri, 2014). Ziemkiewicz et al. 

(2014) note that a study of 15 pits and impoundments in West Virginia found that slope stability 

and liner deficiencies were common problems. Construction quality control and quality assurance 

were often inadequate; the authors found a lack of field compaction testing, use of improper soil 

types, excessive slope lengths, buried debris, and insufficient erosion control, although no breaches 

were reported. A statistical analysis of oil and gas violations in Pennsylvania found that structurally 

unsound impoundments or inadequate freeboard were the second most frequent type of violation, 

with 439 instances in the period from 2008 to 2010 (Olawoyin et al., 2013). 

Unlined Pits

Impacts on groundwater from historic and current uses of unlined pits in the oil and gas industry 

have been documented. In a review of records spanning 25 years (1983 – 2007), 63 incidents of 

private water supply contamination from the infiltration of saline fluids from unlined or 

inadequately constructed reserve pits were identified in Ohio (Kell, 2011). The same study (Kell, 

2011) identified 57 legacy (pre-1984) incidents in Texas involving groundwater contamination 

from unlined produced water disposal pits. Such pits were phased out in Texas by 1984, prompting 

a move towards disposal of oil and gas wastewater in disposal wells. 

Kern County, California has experienced impacts on groundwater associated with unlined 

percolation pits. A 2014 study notes that there are hundreds of pits across Kern County and 

elsewhere in the state, stretching state resources for regulatory oversight (Grinberg, 2014). Past 

sampling of water in percolation pits has shown exceedances of California’s Tulare Lake Basin Plan

(Basin Plan), which specifies maximum levels permitted for discharges of oil field well wastewater 

to unlined ponds overlying groundwater (Grinberg, 2014).1 For example, the McKittrick 1 and 1-3 

pits are large percolation pits in Kern County near oil fields where most of the hydraulic fracturing 

in California takes place (Grinberg, 2014). The pits are situated close to a number of important 

resources. They are located within a few miles of the Kern River Flood Channel, the California State 

Water Project, farmland, and are in an area of high quality groundwater (Grinberg, 2014). Sampling 

of fluids in the pits dating back to 1997 showed consistent exceedances of Tulare Basin Plan 

standards for TDS, chlorides, and boron. Sampling also revealed the presence of BTEX, gasoline 

range organics (GRO), and diesel range organics (DRO) (MTA, 2014). Sampling of three monitoring 

 

1 The Basin Plan sets limits for salinity (1,000 μmhos/cm measured as electrical conductivity), chloride (175 mg/L), and 

boron (1 mg/L) (California Regional Water Quality Control Board Central Valley Region, 2015). 
Chapter 8 – Wastewater Disposal and Reuse

8-45 

wells indicated that in 2004, a plume had migrated at least 4,000 ft (1,000 m) from the pits and was 

still detected in test wells in 2013. As of July 1, 2015, California’s Code of Regulations includes a 

provision that no longer allows the use of pits, including percolation pits, for fluids produced from 

stimulated wells (Grinberg, 2016). 

Unlined pits that were used from the 1960s until the mid-1990s for disposal of drilling muds and 

flowback and produced waters associated with hydraulic fracturing operations have been linked to

groundwater contamination in Pavillion, Wyoming (Digiulio and Jackson, 2016; AME, 2015). A 

report by the Wyoming Oil and Gas Conservation Commission (WYOGCC) (WYOGCC, 2014a) 

summarizes site investigations and reclamation activities conducted by WOGCC, the Wyoming

Department of Environmental Quality (WDEQ), and Encana Oil and Gas for pits in the Pavillion Well

Field. The report includes information on samples collected between 2006 and 2013 from shallow

groundwater in the vicinity of the pits. Some sites had detections for one or more of the following

contaminants: GRO, DRO, BTEX, and/or naphthalene. Of the shallow groundwater sites with

detections, some were associated with pits located within one-quarter mile of a domestic well. One

of these sites exceeded clean-up levels established by the WDEQ Voluntary Remediation Program 

for DRO (13,000 μg/L) and benzene (110 μg/L).1 The report noted that there was insufficient

evidence to determine whether or not drinking water supply wells in the vicinity of the pits were 

contaminated by disposal of hydraulic fracturing wastewater in those pits (WYOGCC, 2014a). 

Other examples in the literature include the detection of VOCs in groundwater downgradient of an 

unlined pit containing oil and gas wastewater near the Duncan Oil Field in New Mexico (Sumi, 

2004) (Section 8.5). Groundwater impacts downgradient of an unlined pit in Oklahoma included 

high salinity (3500-25,600 mg/L) and the presence of VOCs (Kharaka et al., 2002). Neither New 

Mexico nor Oklahoma currently allows unlined pits for disposal or storage (OCC OGCD, 2015; NM 

EMNRD OCD, 2013). 

Mobilization and Transport of Constituents

Groundwater impacts may result not just from constituents in the wastewater but also from 

mobilization of existing constituents in the soil or sediment. A CBM produced water impoundment 

in the Powder River Basin of Wyoming was studied for its impact on groundwater (Healy et al., 

2011; Healy et al., 2008). Infiltration of water from the impoundment was found to create a perched 

water mound in the unsaturated zone above bedrock in a location with historically little recharge. 

Elevated concentrations of TDS, chloride, nitrate, and selenium were found at the site, with one 

lysimeter sample exceeding 100,000 mg/L of TDS (Healy et al., 2008). Most of the solutes found in 

the groundwater mound did not originate with the CBM produced water, but rather were the 

consequence of dissolution of previously existing salts and minerals (Healy et al., 2011). 

Generally, the deeper that wastewater can move into an aquifer, as impacted by the volume and 

timing of the release, the longer the duration of contamination (Whittemore, 2007). Kharaka et al. 

(2007) reported on studies at a site in Oklahoma with one abandoned and two active unlined pits. 

1 WDEQ cleanup levels are derived from a combination of promulgated levels (MCL, state-assigned water quality 

standards) and risk-based cleanup level concentrations (WDEQ, 2016a). 
Chapter 8 – Wastewater Disposal and Reuse

8-46 

Produced water from these pits penetrated 10 to 23 ft (3 to 7 m) thick shale and siltstone units, 

creating three plumes of high-salinity water (5,000 to 30,000 mg/L TDS). The impact of these 

plumes on the receiving water body (Skiatook Lake) was judged to be minimal, although the 

estimate was based on a number of notably uncertain transport quantities (Otton et al., 2007). 

Vadose (unsaturated) zone transport was illustrated at a site in Oklahoma where two abandoned 

pits were major sources for releases of produced water and oil. Saline water from the pits flowed 

through thin soils and readily percolated into underlying permeable bedrock. Deeper, lesspermeable bedrock was contaminated by salt water later in the history of the site, presumably due 

to fractures. The mechanisms proposed were vertical movement through permeable sand bodies, 

lateral movement along shale fractures, and possibly increased clay permeability due to the 

presence of highly saline water (Otton et al., 2007). 

Summary

Collectively, the above examples show that regardless of the purpose of pits (storage or disposal), 

they present a potential pathway for wastewater constituents to impact groundwater or surface 

water. Good construction standards and practices, including liners, adequate freeboard, and 

setbacks, are important for minimizing potential impacts on both surface water and groundwater. 

Proper monitoring and maintenance (e.g., avoiding overfilling, maintaining the integrity of liners 

and berms) are also important for protecting surface water and groundwater. Unlined pits, in 

particular, can lead to groundwater contamination. This can be long-lasting, as evidenced by legacy 

impacts from older pits. Most states have phased out unlined disposal pits and unlined storage pits, 

but if such pits are still in use, they can provide ongoing potential sources of groundwater 

contamination (CCST, 2015a; Grinberg, 2014). 

8.4.6 Other Management Practices and Issues 

Additional strategies for wastewater management in some states include directly discharging to 

surface waters and land application. In particular, wastewater from CBM fracturing and production 

generally has lower TDS concentrations than wastewater from other types of unconventional 

formations and more readily lends itself to other uses. 

8.4.6.1 Land Application and Road Spreading 

Road spreading has been used as a disposal option for high-TDS wastewaters (brines) from 

conventional oil and gas production. Road spreading can be done for dust control and de-icing. 

Although recent data are not available, an American Petroleum Institute (API) survey estimated 

that approximately 75.6 million gal (1.8 million bbls or 286.2 million L) of wastewater was used for 

road spreading in 1995 (API, 2000). The API estimate does not specifically identify hydraulic 

fracturing wastewater. There is no current nationwide estimate of the extent of road spreading 

using hydraulic fracturing wastewater. 

Road spreading with hydraulic fracturing wastewater is regulated primarily at the state level 

(Hammer and VanBriesen, 2012) and is prohibited in some states. For example, with annual 

approval of a plan to minimize the potential for pollution, PA DEP allows spreading of brines from 
Chapter 8 – Wastewater Disposal and Reuse

8-47 

conventional (as defined by PA DEP) wells for dust control and road stabilization. Hydraulic 

fracturing flowback, however, cannot be used for dust control and road stabilization (PA DEP, 

2011b). In West Virginia, use of gas well brines for roadway de-icing is allowed per a 2011 

memorandum of agreement between the West Virginia Division of Highways and the West Virginia 

Department of Environmental Protection, but the use of “hydraulic fracturing return fluids” is not 

permitted (Tiemann et al., 2014; West Virginia DEP, 2011). 

Concerns about road application center on contaminants such as barium, strontium, and radium. A 

report from PA DEP analyzed several commercial rock salt samples and compared results with 

contaminants found in Marcellus Shale flowback samples. The results noted elevated barium, 

strontium, and radionuclide levels in Marcellus Shale brines compared with commercial rock salt 

(Titler and Curry, 2011). Another study found increases in metals (radium, strontium, calcium, and 

sodium) in soils ranging from 1.2 to 6.2 times the original concentrations (for radium and sodium, 

respectively), attributed to road spreading of wastewater from conventional oil and gas wells for 

de-icing (Skalak et al., 2014). 

Potential impacts on drinking water resources from road spreading have been noted by Tiemann et 

al. (2014) and Hammer and VanBriesen (2012). These include potential effects of runoff on surface 

water and migration of brines to groundwater. Snowmelt can carry salts and other chemicals from 

the application site, and transport can increase if application rates are high or rain occurs soon after 

application (Hammer and VanBriesen, 2012). Research on the impacts of conventional road salt 

application has documented long-term salinization of both surface water and groundwater in the 

northern United States (Kelly, 2008; Kaushal et al., 2005). When conventional oil field brine was 

used in a controlled road spreading experiment, elevated chloride concentrations were detected in 

shallow groundwater (Bair and Digel, 1990). The amount of salt attributable to road application of

hydraulic fracturing wastewaters has not been quantified. 

To evaluate land application of solid wastes from oil and gas production, a laboratory study 

mimicking land spreading of conventional oilfield scales and sludges indicated that 20% of the 

radium in barite sulfate scales was released by microbial processes during incubation with soil 

(Matthews et al., 2006; Swann et al., 2004). Although the radium was then complexed with the soil, 

it would be more mobile and more bioavailable than when it was associated with the barite. 

Overall, potential effects on drinking water resources from land spreading are not well understood, 

including the amounts of hydraulic fracturing wastes that are managed by land spreading. 

8.4.6.2 Management of Coalbed Methane Wastewater

Many, but not all, CBM wells are hydraulically fractured to enhance recovery, using fluids that range 

from water alone to more complex gel formulations with proppant (e.g., Engle et al., 2011; 

McCartney, 2011; NRC, 2010; Halliburton, 2008; U.S. EPA, 2004a). The literature indicates that 

hydraulic fracturing of CBM formations is being conducted in the San Juan, Raton, Piceance, and 

Uinta Basins, among others. Literature such as NRC (2010) notes that hydraulic fracturing may not 

be common in the Powder River Basin. Additionally, when CBM well stimulation does take place, it 

can be accomplished using very simple hydraulic fracturing fluid formulations (Chapter 3). 
Chapter 8 – Wastewater Disposal and Reuse

8-48 

Wastewater from CBM wells can be managed like other hydraulic fracturing wastewater discussed 

above. However, the wastewater from CBM wells can also be of higher average quality (typically 

lower TDS content) than wastewater from other hydraulically fractured wells. The lower TDS 

content makes it more suitable for certain management practices and uses. A number of 

management strategies have been proposed or implemented, with varying degrees of treatment 

required depending on the quality of the wastewater and the intended use (Hulme, 2005; DOE, 

2003, 2002). Although specific volumes managed through the practices discussed below are not 

well documented, qualitative information and considerations for feasibility are available and 

presented. The discussion below covers both dilute and higher-TDS wastewater from CBM 

formations. 

The quality of CBM wastewater plays a large role in how the wastewater is managed. The TDS 

content can range from an average of nearly 1,000 mg/L in the Powder River Basin to an average of 

about 14,000 mg/L (and as high as approximately 62,000 mg/L) in the Black Warrior Basin 

(Appendix Table E-3). Data sources from about 2002 through 2008 indicate that operators in some

basins such as the San Juan, Uinta, and Piceance, and Raton (in New Mexico), where TDS is typically 

higher compared to other basins (e.g., Powder River), manage most wastewater by injection into 

disposal wells (NRC, 2010; U.S. EPA, 2010a). 

Discharge to rivers and streams, a management option governed by the CWA, may be permitted in 

cases where wastewater is of high quality.1 To be discharged, the wastewater must meet 

technology-based effluent limitations established by the permitting authority on a case-by-case 

“best professional judgment” basis as well as any more stringent limitations necessary to meet 

applicable water quality standards. For example, as a means of protecting high-quality waters of the 

state, the Montana Supreme Court ruled in 2010 that treatment is required for all CBM produced 

water prior to discharge to surface water (NRC, 2010). 

A 2008 EPA survey of CBM operators found that of the projects represented in the results, direct 

discharge to surface water was by far most prevalent in the Powder River Basin but was also 

reported as a management practice in the Green River, Raton, Black Warrior, Cahaba, Illinois, and 

Appalachian basins (U.S. EPA, 2013e, 2010a).2 Discharges to surface water can provide habitat 

maintenance, restoration of wildlife-waterfowl fishery habitat, and flow augmentation to benefit

downstream water users. However, hydrologic changes from such discharges could also have 

unanticipated effects on ecosystems previously adapted to intermittent streamflow. 

Some CBM wastewater can be put to agricultural use, including livestock and wildlife watering, and 

crop irrigation. Livestock watering with CBM wastewater can be done using on-channel or offchannel impoundments, and irrigation is an area of active research (e.g., Engle et al., 2011; NRC, 

2010). However, wastewater from some higher-salinity CBM basins (e.g., San Juan, Uinta, and 

Piceance) would need blending or treatment before such uses. Irrigation with treated CBM 

 

1 Although discharge to rivers and streams is generally prohibited under the EPA’s oil and gas ELGs, the ELGs do not apply 

to CBM. 

2 These reports did not describe certain non-discharging wastewaters management strategies in basins with few 

operators in order to preserve CBI. The reports also do not provide information on hydraulic fracturing activities in the 

basins. Not also that results are presented by numbers of projects, which may vary in the number of wells they contain. 
Chapter 8 – Wastewater Disposal and Reuse

8-49 

wastewater would be most suitable on coarse-textured soils for cultivation of salt-tolerant crops 

(DOE, 2003). NRC (2010) remarks that “use of CBM produced water for irrigation appears practical 

and sustainable,” provided that appropriate measures are taken such as selective application, 

dilution or blending, appropriate timing, and rehabilitation of soils. 

Although CBM wastewater is generally lower in TDS than wastewater associated with shale gas 

development, it can still have higher TDS concentrations than stream water. This poses concerns 

regarding the sodium adsorption ratio (SAR) for agricultural soils. A USGS study performed trend 

analysis of water quality at sampling sites in the Tongue and Powder River watersheds (Powder 

River Basin) (Sando et al., 2014). One of the study objectives was to determine possible effects of 

CBM produced water particularly in areas where the water was discharged to impoundments or 

upper reaches of in-stream channels for infiltration. Trend analysis showed potential effects of CBM 

production on downstream water quality (increases in sodium, alkalinity, and SAR) in the mainstem Powder River but found mixed results at the Tongue River sites (some appeared to be 

impacted by CBM activities while others did not) (Sando et al., 2014). 

Sando et al. (2014) found that CBM pumping rates (i.e., discharge of produced water) were high 

relative to streamflow in the Powder River Basin. For the three main-stem Powder River sites, the 

CBM pumping rates were 26-34% of the 2001-2010 median streamflows. For one site in the Little 

Powder River watershed, the CBM pumping rate was 360% of 2001-2010 median streamflow. This 

underscores that in arid climates in the western United States, permitted discharges from CBM 

activities (whether hydraulically fractured or not) at a particular site may be large relative to the 

size of the receiving water and may sometimes dominate flows.

As noted above, a degree of treatment is needed (or required) for some uses. Plumlee et al. (2014)

examined the feasibility, treatment requirements, and potential costs of several hypothetical uses 

for CBM wastewater. In several cases, costs for these uses were projected to be comparable to or 

less than estimated disposal costs. In one case study, use of CBM wastewater for streamflow 

augmentation or crop irrigation could potentially cost between $0.26 and $0.27 per bbl. For 

comparison, reported disposal costs in 2000-2001 ranged from $0.01 per bbl for a pipeline 

collection system with impoundment to $2.00 per bbl for hauling to disposal or treatment. The 

2010 NRC report (NRC, 2010) noted that 15 to 18% of CBM produced water in the Powder River 

Basin was being treated to reduce SAR in order to satisfy NPDES permits for discharge.1 If 

wastewater is treated to address SAR, reported costs are approximately $0.12 to $0.60/bbl (NRC, 

2010). 

The applicability of particular uses may be limited by ecological and regulatory considerations as 

well as the irregular nature of CBM wastewater production (voluminous at first, and then declining 

and halting after a period of years). Legal issues, including overlapping jurisdictions at the state 

level and senior water rights claims in over-appropriated basins (in western states) can also 

determine the use of CBM wastewater (Wolfe and Graham, 2002). 

 

1 SAR is the relative proportion of sodium to other cations in water. It is also an indication of risk to soil from alkalinity. 

The higher the SAR, the less suitable the water is for irrigation, and long-term use can damage soil structure.
Chapter 8 – Wastewater Disposal and Reuse

8-50 

8.4.6.3 Other Documented Uses of Hydraulic Fracturing Wastewater

Uses of wastewater from shales or other hydraulically fractured formations face many of the same 

possibilities and limitations as those associated with wastewater from CBM operations. The biggest 

difference is in the quality of the water. Wastewaters vary widely in water quality, with TDS values 

from shale and tight sand formations ranging from less than 1,000 mg/L TDS to hundreds of 

thousands of mg/L TDS (DOE, 2006) (Chapter 7). Wastewaters on the lower end of the TDS 

spectrum could be reused in many of the same ways as CBM wastewater, depending on the 

concentrations of potentially harmful constituents and applicable federal, state, and local 

regulations. High TDS wastewaters have more limited uses, and pre-treatment may be necessary 

(Shaffer et al., 2013; Guerra et al., 2011; DOE, 2006). Agricultural and wildlife uses are subject to the 

produced water daily effluent discharge limit of 35 mg/l for oil and grease.1

Potential uses for wastewater in the western United States include livestock watering, irrigation, 

streamflow supplementation, fire protection, road spreading, and industrial uses, with each having 

their own water quality requirements and applicability (Guerra et al., 2011). Guerra et al. (2011)

summarized the least conservative TDS standards for five possible uses in the western United 

States that include 500 mg/L for drinking water (the drinking water secondary maximum 

contaminant level (SMCL)), 625 mg/L for groundwater recharge, 1,000 mg/L for surface water 

discharge, 1,920 mg/L for irrigation, and 10,000 mg/L for livestock watering. The authors 

estimated that wastewater from 88% of unconventional wells in the western United States could be 

used for livestock watering without TDS removal based on a maximum TDS concentration of 10,000 

mg/L. However, wastewater from only 10% of unconventional wells could be used for surface 

discharge without treatment for TDS based on the least conservative standard among the western 

states of 1,000 mg/L TDS (Guerra et al., 2011). Guerra et al. (2011) indicate that in several basins in 

the western United States (e.g., Wind River, Green River, and Powder River), wastewater from 50% 

or more of oil and gas wells is suitable for agricultural use. In other basins (e.g., San Juan, Piceance, 

and Permian) over 50% of oil and gas wastewater is unsuitable for use without treatment. A 2006 

Department of Energy (DOE) study pointed out that the quality necessary for use in agriculture 

depends on the plant or animal species involved and that in the Bighorn Basin in Wyoming, lowsalinity wastewater is used for agriculture and livestock watering after minimal treatment to 

remove oil and grease (DOE, 2006). 

Although TDS is a common criterion for water quality, there are also recommended limits or 

considerations for some metals, alkalinity, and nitrate in water for use in livestock watering, and for 

metals, SAR, electrical conductivity (ECw), and pH for water for irrigation (Guerra et al., 2011). Also, 

using TDS/salinity as the primary criterion may not be appropriate if wells contributing to the 

produced water have undergone hydraulic fracturing or if maintenance chemicals are being used 

on the well. 

The water quality standards and monitoring requirements for direct discharge for use in irrigation 

or livestock watering include few specifications. In California, the California Council on Science and 

Technology (CCST, 2015a) notes that the testing and treatment required by the regional water 

 

1 40 CFR 435.52(b).
Chapter 8 – Wastewater Disposal and Reuse

8-51 

quality control boards prior to use of produced water for irrigation do not include assessment for 

chemicals associated with hydraulic fracturing and that there are no policies prohibiting the use of 

hydraulic fracturing wastewaters for irrigation.

In the Wind River Basin in Wyoming, three NPDES permits were appealed by environmental groups 

due to concerns that the permits failed to address maintenance and hydraulic fracturing chemicals

(Natural Resources Defense Council, 2015; PEER, 2015). The environmental groups argued that the 

EPA’s regulations do not allow for the discharge of produced water containing chemicals from well 

treatment, and that, moreover, the EPA lacked sufficient information regarding the well treatment 

chemicals to determine whether the discharge would be “good enough quality” for wildlife and 

agricultural use, as required under the ELG regulations. As an example, the environmental groups 

pointed to MSDS information provided upon request for six maintenance products, which included 

toxic chemicals such as ethylene glycol, benzyl chloride, isopropanol, naphthalene, benzene, and 

xylene, among others. This raised concerns that produced water permitted for direct discharge may 

contain toxic chemicals or their degradation products. Ultimately, pursuant to a settlement 

agreement with the environmental groups and permittees, the EPA issued modified permits that 

included additional conditions for handling of and reporting about well stimulation and well 

maintenance chemicals. 

8.4.7 Management of Solid and Liquid Residuals

Solid and liquid residuals associated with hydraulic fracturing wastewater are formed from 

treatment processes at CWTs, buildup of sludges in tanks and pits, and scale formation on pipes and 

equipment. These residuals must be managed and disposed of properly to avoid impacts on ground 

and surface water resources. (Note that drill cuttings and drilling muds are outside the scope of this 

chapter.) 

8.4.7.1 Solid Residuals

The solid residuals produced at a CWT depend on the constituents in the untreated water and the 

treatment processes used and are likely to contain TSS, TDS, metals, radionuclides, and organics. 

Solid residuals can consist of sludges (from precipitation, filtration, settling units, and biological 

processes), spent media (filter media, adsorption media, or ion exchange media), and other 

material such as spent filter socks used to remove gross particulates. In addition, solids that 

accumulate in storage tanks and pits and scale that deposits on equipment are part of the residual 

load from a site. These residuals can constitute a considerable fraction of solid waste in an oil or gas 

production area. 

Handling and disposal of residual sludges from treatment processes can present some of the biggest 

challenges associated with these technologies (Igunnu and Chen, 2014). Additional treatment may 

be applied to solid residuals including thickening, stabilization (e.g., anaerobic digestion), and 

dewatering processes prior to disposal. The solid residuals are then typically sent to a landfill, land 

spread on-site, or incinerated (Morillon et al., 2002). Land spreading is a waste management 

method in which wastes are spread over the soil surface and tilled into the soil to allow the 

hydrocarbons in the wastes to biodegrade (Smith et al., 1998); note that inorganic constituents 
Chapter 8 – Wastewater Disposal and Reuse

8-52 

(e.g., salts, metals, metalloids, and radionuclides) will not degrade. In addition, pits or 

impoundments that have reached the end of their useful life have accumulated residuals. Practices 

used to decommission these pits include draining and leveling the pit in place or land farming the 

residual materials into the ground (Rich and Crosby, 2013), although more information is needed 

on the potential for these practices to affect water resources.

A particular concern for the management of residual wastes is TENORM that originates from the 

geologic formation and was present in the produced water (SAFER PA, 2015). Studies have found 

TENORM in solid residuals at oil and gas operations including the filter cake (PA DEP, 2015b), filter 

socks (Harto et al., 2014), and pit sludges (Rich and Crosby, 2013). Researchers have assessed 

Marcellus produced water samples, finding that many with low barium and high radium-226 levels 

would generate sludges that exceed the maximum acceptable radium-226 activity for 

nonhazardous landfill disposal in Pennsylvania (Silva et al., 2014b; Silva et al., 2014a). In scales that 

build up on hydraulic fracturing and treatment equipment and sludges that accumulate in tanks and 

pits, radium can coprecipitate with barium, strontium, or calcium sulfates (Smith et al., 1999). (See 

Section 8.5.2 for additional discussion of TENORM associated with residuals.)

The accumulation of TENORM in the solids generated can limit or preclude landfills as a disposal 

option. Walter et al. (2012) point out that wastes containing TENORM can be problematic due to 

the possibility of radon emissions from the landfill. Regulatory limits on permissible radionuclide 

levels accepted at non-hazardous landfills vary by state (Silva et al., 2014a).1 Some states have 

volumetric limitations on TENORM in their landfill permits (e.g., Colorado). Also, some states write 

criteria, such as gamma exposure rates (radiation) and radioactivity concentration limits, into 

permits for many landfills that are permitted to accept TENORM. Silva et al. (2014a) note that there 

are 50 nonhazardous (RCRA-D) disposal facilities in Pennsylvania, but no TENORM disposal 

facilities. Texas and other states have disposal facilities for TENORM. 

8.4.7.2 Liquid Residuals

Liquid residuals include concentrated brines (from membrane or evaporation processes) and 

regeneration or cleaning chemicals (from ion exchange, adsorption, and membrane processes) 

(Fakhru'l-Razi et al., 2009). Practices for managing liquid residual streams from treatment 

processes are generally the same as for untreated hydraulic fracturing wastewaters, although the

treated volumes are smaller, resulting in lower costs (Hammer and VanBriesen, 2012). 

Concentrations of contaminants in liquid residuals, however, will be higher. The most common 

disposal method is injection into disposal wells. 

If the liquid is not injected into a disposal well, treatment to remove salts would be required for 

surface water discharge to meet NPDES permit requirements and protect the water quality for 

downstream users such as drinking water utilities (Section 8.5). Because some constituents of 

concentrated liquid residual waste streams can pass through or impact municipal wastewater 

treatment processes (Linarić et al., 2013; Hammer and VanBriesen, 2012), these residuals would

 

1 Examples of permissible radionuclide levels at non-hazardous landfills: Pennsylvania requires alarms to be set at all 

municipal landfills, with a trigger set at 10 μR/hr above background radiation. Texas sets a radioactivity limit, requiring 

that any waste disposed by burial contains less than 30 pCi/g radium or 150 pCi/g of other radionuclides.
Chapter 8 – Wastewater Disposal and Reuse

8-53 

not be appropriate for discharge to a POTW. Elevated salt concentrations, in particular, can have 

detrimental effects on microbiological treatment at municipal wastewater systems, such as 

activated sludge treatment (Linarić et al., 2013). 

Liquid residuals can also be mixed with a solidifying agent such as Portland cement and then

disposed of in landfills, or they can undergo advanced treatment processes to generate products 

such as road salt or industrial chemicals (SAFER PA, 2015). 

8.4.7.3 Potential Impacts from Solid and Liquid Residuals

Residual wastes have the potential to impact the quality of drinking water resources if 

contaminants leach to groundwater or reach surface water. In a recent study by PA DEP, radium 

was detected in leachate from 34 of 51 landfills that accept waste from the oil and gas industry 

(Marcellus in particular). Radium-226 concentrations ranged from 54 to 416 pCi/L, and radium228 ranged from 2.5 to 1,100 pCi/L (PA DEP, 2015b). (See also Section 8.5.2 and see Chapter 9 for 

health effects associated with radium). Countess et al. (2014) studied the potential for a wide array 

of elements to leach from sludges generated at a CWT handling hydraulic fracturing wastewater in 

Pennsylvania. Tests used strong acid solutions (to simulate the worst case scenario) and weak acid 

digestions (to simulate environmental conditions). The data illustrate the possibility of leaching of 

these constituents from landfills. The extent of leaching varied by constituent and by fluid type, but 

the authors concluded that boron, bromide, calcium, magnesium, manganese, silicon, sodium, and 

strontium had high potential to migrate from the residual solids, with bromide and sodium having 

the highest leaching potential (Countess et al., 2014). (See also Section 5.8 in Chapter 5 for 

discussion of the processes governing the movement of constituents in the subsurface.)

In another study assessing the leaching behavior of residuals from hydraulic fracturing operations, 

Sharma et al. (2015) found that alkali metals, alkaline earth metals, and bromide had the highest 

leaching potential of the constituents tested. The authors also found that disposing of hydraulic 

fracturing residuals along with other solids (e.g., at a municipal landfill) produces a greater leaching 

potential than if the residuals are disposed of by burying or land disposal designed for solely the 

hydraulic fracturing residuals. This is due to the more acidic leachate formed at the co-disposal 

locations (Sharma et al., 2015). 

Sang et al. (2014) studied the potential for hydraulic fracturing fluid to mobilize colloidal particles 

in the soil. The study used microspheres and sand particles as surrogates for contaminant particles. 

The authors note that the chemistry of hydraulic fracturing fluid favors transport of colloids and 

mineral particles through rock cracks, and they found that infiltration of flowback fluid can 

transport existing pollutants such as heavy metals, radionuclides, and pathogens, in unsaturated 

soils (Sang et al., 2014). Heavy metals can also move through soil. Although not specific to hydraulic 

fracturing wastes, Camobreco et al. (1996) report high levels of heavy metal transport in soil 

columns, with 12% recovery for lead, 15% for copper, 23% for zinc, and 30% for cadmium 

(Camobreco et al., 1996). 

Residuals, whether liquid or solid, are the most concentrated wastes and waste streams associated 

with hydraulic fracturing operations. Contaminants in the produced water will accumulate in the 
Chapter 8 – Wastewater Disposal and Reuse

8-54 

sludges in storage tanks/pits, in scale on the equipment, and in treatment facilities. Proper 

management and disposal of these highly concentrated wastes is critical to minimize the potential 

for impacts on water resources. 

8.5 Potential Impacts of Hydraulic Fracturing Wastewater Constituents on 

Drinking Water Resources

The previous section discussed the potential impacts of specific wastewater management strategies

on drinking water resources. The severity of impacts, however, depends largely on the constituents 

in the wastewater, the concentrations of those constituents, and their health and ecological effects. 

This section will discuss the potential impacts of several specific types of hydraulic fracturing 

wastewater constituents on drinking water resources. 

The impacts or potential impacts discussed in the literature are heavily focused on discharges from 

CWTs, including treated wastewater that is discharged indirectly through POTWs. Available 

evidence suggests that the effects of hydraulic fracturing on surface water quality are related to 

discharges of partially treated wastewater (Kuwayama et al., 2015a). Other avenues of 

contamination for both surface water and groundwater include leaks from pits and impoundments, 

landfill leachate, and leaching from contaminated sediments and other improperly managed solid 

wastes. 

As noted, an important consideration regarding the potential impacts of hydraulic fracturing 

wastewater on receiving water is whether there are constituents of concern known to have health 

effects or that can give rise to compounds with health effects. See Chapter 9 for discussion of the 

health effects of wastewater constituents. For some classes of constituents, such as DBP precursors, 

considerable research exists regarding concentrations in the waste stream and impacts on 

downstream drinking water treatment plants or the finished drinking water after treatment. For 

other constituents, information is limited, especially within the context of hydraulic fracturing 

activities. There may also be unknown constituents because some ingredients in the original 

hydraulic fracturing fluids are claimed to be CBI. The following subsections identify several classes 

of constituents known to occur in hydraulic fracturing wastewater, discuss whether potential 

impacts are likely, and detail information gaps. 

8.5.1 Bromide, Iodide, and Chloride 

Halides, including bromide, chloride, and iodide, are commonly found in high-TDS hydraulic 

fracturing wastewater. As noted in Section 8.3.1.1, chloride is a regulated contaminant with a 

secondary MCL of 250 mg/L. Bromide and iodide are not regulated, but are of concern due to their 

role in the formation of DBPs (Parker et al., 2014; Krasner, 2009). (See Appendix F for information 

on DBP formation.) High-TDS wastewaters from the Marcellus Shale have been the focus of concern 

due to the state’s history of treating these wastewaters at POTWs (without pretreatment) and at 

CWTs without TDS removal capabilities (Text Box 8-1). Discontinuing the practice of sending shale 

gas wastewater to POTWs without pretreatment (States et al., 2013), and compliance with the new 

EPA pretreatment standards for discharges of unconventional oil and gas wastewaters helps 

mitigate this problem. This section describes the role of some constituents in high-TDS fluids in the 
Chapter 8 – Wastewater Disposal and Reuse

8-55 

formation of DBPs and provides more details on the effects on surface waters as observed in 

Pennsylvania. The lessons learned and steps taken in the Marcellus region can provide valuable 

knowledge for operators and state agencies in other parts of the country that treat and discharge 

high-bromide and high-iodide wastewaters.

8.5.1.1 Influence of Bromide and Iodide on Formation of Disinfection Byproducts

Disinfection byproducts (DBPs) are formed when organic material comes in contact with 

disinfectants (e.g., chlorine, chloramine, chlorine dioxide, or ozone). Of particular concern are DBPs 

formed in the presence of halides (e.g., bromide or iodide). The type of DBP formed depends on the 

organic precursors in the source water and the disinfectant used. Regulated DBPs include total 

trihalomethanes (TTHM), five haloacetic acids (HAA5), bromate, and chlorite. There are, however, 

many additional DBPs that are not regulated and may in fact be of greater concern than the 

regulated species. Brominated forms of DBPs, for example, are considered to be more toxic and 

carcinogenic than chlorinated species (McGuire et al., 2014; Parker et al., 2014; States et al., 2013; 

Krasner, 2009; Richardson et al., 2007). Another halide, iodide is also found in some hydraulic 

fracturing wastewater (Chapter 7), and although its effects have not been as well documented as 

those associated with bromide, iodide raises some of the same concerns regarding formation of 

toxic DBPs as bromide (Xu et al., 2008). 

Studies have found that elevated bromide levels in water correlate with increased DBP formation in 

the drinking water that is delivered to customers (also called “finished drinking water”) (Obolensky 

and Singer, 2008; Matamoros et al., 2007; Hua et al., 2006; Yang and Shang, 2004). Harkness et al. 

(2015) studied the chemical composition of flowback, produced waters, treated wastewaters, 

instream flows downstream from discharges, and accidental spill sites. The study found high 

concentrations of bromide and iodide in the flowback and produced waters, concluding that the 

elevated levels of these constituents could promote the formation of toxic brominated and 

iodinated DBPs in downstream drinking water systems (Harkness et al., 2015). 

In terms of the resulting DBP formation, laboratory experiments using hydraulic fracturing 

wastewater from the Marcellus and Fayetteville shales and river water from the Allegheny and Ohio 

rivers suggest that a relatively small portion of hydraulic fracturing wastewater can notably affect 

DBP formation (Parker et al., 2014). In particular, trihalomethanes (THM; a category of DBPs) were 

shown to shift towards greater brominated and iodinated species with a little as 0.01% hydraulic 

fracturing wastewater in disinfected samples. Modeling work by Landis et al. (2016) evaluated the 

impact of CWT discharges on DBP formation at a drinking water system and suggested that 

although only a 3% increase in overall TTHM formation was predicted, the model predicted a 

decrease in chlorinated THM and a substantial shift toward a higher percentage of the more-toxic 

brominated THMs (Landis et al., 2016). 

States et al. (2013) found a strong correlation between bromide concentrations in source water 

from the Allegheny River in Pennsylvania and the percentage of brominated THMs in finished water 

at a drinking water facility using Allegheny source water. Bromide concentrations in the river water 

measured during the study ranged from less than 25 μg/L to 299 μg/L. The authors noted that 

source water containing 50 μg/L of bromide resulted in treated drinking water with approximately 
Chapter 8 – Wastewater Disposal and Reuse

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62% of total THMs consisting of brominated species. When the source water contained 150 μg/L 

bromide, the brominated THM percentage was 83% (States et al., 2013). 

Pope et al. (2007) reported that increased bromide levels are the second best indicator of DBP 

formation, with pH being the first. Furthermore, bromine (which may be formed from bromide in 

the water during disinfection) reacts as much as ten times faster and more efficiently with DBP 

precursors than chlorine (Westerhoff et al., 2004). These studies show that increased bromide 

concentration in a drinking water resource shifts the DBP formation towards more-toxic 

brominated forms.

If disinfection is accomplished using ozonation instead of or in addition to chloramination or 

chlorination, bromide and iodide in the source water can form two additional constituents: bromate 

and iodate. Iodate, although formed during disinfection by ozonation, is not considered a DBP and is 

non-toxic (Allard et al., 2013). Bromate, however, is a DBP of concern and has an MCL of 0.010 

mg/L (U.S. EPA, 1998). 

Another category of DBP that is not regulated is the nitrogenous DBPs, including nitrosamines. Data 

are lacking on the formation of nitrogenous DBPs specifically linked to hydraulic fracturing 

wastewater, but their formation is possible. During chloramination, bromide can enhance the 

formation of the nitrosamine N-nitrosodimethylamine (NDMA) in waters containing the precursor 

dimethylamine (DMA) (Le Roux et al., 2012; Luh and Mariñas, 2012). As with some other nonregulated DBPs, nitrogenous DBPs may be more toxic than the regulated ones (Harkness et al., 

2015; McGuire et al., 2014; Parker et al., 2014). 

As discussed in Section 8.4 and Text Box 8-3, removal of dissolved solids, including chloride and 

bromide, requires advanced treatment processes such as reverse osmosis (RO), distillation, 

evaporation, or crystallization. Unless the treatment plant receiving the high-TDS wastewater 

employs processes specifically designed to remove these constituents, effluent discharge may 

contain high levels of bromide and chloride. Drinking water systems with intakes downstream of 

these discharges may receive water with correspondingly higher levels of bromide and chloride 

and may have difficulty complying with SDWA regulations related to DBPs.

8.5.1.2 Effects on Receiving Waters

Studies show that discharges from oil and gas wastewater treatment facilities can elevate TDS, 

bromide, and chloride levels in receiving waters, and potential impacts may be detectable far 

downstream (> 1km) of an outfall (States et al., 2013; Warner et al., 2013a; Wilson and Van Briesen, 

2013). The work by Landis et al. (2016) in the Allegheny River mentioned above is consistent with 

these findings. The authors studied the impacts of a CWT accepting oil and gas wastewater on water 

quality at a downstream drinking water intake. They found that compared to data from upstream 

(background) locations, bromide concentrations at the intake were increased by 53% at low 

streamflow and 22% during high streamflow.1 

1 Background samples are those taken from locations upstream of, and therefore unaffected by, permitted facilities.
Chapter 8 – Wastewater Disposal and Reuse

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Elevated TDS, chloride, and bromide can serve as indicators of potential influence from hydraulic 

fracturing wastewater in surface water and can also raise concerns about DBP formation in 

downstream drinking water systems. Elevation of bromide has been shown to place a burden on 

downstream drinking water systems. The Pittsburgh Water and Sewer authority (PWSA) drinking 

water system concluded that elevated bromide in their source water led to elevated TTHMs in their 

finished drinking water, with a substantial increase in the percentage of brominated TTHMs (States 

et al., 2013). The utility modified their treatment process and proposed improvements to their 

storage facilities to address the elevated TTHM levels in the distribution system (Chester Engineers, 

2012). 

Conversely, changes in regional wastewater handling that reduce bromide discharges can be 

reflected in receiving waters. A three-year study at water intakes downstream of wastewater 

discharges on the Monongahela River in western Pennsylvania evaluated water chemistry in the 

context of flow measurements. The authors concluded that an overall decrease in bromide 

concentrations at drinking water intakes from 2010 to 2012 was likely associated with shale gas 

operators voluntarily ceasing the practice of sending high-bromide wastewaters to treatment 

facilities that discharge to surface waters without adequate TDS removal (Wilson and Van Briesen, 

2013). 

Elevated TDS and halides need to be interpreted in the context of other inputs into a watershed. An 

EPA source apportionment study of the Allegheny River in Pennsylvania (U.S. EPA, 2015o) found 

that CWTs accounted for almost 90% of the bromide at one drinking water treatment plant intake 

and 37% of the bromide at another intake. Other sources include coal-fired power plants and acid 

mine drainage. Furthermore, although effluent is diluted when discharged to a water body, this may 

not always be sufficient to avoid water quality problems if there are existing pollutant loads in the 

waterbody from other contributors (e.g., such as acid mine drainage or power plant effluent) 

(Ferrar et al., 2013). Warner et al. (2013a) evaluated effluent from the Josephine Brine Treatment 

Facility, which treated both conventional and unconventional (as defined by PA DEP) oil and gas 

wastewater at the time of the study. The authors concluded that even a 500 to 3,000-fold dilution of 

the wastewater would not reduce bromide levels to background. Modeling by Weaver et al. (2016)

suggests that bromide levels in receiving streams can be improved by reducing concentrations in 

the effluent, discharging during periods of high streamflow, and discharging intermittently 

(pulsing). (See Appendix F for additional description of modeling studies.)

In addition to concerns about formation of DBPs within downstream drinking water systems, 

treatment at the upstream CWTs and POTWs themselves can also produce DBPs if the facilities 

disinfect prior to discharge. The DBPs may then be released into receiving waters and increase 

concerns about the total loads of brominated and iodinated DBPs at downstream drinking water 

systems (Hladik et al., 2014). A study by Hladik et al. (2014) documented brominated and iodinated 

DBPs at the outfalls of CWTs and POTWs treating both conventional and unconventional 

wastewater and noted that this DBP signature was different than for those plants that did not 

accept oil and gas wastewater. 
Chapter 8 – Wastewater Disposal and Reuse

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8.5.1.3 Other Constituents That Can Affect Downstream DBP Formation 

In addition to halogens, organic matter and ammonium can also be present in hydraulic fracturing 

wastewater (Chapter 7; Appendix E) and can have an influence on the formation of DBPs at 

downstream drinking water systems (Harkness et al., 2015). Experimental work by Parker et al. 

(2014) found that a mixture of river water with 1-2% flowback by volume could contribute to DBP 

formation due to the higher dissolved organic carbon content of the flowback. Harkness et al. 

(2015) studied the chemical composition of water associated with oil and gas production and found 

high concentrations of ammonium in the flowback and produced waters. Elevated levels of 

ammonium can convert chlorine to chloramines at downstream drinking water treatment plants. 

This could have an impact on the plant’s disinfection practices because chloramines are a weaker 

disinfectant than chlorine (Harkness et al., 2015; Parker et al., 2014). 

8.5.1.4 Mitigating Impacts from TDS and Halides on Drinking Water Utilities

High bromide concentrations and low flow conditions in waterways have been shown to increase 

DBP formation in downstream drinking water systems (States et al., 2013). Most drinking water 

treatment plants are not designed to address high concentrations of TDS (including bromide and 

iodide), limiting their options for restricting the formation of brominated and iodinated DBPs when 

these halides are present. 

To mitigate these impacts, one strategy that was implemented in Pennsylvania was to disallow 

influent of high-TDS wastewaters to POTWs and CWTs that discharged to streams and were not 

designed to treat for TDS. Wilson and Van Briesen (2013) showed that this strategy was effective 

for reducing bromide concentrations at drinking water utilities downstream from POTWs and 

CWTs that had formerly accepted hydraulic fracturing wastewaters (States et al., 2013; Warner et 

al., 2013a; Wilson and Van Briesen, 2013). Alternatively, advanced treatment processes such as 

reverse osmosis, distillation, evaporation, and crystallization, can be employed to reduce 

constituents that contribute to high TDS (e.g., such as chloride, bromide, and iodide), reducing 

impacts on surface waters and, subsequently, downstream drinking water utilities. Strategies such 

as discharging during higher streamflow periods and using a pulsing or intermittent discharge 

could also reduce the frequency and severity of potential impacts on drinking water systems from 

elevated TDS. 

8.5.2 Radionuclides

Potential impacts on drinking water resources from TENORM associated with hydraulic fracturing 

wastewater can arise through a number of pathways, including: treated wastewater in which 

radionuclides were not adequately removed; accumulation of radionuclides in surface water 

sediments downstream of wastewater treatment plant discharge points; migration or mobilization 

from soils that have accumulated radionuclides from previous activities such as pits or land 

application; and inadequate management of treatment plant solids (such as filter cake), landfill 

leachate, or sediments in pits or tanks that have accumulated radionuclides.

An additional concern is the potential for underestimation of radium concentrations in hydraulic 

fracturing wastewater due to the high TDS content. When using wet chemical techniques, high TDS 
Chapter 8 – Wastewater Disposal and Reuse

8-59 

concentrations can result in poor recovery of some chemical constituents. For radium, recovery 

may be as low as <1% in a high-salt matrix (Nelson et al., 2014). This may lead to the inability to 

identify an impact on drinking water resources or an underestimation of the severity of an impact. 

Research suggests that spectroscopic methods are more appropriate for analysis of radium in highTDS wastewaters (Nelson et al., 2014). 

A recent study by the PA DEP (PA DEP, 2015b) provides information that helps fill a general data 

gap regarding TENORM content in oil and gas wastes that are treated and discharged to surface 

waters. The study, although not exclusive to Marcellus wastes, was motivated by concerns over an 

increase in radionuclides in oil and gas wastes observed during the expansion of Marcellus Shale 

production. The study began in 2013 and quantified radionuclide (radium-226, radium-228, K-40, 

gross alpha, and gross beta) levels at CWTs, POTWs, well sites, and landfills and discussed human 

health and environmental implications. Other relevant studies addressing radionuclides focus on 

CWTs that have handled Marcellus wastewater, evaluation of solids in storage pits, and analysis of 

scale on pipes and tanks.

8.5.2.1 Effluent from POTWs

In Pennsylvania between 2007 and 2010, TENORM-bearing wastewaters were sent to POTWs, 

which are generally not required to monitor for radioactivity (Resnikoff et al., 2010). Although 

management of Marcellus wastewaters via POTWs has declined, there is still potential for input of 

radionuclides to surface waters via discharge of CWT effluent either directly to surface water or 

indirectly through discharge to POTWs. The potential for TENORM to pass through treatment at 

POTWs is one of the concerns addressed in the EPA’s recently promulgated pretreatment standards 

for unconventional oil and gas wastewaters that discharge to POTWs. 

Six of the POTWs in the PA DEP TENORM study received effluent from a CWT along with municipal 

wastewater. Note that the CWTs in the study are not described as receiving exclusively Marcellus 

wastewater. The POTWs that receive both CWT effluent and municipal waste had radium in their 

effluent (overall average effluent radium-226 concentration of 103 pCi/L, with a range of <35 to 

340 pCi/L). Those POTWs receiving only municipal wastewater also contained radium, with an 

average effluent radium-226 concentration of 145 pCi/L.1 These concentrations are many times 

higher than the MCL for radium (5 pCi/L) and are also orders of magnitude higher than typical 

background values; radium-226 in river water generally ranges from 0.014 pCi/L to 0.54 pCi/L 

(IAEA, 2014).2

 

1 These values are for unfiltered samples. In filtered samples, the POTWs that receive both CWT effluent and municipal 

waste had higher average radium-226 values than those for POTWs only treating municipal waste (497 pCi/L vs. 85 

piCi/L). Filtered samples are passed through a filter to remove fine particles; concentrations of constituents in filtered 

samples are often lower than in unfiltered samples. However, liquid samples in this study were filtered after preservation 

with acid. Therefore, the difference between unfiltered and filtered samples may not be reliable.

2 A confounding issue for this study is that it was not clear why the radium-226 concentrations were comparable or 

higher for those POTWs not receiving oil and gas CWT effluent. However, sample sizes were small and possible 

alternative sources for the radium were not discussed. The report also did not describe how it was verified that the 

POTWs did not receive contributions from oil and gas wastewater.
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8.5.2.2 Effluent from CWTs 

Four of the ten CWTs sampled during the PA DEP TENORM study (PA DEP, 2015b) discharged to 

surface water under a National Pollution Discharge Elimination System (NDPES) permit, and the 

other six discharged to POTWs. The average radium-226 concentration in the effluent from the 

CWTs (1,840 pCi/L for unfiltered samples) was an order of magnitude higher than in effluent from 

the POTWs. Samples of treated wastewater from zero-discharge facilities contained higher 

concentrations, averaging 2,610 pCi/L radium-226 and 295 pCi/L radium-228 (PA DEP, 2015b). 

The treated wastewater from these zero-discharge facilities will likely be reused for subsequent 

hydraulic fracturing jobs, postponing the need for disposal, but reuse could result in overall 

increases in some constituents of concern due to repeated passage through the subsurface. In 

addition, there is also a potential for impacts on drinking water resources from spills and leaks 

associated with wastewater storage and handling at these facilities. 

Sampling done at the Josephine Brine Treatment Plant in western PA from 2010 – 2012 (Warner et

al., 2013a) detected radium in the effluent (mean values of 4 pCi/L of radium-226 and 2 pCi/L of 

radium-228). Treatment at the facility removes radium by coprecipitation with barium sulfate. The

authors note that if the activities of radium-226 and radium-228 in Marcellus brine influent at the

CWT are similar to those reported by other researchers (Rowan et al., 2011), then the CWT

achieved a 1,000-fold reduction in radium content. (This facility also accepted conventional oil and

gas wastewater.) The detection of radium in the effluent from this CWT suggests that if the influent

concentration is extremely high, radium will still be found in the effluent of a treatment plant even 

if the treatment process removes a high percentage (see Section 8.4 and Appendix F for additional

discussion on constituent removal efficiencies at CWTs).

8.5.2.3 Accumulation in Sediments

In addition to concerns about TENORM in discharges to surface waters, studies have shown the 

potential for a legacy of radionuclide accumulation in surface water sediments. The PA DEP 

TENORM study (PA DEP, 2015b) found radium in sediments near the outfalls for CWTs (averages of 

84.2 pCi/g and 19.8 pCi/g for radium-226 and -228, respectively) and three POTWs receiving 

treated oil and gas wastewater from CWTs (radium-226 and radium-228 concentrations ranging 

from 1.8 to 18.2 pCi/g). Typical background soil levels of radium are approximately 1 to 2 pCi/g (PA 

DEP, 2015b). 

Warner et al. (2013a) measured radium-226 levels in stream sediment samples at the point of 

discharge of a CWT that had treated both conventional oil and gas wastewater and unconventional 

Marcellus wastewater. They found concentrations approximately 200 times greater than upstream 

and background sediments. This indicates the potential for accumulation of contaminants in 

localized areas near wastewater discharge facilities. Although the CWT studied by Warner et al. 

(2013a) also accepted conventional oil and gas wastewater, the authors observed that the radium228/radium-226 ratio in the river sediments near the discharge (0.22 – 0.27) is consistent with 

ratios in Marcellus wastewater. The authors indicate that the radium likely accumulated in the 

sediments, originating from the discharge of treated unconventional Marcellus oil and gas 

wastewater. Accumulation of TENORM can also occur in sediments receiving discharged effluent 
Chapter 8 – Wastewater Disposal and Reuse

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from landfills that accept oil and gas wastes. In the PA DEP TENORM study (PA DEP, 2015b), 

samples of impacted soils were collected at three landfill outfalls. Radium-226 and -228 were 

detected in all samples (2.82 to 4.46 pCi/g and 0.979 to 2.53 pCi/g, respectively).

A study by Skalak et al. (2014), on the other hand, did not find elevated levels of alkali earth metals 

(including radium) in sediments just downstream of the discharge points of five POTWs that had 

previously treated Marcellus wastewater. These inconsistencies among studies suggest that 

accumulation of contaminants in sediment may depend on treatment processes and their removal 

rates for each constituent as well as stream chemistry and hydrologic characteristics. 

Contamination with radium-226 would potentially be long lived because of the long half-life of 

radium.1 

The association of radium with sediments near discharge points is attributed to adsorption of 

radium to the sediments, a process governed by factors such as the salinity of the water and 

sediment characteristics. Increased salinity promotes desorption of radium from sediments, while 

lower salinity promotes adsorption, with radium adsorbing particularly strongly to sediments high 

in iron and manganese (hydr)oxides (Porcelli et al., 2014; Gonneea et al., 2008). Warner et al. 

(2013a) speculate that when saline CWT effluent is discharged into stream water, the lower salinity 

of the stream environment facilitates sorption of radium onto streambed sediments. The long-term 

fate of radium sorbed to sediments depends upon changes in water salinity and the sediment 

properties, including any reduction/oxidation chemical reactions that affect iron and manganese 

minerals in the sediments. Additionally, the sediment may be physically transported downstream 

due to high flows or if sediment is disturbed and resuspended. 

8.5.2.4 Pits and Tanks

Where pits or impoundments are used, radionuclides may accumulate in the bottom sludges and 

can also be found in soils once the pit is closed and leveled. A study of three centralized wastewater 

storage impoundments in southwestern Pennsylvania (Zhang et al., 2015a) showed that radium226 accumulated in various components of the bottom solids, including through coprecipitation 

with barium sulfate. Sludge from one pit showed a substantial increase in radium-226 between 

sampling events 2.5 years apart (from 8.8 pCi/g to 872 pCi/g). The authors attributed the steep 

increase to enrichment in radium during cycles of wastewater reuse. In Texas, accumulation of 

radionuclides (potassium, thorium, bismuth, radium, and lead) was documented for two pits that 

stored fluids associated with hydraulic fracturing (Rich and Crosby, 2013). One pit was 

decommissioned and used as farmland, and the other was active at the time of sampling. Analyses 

of soil and sludge samples detected a number of radionuclides, including radium-226, radium-228, 

thorium-228, strontium-90, and potassium-40 (radium-226 was only found at the former pit). Rich 

and Crosby (2013) note a total beta radiation value of 1,329 pCi/L in one sample from the active pit. 

They note that this value exceeded regulatory guidelines even though the values for individual 

1 The half-life of radium-226 is approximately 1,600 years, while the half-life of radium-228 is 5.76 years. The half-life is 

the time it takes for half of the nuclei in a sample of a radioactive element to decay. After two half-lives, one fourth of the 

original sample will be left, and after three half-lives there will be one eighth of the original sample remaining, and so 

forth.
Chapter 8 – Wastewater Disposal and Reuse

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radionuclides did not exceed regulatory guidelines, suggesting that using a single radionuclide (i.e., 

radium) as an indication of exposure can underestimate total radioactivity. 

Although the sample sizes were small for both the Zhang et al. (2015a) and the Rich and Crosby

(2013) studies, the results suggest that radionuclides associated with sediments from some pits 

could have potential impacts on surface water or groundwater. These studies illustrate the need for 

appropriate management where wastes have high TENORM content. Rich and Crosby (2013) note 

that pits are often found in agricultural regions. If pit solids that are incorporated into soils (e.g., 

during draining and leveling or during land application) contain radionuclides, they may reach 

surface water in runoff or leach from the solids and migrate to groundwater. In active pits, Rich and 

Crosby (2013) note that TENORM in the contents may be deposited onto crops and soil through 

aerosolization or breaching. The Pennsylvania study (Zhang et al., 2015a) suggests that landfill 

leachate may be affected by receiving sludges from impoundments that store produced water and 

will need to be managed appropriately. 

With radium-226 values of 121 pCi/g and 872 pCi/g, sludges from the pits studied by Zhang et al. 

(2015a) exceeded the limit for disposal as a nonhazardous solid in a municipal or industrial solid 

waste landfill but would meet the radium-226 limits for disposal in a hazardous waste landfill. 

There are currently no federal requirements to test solid residuals for radionuclides before 

disposal. At landfills studied in the PA DEP TENORM report (PA DEP, 2015b), seven samples of 

treated effluent from nine facilities that accept oil and gas waste had radium-226 values ranging 

from 105 pCi/L to 378 pCi/L and radium-228 values ranging from <6 pCi/L to 1,100 pCi/L. 

Untreated effluent from the nine landfills had radium-226 contents ranging from 70 to <139 pCi/L.

The study authors conclude that there is “limited potential” for environmental impacts from spills 

or discharges of leachate from these facilities. 

Where wastewater is stored in tanks, TENORM concentrations can increase through radioactive

ingrowth.1 Radium-226 and radium-228 are generally considered the radionuclides of greatest 

concern in wastewaters and are the most frequently measured. But recent research indicates that 

in closed environments such as tanks, where the radium decay product radon cannot escape, total 

radioactivity may increase due to ingrowth of other decay products of radium such as Pb-210, Po210, and Th-228 (Nelson et al., 2015). Experimental work by Nelson et al. found that concentrations 

of these decay products in Marcellus produced water that was stored in a sealed drum started 

growing immediately. Concentrations started at zero and reached 10.49 pCi/L for Po-210 and 155 

pCi/L for Th-228 over the first 50 and 66 days of storage, respectively. The authors note that these 

decay products are not soluble, would be associated primarily with particulates, and could be 

bioavailable. This study demonstrates that analyzing for radium will not provide a complete 

indication of sample radioactivity if the water is stored in a closed environment and that 

subsequent management decisions would need to take into account possible increases in 

radioactivity due to ingrowth.

 

1 The ingrowth, or growth within a sample, of radioactive daughter products from radionuclides initially present in the 

sample can cause greater radioactivity than that resulting from the parent radionuclides alone. 
Chapter 8 – Wastewater Disposal and Reuse

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8.5.2.5 Other Solids

Other solid wastes associated with unconventional oil and gas production that may contain 

radionuclides include solid residuals from POTWs and CWTs and scale in oil and gas equipment. 

Filter cake samples from POTWs were found by PA DEP (2015b) to have highly variable radium226 concentrations, with an average of 16 pCi/g, while typical soil concentrations in Pennsylvania 

have been found to be less than 2.5 pCi/g (Greeman et al., 1999). Filter cake from CWTs had an 

average radium-226 concentration of 111 pCi/g. The authors conclude that there could be impacts 

on surface waters through spills or effects on groundwater from landfill leachate containing 

contaminants originating in residuals sent to landfills.

Accumulation of TENORM-bearing scale in CWTs or POTWs may continue to affect the treatment 

plant even after discontinuing treatment of wastewaters containing high radionuclide 

concentrations. Radium can adsorb onto scales in pipes and tanks and can also be removed from 

water by coprecipitation if sulfate or carbonate is added to hydraulic fracturing wastewater to 

precipitate calcium, barium, or strontium (Kappel et al., 2013; USGS, 2013a). Pipe scale in oil and 

gas production facilities has been found to have radium concentrations as high as 154,000 pCi/g, 

although concentrations of less than about 13,500 pCi/g are more common (Schubert et al., 2014). 

A similar issue, the potential for accumulation and possible release of radionuclides and other trace 

inorganic constituents in water distribution systems, has gained attention, with the potential for 

drinking water concentrations to exceed drinking water standards (Water Research Foundation, 

2010). Scale eventually removed from pipes or other oil and gas equipment can end up in landfills 

and then leach into groundwater or run off to surface water (USGS, 2013a). Also, laboratory 

research suggests that radium in land-applied barium sulfate scales from conventional oil and gas 

operations may become mobilized by microbial processes, rendering the radium more mobile and 

bioavailable (Matthews et al., 2006; Swann et al., 2004); see discussion in Section 8.4.6.1. 

Monitoring would be needed in order to ascertain the potential for accumulation and release of 

radionuclides from systems that have treated or continue to treat hydraulic fracturing wastewaters 

with elevated TENORM concentrations.

8.5.2.6 Road Spreading

Salt and radionuclide accumulation can occur near road spreading sites; one study in Pennsylvania 

describes a roughly 20% increase in average radium-226 concentrations in soils near five roads 

where wastewaters from conventional operations had been spread for de-icing (Skalak et al., 2014). 

However, the standard deviation for the samples was large (24 pCi/g), and background 

concentrations were approximately 1 pCi/g. Should significant accumulation of radionuclides in 

soils near roads occur, it would present a vehicle for potential impacts on drinking water resources. 

The frequency with which hydraulic fracturing wastewater contributes to this type of impact 

depends on state-level regulations dictating whether the wastewater can be used for road 

spreading. 
Chapter 8 – Wastewater Disposal and Reuse

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8.5.2.7 Potential for Monitoring

Effluent from treatment plants (e.g., CWTs, POTWs) and receiving waters can be monitored for 

radionuclides. Research suggests that radium-226 and radium-228 are the predominant 

radionuclides in Marcellus Shale wastewater, and they account for most of the gross alpha and 

gross beta activity in the waters studied (Rowan et al., 2011). Gross alpha and gross beta 

measurements may, therefore, serve as an effective screening mechanism for the presence of 

radionuclides in hydraulic fracturing wastewater. This in turn can help in evaluating management 

strategies. Portable gamma spectrometers allow rapid screening of wastewater effluent. Sediments 

can also be measured for radionuclide concentrations at discharge points. If an accurate assessment 

of total radioactivity is needed rather than a screening, measuring radium content may not be 

adequate depending upon how wastewater has been stored. Analyses of other radionuclides such 

as Pb-210, Po-210, and Th-228 may be warranted, especially if the wastewater has been stored in 

closed loop systems.

8.5.3 Metals

Given the presence in hydraulic fracturing wastewaters of some heavy metals, as well as barium 

and strontium concentrations that can reach hundreds or even thousands of milligrams per liter 

(Table 7-5), surface waters may be impacted if discharges from CTWs or POTWs indirectly 

receiving oil and gas wastewater via CWTs are not managed appropriately or if spills occur. 

Common treatment processes, such as chemical precipitation, are effective at removing many 

metals (Section 8.4). Effluent sampling results collected between October 2011 and February 2013 

from seven facilities in Pennsylvania treating oil and gas wastewaters were requested by the EPA. 

The results revealed low to modest concentrations of copper (0 – 50 μg/L), zinc (14 – 256 μg/L), 

and nickel (8 – 22 μg/L) (U.S. EPA, 2015f, g). However, metals such as barium and strontium were

found to range from low to elevated concentrations in the effluent for some of the facilities. The 

data showed effluent barium concentrations ranging from 0.35 to 25 mg/L (median of 3.5 mg/L 

and average of 6.7 mg/L). For results that were greater than 2 mg/L, the drinking water MCL for 

barium was exceeded. Strontium concentrations ranged from 0.36 to 546 mg/L (median of 297 

mg/L and mean of 236 mg/L) (U.S. EPA, 2015g). (See Chapter 9 for information on health effects for 

barium and strontium.)

Volz et al. (2011) discussed a December 2010 effluent sampling effort at a Pennsylvania CWT that 

had been treating both conventional and Marcellus wastewater; they measured average barium and 

strontium concentrations of 27 mg/L and nearly 3,000 mg/L, respectively (eight samples from the 

one plant) (Volz et al., 2011). NPDES compliance data submitted for 2011 shows that effluent from 

the same CWT had average barium effluent levels ranging from 26 to 98 mg/L in the months prior 

to PA DEP’s April 2011 request to cease sending hydraulic fracturing wastewater to this and other 

facilities exempt from the 2010 TDS regulation (U.S. EPA, 2015f, g). After May, 2011, barium 

effluent concentrations dropped to average values of 9 to 22 mg/L. The facility is scheduled to 

upgrade its TDS removal capabilities, which should help decrease concentrations of metals in the 

effluent. 
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Limited data are available on metal concentrations in wastewater and treated effluent that are

directly discharged; additional information would be needed to assess whether there could be 

downstream effects on drinking water utilities. NPDES discharge permits, which restrict TDS 

discharge concentrations, would likely reduce metal effluent concentrations due to the additional 

treatment necessary to minimize TDS.

8.5.4 Volatile Organic Compounds

Benzene is a common constituent in hydraulic fracturing wastewater, and it is of concern due to 

recognized human health effects. A wide range of concentrations of BTEX compounds occurs in 

wastewater from the Barnett and Marcellus shales. Natural gas formations generally produce more 

BTEX than oil formations (Veil et al., 2004), and lower concentrations of BTEX naturally occur in 

wastewater from CBM production (Appendix Table E-9). The organic chemistry of Marcellus 

wastewater has been found by Akob et al. (2016) to be more variable than that of inorganic 

constituents, indicating the need to consider the concentrations of organic compounds when 

planning wastewater management. 

Processes such as air stripping or dissolved air flotation can remove VOCs during treatment, but if 

treatment is not adequate prior to discharge, the VOCs may reach water resources. For example, the 

average benzene concentration measured in the discharge from a Pennsylvania CWT in December 

2010 was 12 μg/L (Volz et al., 2011) exceeding the MCL for benzene of 5 μg/L.1 The facility was 

receiving wastewater from both conventional and unconventional operations at that time. Ferrar et 

al. (2013) measured for BTEX in effluent from the same facility, and mean concentrations among 

the four compounds ranged from approximately 2 to 46 μg/L. Concentrations were lower for 

samples taken after May 19, 2011 (when Marcellus operators voluntarily stopped sending 

wastewater to POTWs and CWTs exempt from the 2010 TDS regulation), and the difference 

between pre and post May 2011 sampling was considered statistically significant. 

Spills and leakage from pits creates another potential route of entry to drinking water resources, as 

described in Section 8.4.5. Akob et al. (2016) documented the microbial degradation of organic 

compounds in Marcellus produced water and note that more research is needed to evaluate how 

this could mitigate the migration of organic constituents in the event of spills or leaks.

8.5.5 Semi-Volatile Organic Compounds

Little is known about the fate of the SVOC, 2-butoxyethanol (2-BE) (an antifoaming and anticorrosion agent used in slick-water) (Volz et al., 2011) or its potential impact on surface waters, 

drinking water resources, or drinking water systems. This compound is very soluble in water and is 

subject to biodegradation, with an estimated half-life of approximately 1-4 weeks in the 

environment (Wess et al., 1998). It is classified by the EPA’s Integrated Risk Information System 

(IRIS) as not likely to be carcinogenic to humans, and the International Agency for Research on 

Cancer (IARC) classifies it as having insufficient evidence to determine carcinogenicity (see Chapter 

9 for more information). 2-BE was detected in the discharge of a Pennsylvania CWT at 

 

1 Among the BTEX compounds, the MCL for benzene is the lowest at 5 μg/L; the MCL for ethylbenzene is 700 μg/L, the 

MCL for toluene is 1,000 μg/L, and the MCL for xylenes is 10,000 μg/L. 
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concentrations of 59 mg/L (Volz et al., 2011). Ferrar et al. (2013) detected 2-BE in the effluent from 

a CWT in western Pennsylvania at average concentrations of 34 – 45 mg/L; the latter value was 

measured when the CWT was receiving only conventional oil and gas wastewater. Data are lacking 

on 2-BE concentrations in surface waters that receive treated effluent from hydraulic fracturing 

wastewater treatment systems.

Polyaromatic hydrocarbons (PAHs; a group of SVOCs) have been found in hydraulic fracturing 

wastewater (Section 7.3.4.7, Table 7-6). PAHs detected in an unlined pit containing oil and gas 

wastewater near the Duncan Oil Field in New Mexico were also detected in soils 82 ft (25 m) 

downgradient at concentrations ranging from 2,000 to 4,900 μg/kg and 164 ft (50 m)

downgradient, with concentrations ranging from 22 to 370 μg/kg (Sumi, 2004; Eiceman, 1986). 

8.5.6 Oil and Grease

Oil and grease in oil and gas wastewater can come from the formation or from oil-based drilling 

fluids. Typically, oil and grease are separated from the wastewater before discharge either by heat 

treatment or by gravity separation followed by skimming. If these processes are inefficient, oil and 

grease can be integrated with the discharge to surface waters. For example, in some cases, oil and 

grease are allowed to separate in pits, and water is then withdrawn from the lower part of the pit. If 

the oil layer is allowed to drop to the level of the standpipe or if the water is agitated, oil and grease 

may be discharged along with the water. Oil and grease are also often dispersed in wastewater in 

the form of small droplets that are 4 to 6 microns in diameter. These droplets can be difficult to 

remove using typical oil/water separators (Veil et al., 2004). 

A study was conducted in Wyoming by the U.S. Fish and Wildlife Service from 1996 to 1999 of sixty 

five oil and gas sites that discharge to ephemeral streams and subsequently to wetlands. Fifteen 

percent of the wetlands receiving wastewater contained oil-stained vegetation and had a visible oil 

sheen on the sediments. In addition, ten of twelve sites that were randomly selected for water 

sample collection (from oil field separator or skim pit effluent) exceeded the discharge limit of 10 

mg/L for oil and grease with one site as high as 54 mg/L (Ramirez, 2002). 

8.6 Synthesis

A variety of strategies may be considered for the management of hydraulic fracturing wastewater. 

Important factors for planning management include cost, logistics, wastewater composition, 

wastewater volumes, and regulations. Available information suggests that Class IID wells regulated 

under the UIC Program are the most frequently used wastewater management practice, but reuse, 

sending to a CWT, and various other methods are also employed. 

8.6.1 Summary of Findings

8.6.1.1 Wastewater Volumes

The most current national estimate of the total wastewater volume generated in the oil and gas 

industry (both onshore and offshore) was 889.59 billion gal (21.18 billion bbls or 3.37 trillion L) in 

2012, although this estimate is subject to a number of uncertainties (Veil, 2015). The total amount 
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of wastewater generated may increase if hydrocarbon production increases in a region, although 

Veil (2015) suggests that this trend may not hold true at the national level. Geographically, a large 

portion of onshore oil and gas wastewater in the United States is reported to be generated in the 

western part of the country, consistent with the areas where most oil and gas wells are located and 

most production takes place. 

Obtaining reliable national estimates of the amount of wastewater attributable to hydraulic 

fracturing is a challenge. State data collection efforts vary, and in many states, production data do 

not identify which wells have been hydraulically fractured. However, annual estimates compiled 

from those states where hydraulic fracturing wastewater is identified range from hundreds of 

millions to billions of gallons of wastewater generated each year. Data from individual states 

indicate that along with an increase in the numbers of hydraulically fractured wells, associated 

wastewater volumes have generally increased over the last several years into 2014. However, while 

there is a general correlation between unconventional oil and gas production and wastewater 

volume, the relationship is complicated by several factors such as timing of drilling and production. 

More complete and comparable estimates of local, state, and regional wastewater volumes would 

facilitate wastewater management on the part of operators as well as planning on the part of 

agencies that oversee wastewater management. 

8.6.1.2 Wastewater Management Practices

Hydraulic fracturing wastewater is managed in a variety of ways, including disposal via Class IID 

wells; minimal treatment and reuse (in subsequent fracturing operations); more complete 

treatment followed by reuse; sending to CWTs for treatment followed by direct discharge or 

transfer to POTWs; evaporation; and other uses such as agriculture and wildlife use (allowed only 

in the arid west when the wastewater is of good enough quality for such uses). All of these 

strategies have the potential to affect drinking water resources. Wastewater management practices 

continue to shift in response to evolving understanding of environmental concerns, emplacement of 

new regulatory controls, changes in costs, and changes in technology and operator practices. 

Unauthorized discharges of hydraulic fracturing wastewater have also been documented, and such 

discharges can potentially impact drinking water resources. 

As of 2015, available information suggests that Class IID disposal wells are a primary wastewater 

management practice for operators in most of the major unconventional reservoirs in the United 

States, with the notable exception of the Marcellus Shale region in Pennsylvania. Class IID wells 

tend to be economically favorable, especially if they are located within a reasonable transportation 

distance from well sites (U.S. GAO, 2012). In particular, large numbers of active injection wells are 

found in Texas (7,876), Kansas (5,516), Oklahoma (3,837), Louisiana (2,448), and Illinois (1,054)

(U.S. EPA, 2016d). 

Pennsylvania is somewhat unique in having only nine Class IID wells (as of February 2015), along 

with having experienced significant growth of shale gas production in the Marcellus and 

corresponding production of large volumes of wastewater. Operators producing from 

unconventional formations (as defined by PA DEP) have managed their wastewater through the use 

of POTWs (a practice that is subject to recently promulgated regulations), CWTs, extensive reuse 
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for hydraulic fracturing operations, and hauling to disposal wells (to a lesser degree). The 

wastewater management history in Pennsylvania provides an example of evolving strategies to 

manage the treatment, discharge, storage, and reuse of hydraulic fracturing wastewaters that are 

high in constituents of concern (e.g., bromide, TDS, and TENORM). 

Reuse of hydraulic fracturing wastewater to formulate fluid for subsequent hydraulic fracturing 

jobs is most prevalent in Pennsylvania (as high as 90%), with much of the reuse happening on-site 

(PA DEP, 2015b). Reuse is practiced in other regions as well (e.g., Haynesville Shale, the Fayetteville 

Shale, the Barnett Shale, and the Eagle Ford Shale), but at much lower rates (about 5 – 20%). 

Reliable estimates are not available for all areas of the United States because waste management 

practices are not consistently reported across all states. If hydraulic fracturing activity slows, 

demand for wastewater for reuse will also likely decrease, and other forms of wastewater 

management will be needed. Potential impacts associated with reuse center on concerns over the 

storage of untreated or minimally treated wastewater on-site or transport to CWTs.

Treatment of hydraulic fracturing wastewater may be done at CWTs or using mobile or semimobile systems designed for on-site use. Treatment at a CWT may be followed by direct discharge 

by the CWT to surface water, indirect discharge to a POTW in accordance with recently 

promulgated regulations, or reuse. Most CWTs treating hydraulic fracturing wastewater are located 

in Pennsylvania (about 40 facilities), with a limited number in other states. CWTs vary widely in 

treatment capabilities, ranging from producing high-quality effluent to minimal treatment for reuse.

Other wastewater management practices, such as evaporation and agricultural uses, represent a 

smaller fraction of wastewater management nationally. These practices can, however, be locally 

significant. Although specific instances of contamination were not identified for this assessment, 

these practices could lead to impacts on drinking water resources if facilities are not properly 

constructed and maintained or if water quality is not adequately characterized to ensure that 

management is appropriate. 

8.6.1.3 Treatment and Discharge

Wastewater that is treated and subsequently discharged by CWTs can result in impacts due to 

inadequate treatment. A frequently cited concern is the high TDS content in wastewaters from 

unconventional formations, which poses challenges for treatment, discharge, and reuse. Treatment 

processes such as sedimentation, filtration, flotation, and chemical precipitation are capable of 

removing constituents such as oil and grease, major cations, metals, and TSS. They do not, however, 

adequately reduce TDS in high-salinity wastewaters. More advanced processes such as reverse 

osmosis (RO) or distillation are needed if TDS removal is required (Shaffer et al., 2013; Younos and 

Tulou, 2005). Most available information on treatment of hydraulic fracturing wastewater is based 

on practices used in Pennsylvania because that is where most data have been collected. 

Hydraulic fracturing wastewater discharged from treatment facilities without advanced TDS 

removal processes has resulted in elevated TDS concentrations (including bromide, iodide, and 

chloride levels) in receiving waters. Impacts from these discharges is due largely to the role of 

bromide and iodide in DBP formation at downstream drinking water systems, potentially causing 
Chapter 8 – Wastewater Disposal and Reuse

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higher levels of harmful DBPs in finished drinking water.1 Modeling suggests that very small 

percentages of hydraulic fracturing wastewater added to a river used as a source for drinking water 

systems could cause a notable increase in DBP formation. 

Radionuclides (i.e., TENORM), which are present in some hydraulic fracturing wastewaters, can 

cause impacts if the wastewater is discharged without adequate treatment. TENORMs have been 

measured in effluent from wastewater treatment facilities receiving Marcellus wastewater (which 

includes effluent sent for reuse and not discharged to surface water). Radium-226, radium-228, 

gross alpha, and gross beta are most cited as the radioactive constituents of concern, likely due to 

the availability of test methods for these constituents in wastewater. Radium concentrations can 

range up to thousands or tens of thousands of pCi/L. Fewer data are available on concentrations of 

uranium and other radionuclides in hydraulic fracturing wastewaters. Also, fewer data exist on 

radionuclide concentrations in wastewaters from unconventional formations other than the 

Marcellus, limiting our ability to assess potential impacts from TENORM on a nationwide basis. 

Other constituents posing health or environmental concerns that can be discharged in inadequately 

treated hydraulic fracturing wastewater include organic compounds, barium, strontium, and other 

metals. Chemicals used in the fracturing fluid or their degradation products could also be present. A 

variety of treatment processes can be used for removal of these contaminants, from commonly used 

methods such as chemical precipitation and filtration to more advanced and more costly 

techniques, such as reverse osmosis, distillation, and mechanical vapor recompression. 

8.6.1.4 Storage and Disposal Pits and Impoundments

Regardless of the wastewater management practices used, some type of temporary storage of fluids 

is generally required. Storage can be in the form of tanks as well as pits and/or impoundments. Pits 

encompass a variety of structures, from on-site pits for storage at the well site to larger, centralized 

facilities (typically referred to as “impoundments” or “ponds”). Some states allow evaporation pit 

facilities or percolation pits as a means of wastewater disposal. The locations and number of pits 

are not well documented in most states, nor are pits associated with hydraulic fracturing 

operations necessarily identified, despite efforts by the U.S. EPA (U.S. EPA, 2003b) and 

environmental groups such as SkyTruth to identify pits in use. Information that is typically 

available on state websites includes permitted centralized commercial evaporation facilities 

(COWDFs) most commonly used in the western United States. 

Impacts on both groundwater and surface water resources due to inadequate pit capacities, 

overfilling, and leaks have been documented. In extreme precipitation events, pits can be 

overtopped. Leaks can occur if liners are compromised or were not used. With an increased 

emphasis on reuse in some regions, the need for temporary storage of high-TDS wastewater 

increases the potential for leaks and spills from pits and during fluid handling. 

 

1 Some types of DBPs are regulated under SDWA’s Stage 1 and Stage 2 DBP Rules, but a subset of DBPs, including a 

number of chlorinated, brominated, nitrogenous, and iodinated DBPs, are not regulated. Brominated and iodinated DBPs 

are more toxic than other species of DBPs.
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Unlined pits, in particular, provide a pathway for contaminants to reach groundwater, and impacts 

on groundwater from historic and current uses of unlined pits in the oil and gas industry have been 

documented. The resulting contamination can be long-lasting. States have taken measures to phase 

out the use of unlined disposal and storage pits, but unlined pits that are still in use can provide an 

ongoing potential source of contamination for groundwater (Grinberg, 2014). 

8.6.1.5 Residuals

Solid and liquid residuals associated with hydraulic fracturing wastewater (treatment residuals 

from CWTs, sludges from tanks and pits, and pipe scale) could have impacts on drinking water 

resources if not managed and disposed of properly. Liquid residuals are inappropriate for surface 

water discharge or discharge to a POTW due to high concentrations of salts and other 

contaminants; they are commonly disposed of in an injection well. Solid residuals may leach a 

number of constituents, such as alkali metals, alkaline earth metals, and bromide. They can also 

contain TENORM if radionuclides are present in the wastewater being treated. Given that residuals 

are commonly disposed of in landfills, TENORM can be problematic due to the possibility of radon 

emissions and radioactivity in the landfill leachate. Solids from pits or tanks can also contain 

TENORM if the wastewater contains radionuclides, and one study has shown the potential for 

radioactivity to increase in the closed environment of tanks. 

8.6.2 Factors Affecting the Frequency or Severity of Impacts

The frequency and severity of impacts on drinking water resources from hydraulic fracturing 

wastewater will depend upon the wastewater composition and volumes, and the mix of wastewater 

management strategies used.1 The types of potential impacts (along with frequency and severity) 

may shift in time as management practices change in response to evolving environmental, 

regulatory, economic, or logistical drivers. The frequency and severity of impacts can also depend 

on the size and initial quality of the drinking water resource and its proximity to wastewater 

management operations.

8.6.2.1 Role of Changing Wastewater Management Practices

The most common disposal option for hydraulic fracturing wastewater is injection into Class II 

disposal wells. If this option becomes restricted in a given location, the wastewater management 

options could shift, at least locally, towards other options such as sending wastewater to CWTs for 

treatment and either discharge or reuse. Although reuse avoids the immediate need to discharge 

wastewater by directing it to ongoing hydraulic fracturing activities, the practice could concentrate 

radionuclides or other constituents as fluid moves through cycles of reuse. Whether such 

concentrations would be significant depends on the ratio of recycled to “fresh” water when the 

wastewater gets reused. Alternatively, wastewater might need to be transported to more distant 

 

1 Both national and state regulations affect the wastewater management practices used. At a national level, although the 

EPA’s oil and gas ELG regulations generally prohibit the direct discharge of oil and gas wastewater to waters of the U.S., 

treatment and discharge of hydraulic fracturing wastewater can occur under certain limited circumstances, such as under 

an exemption authorizing discharge for agricultural and wildlife use in the arid west, or by Centralized Waste Treatment 

facilities. For additional information on national regulations relevant to hydraulic fracturing wastewater management, see 

Text Box 8-2. 
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Class IID wells. This option, while attractive from the perspective of limited disposal impacts, could 

increase the frequency of impacts from spills and leaks during transportation (see Chapter 7 for 

discussion of roadway transport of produced water). 

8.6.2.2 Treatment and Discharge

Both the frequency and severity of potential impacts on drinking water resources from treated 

hydraulic fracturing wastewater depend on the influent concentrations of the constituents in the 

wastewater and the type and adequacy of the treatment processes employed. If treatment and/or 

blending is inadequate, the resulting quality in a receiving water could, for example, influence 

formation of DBPs during subsequent drinking water treatment, impair biological treatment 

processes, and release TENORMs into receiving waters. 

The volume of treated effluent discharged relative to the size of the receiving water body is an 

important local factor affecting the frequency and severity of potential impacts. Because of dilution 

effects, drinking water systems drawing from smaller rivers will likely face greater challenges in 

dealing with contaminants in their source water than systems drawing from larger rivers receiving 

the same volume of effluent. Seasonal changes in streamflow will also affect frequency and severity 

by affecting the degree of dilution. Existing loadings of pollutants from other sources in a watershed 

can increase the frequency and severity of potential impacts if the additional contributions from 

hydraulic fracturing wastewater cause concentrations to exceed thresholds. 

Direct discharges of wastewaters with lower TDS concentrations to ephemeral streams are allowed 

in parts of the country where the wastewater is considered to be “of good enough quality” for 

livestock watering and wildlife use, and the discharges may constitute a large portion of 

streamflow. Permits authorizing such discharges may only require monitoring for a limited set of 

constituents. In particular, they may not necessarily require monitoring for specific constituents 

associated with hydraulic fracturing. The potential for water quality impacts from such discharges 

depends upon whether chemicals used for fracturing fluid or maintenance (or their degradation 

products) are present and at what concentrations. Long-term discharges to these ephemeral 

streams could result in ongoing impacts if there are unrecognized or unaddressed water quality 

issues. 

Concerns about radionuclides in hydraulic fracturing wastewater have received considerable public 

attention, especially in the Marcellus region. The severity and frequency of impacts on receiving 

waters and sediments from TENORM depends upon the TENORM content in the wastewater 

(highest in regions with NORM-rich formations), temporal variability in the wastewater 

composition, and the treatment processes used. There are insufficient data to indicate whether 

radionuclides from these wastewaters have reached drinking water intakes. However, data do 

suggest that radionuclides can accumulate in sediments at or near discharge points from facilities 

that treat and discharge oil and gas wastewater. A recent PA DEP study (PA DEP, 2015b) reported 
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radium in the effluent of both CWTs handling oil and gas wastewater and POTWs receiving effluent 

from such facilities. 

Analysis of TENORM concentrations in hydraulic fracturing wastewaters prior to treatment, 

selection of appropriate treatment processes that adequately address the TENORM levels, and 

monitoring of TENORM in the treated effluent and receiving waters could help address the 

frequency and severity of potential impacts on drinking water resources in these areas. However, a 

confounding issue is underestimation of radium concentrations when using traditional wet 

chemical methods with high-TDS waters. This could consequently cause underestimation of 

frequency or severity of impacts. Newer studies have begun to use gamma spectroscopy for better 

recovery, which could help with more accurate assessment of frequency and severity of impacts 

(Nelson et al., 2014). 

Accumulation of other contaminants such as organic compounds or metals in sediments at or near 

discharge points is also possible. If the sediments are disturbed or entrained due to dredging or 

flood events, contaminated sediments could be transported downstream closer to drinking water 

systems. The fate of such sediments and likelihood of mobilization of contaminants originating from 

hydraulic fracturing wastewaters have not been explored. The frequency and severity of impacts 

related to contaminated sediments would depend on a number of site-specific factors such as 

concentrations in the sediments, effluent quality, volume from the discharging facility, stream 

water quality, and stream hydrodynamics. 

8.6.2.3 Storage and Disposal Pits and Impoundments

Tanks, pits, and impoundments, ever-present at oil and gas operations and CWTs, provide an 

opportunity for impacts on drinking water resources. Tanks are generally regarded as being safer 

than pits in terms of containment, although recent research has shown the potential for an increase 

in radioactivity in tank sediment if the wastewater contains TENORM. For pits and impoundments, 

the likelihood and severity of impacts due to spills and leaks depends in part on state construction 

and maintenance requirements for pits and how well these are observed. Frequency and severity of 

impacts will be lessened by attention to design standards, competent construction, and operational 

practices.

Liners, in particular, are an important measure to protect groundwater resources and are a 

common aspect of pit construction requirements. Liner specifications address materials, thickness, 

and leak detection. If a liner is compromised or nonexistent, the severity of impacts on groundwater 

will be affected by the volume leaked, the composition of the water in the pit, the depth to the water 

table, soil permeability, and the capacity of the soil to retain certain pollutants as the water 

percolates through. If substantial sediment has built up in the bottom of the pit, then in the event of 

a liner breach, contaminants may leach if the sediments permit water to pass through and into the 

soil. The fate and transport of wastewater contaminants in the subsurface is governed by a complex 

set of physical, chemical, and biological processes that dictate interactions between wastewater 

constituents and soil minerals, degradation or transformation of wastewater constituents, and 

possible mobilization of constituents in the soil under a pit (see Section 5.8 in Chapter 5 for a 

thorough discussion of processes affecting movement of constituents in the subsurface). Duration 
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of use is also a consideration; the longer a pit with a faulty or nonexistent liner receives 

wastewater, the more severe the ultimate impact could be on underlying sediment and 

groundwater. 

In the event of overtopping of a pit due to overfilling or extreme weather, the severity of impacts on 

surface water or groundwater will depend on the volume that overflows, wastewater composition,

distance to surface water (if wastewater flows over land), depth to the water table, and soil 

properties (if the overflow infiltrates into the soil). If the overflow reaches a stream or river, the 

size of the spill relative to stream size and flow rate could also affect the severity of the impact. The 

combined factors that can contribute to overflows include capacity of the pit, the volume of fluid 

stored in the pit (i.e., freeboard) at the start of the precipitation event, and failure to monitor/

reduce pit fluid levels if needed. 

As with concerns over discharges, the potential for impacts will be tied to other, existing stresses 

within a watershed. If the surface water is already receiving pollutant loadings from other sources, 

then an additional contribution from a pit-related leak or spill may not be as readily accommodated 

without causing water quality impairment. 

8.6.2.4 Other Management Practices and Management of Residuals

Other management strategies such as irrigation, road spreading, and evaporation are less 

frequently employed for hydraulic fracturing wastewaters. The severity of impacts on surface 

waters from irrigation and road spreading will depend on the constituents in the wastewater (e.g., 

salts, radionuclides, and chemicals used in hydraulic fracturing), the distance to a receiving water, 

and whether stormwater management measures exist to mitigate runoff. The factors influencing 

whether constituents will migrate to shallow groundwater include depth to the water table, 

precipitation, soil permeability, and the soil’s ability to retain pollutants that can adsorb to 

particles. If irrigation and road spreading are long-term management practices, the frequency of 

impacts will likely be proportional to the frequency with which the practices are employed.

Liquid and solid residuals generated from the treatment, storage, and handling of hydraulic 

fracturing wastewater have highly concentrated waste constituents. This could increase the 

potential severity of impacts due to spills that reach surface water resources or leach to 

groundwater. Potential impacts from management of residuals can be lessened in frequency and 

severity through careful handling, adequate characterization (including TENORM content), and 

selecting an appropriate disposal method, including use of a landfill that can accept TENORM waste 

if needed.

8.6.3 Uncertainties

A full understanding of hydraulic fracturing wastewater management is limited by a lack of 

available data in several areas. First, it is difficult to assemble a complete national- or regional-level 

picture of wastewater volumes and the management practices used because the tracking and 

availability of data vary from state to state. Although some states provide well-organized and 

relatively thorough data, not all states collect or make such information available. It can be difficult 

to identify wastewater volumes specifically associated with hydraulic fracturing (as compared to all 
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8-74 

oil and gas production activities). Such data would be needed to place hydraulic fracturing 

wastewater in the broader context of all oil and gas wastewaters. It is also generally difficult to 

determine whether hydraulic fracturing wastewater is being injected under a given disposal well 

permit because the permit rarely identifies which production wells are contributing to the 

wastewater stream. Data are also generally difficult to locate for wastewater production volumes, 

the chemical composition and concentrations in wastewater, and the management and disposal 

strategies for residuals.

Up-to-date information on the volume of hydraulic fracturing wastewater disposed of via 

underground injection by state is not uniformly available. Without this information, it is difficult to 

assess whether disposal well capacity will become an issue in areas where hydraulic fracturing 

activity is expected to increase or where use of disposal wells may become restricted locally or 

regionally. 

For CWTs permitted to discharge to surface water, the ability to assess the potential effects of these 

discharges on drinking water resources is limited by the lack of effluent water quality data. Some 

monitoring data are required by the permit, but the list of monitored constituents may be limited. 

Selection of the appropriate water quality parameters to be monitored is critical to ensure that 

potentially problematic constituents are identified (e.g., chemicals associated with hydraulic 

fracturing fluids, maintenance chemicals, and degradation products of those chemicals). Some 

chemicals used in fracturing fluids are not disclosed, and analytical methods are lacking for some 

chemicals of concern and their degradation products.

Pollutant removal capabilities of the treatment facilities would also be valuable information to have, 

but this would require well-coordinated collection of both influent and effluent samples; this type 

of data is even less commonly available. In addition, the use of inappropriate analytical methods for 

the high TDS wastewater associated with hydraulic fracturing operations can complicate the use of 

available data. Methods used should be suitable for the highly complex matrix of contaminants 

encountered with oil and gas wastewater to have confidence in the results of chemical analyses. 

Monitoring of surface waters downgradient of discharges, such as screening with a TDS proxy (i.e., 

conductivity), would also help assess the frequency of impacts on receiving waters by hydraulic 

fracturing activities (including spills and discharges of wastewater). Such data can also give an 

estimation of the severity of those impacts. Other than a few studies in the Marcellus Shale region, 

these types of water quality data are lacking. Existing data are also limited regarding legacy effects, 

such as accumulation of contaminants in sediments at discharge points, soil accumulation due to 

application of de-icing brines or salts from wastewater treatment, and handling of wastewater 

treatment residuals. 

Assessing longer-term impacts on surface water quality from hydraulic fracturing activities in 

general is severely hampered by inadequate data. Bowen et al. (2015) state that available nationallevel databases are inadequate for addressing the question of whether there is evidence of nationallevel trends in surface water quality (as measured by specific conductivity and chloride) in areas 

where unconventional oil and gas production is taking place. Work by the Northeast-Midwest 

Institute and the USGS (Betanzo et al., 2016) was undertaken to explore the types and amounts of 
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8-75 

data needed to assess whether shale gas development activities contaminate surface water or 

groundwater in the Susquehanna River Basin. The focus was on longer-term cumulative impacts 

because detection of such impacts requires water quality monitoring. Detection of impacts (in 

either surface water or groundwater) requires a systematic monitoring approach that includes 

sampling at appropriately selected locations at an adequate frequency and duration and for a suite 

of water quality parameters to detect changes over time. Comparison sites without hydraulic 

fracturing activity are needed as well. The authors concluded that the data necessary to detect 

changes in surface water or groundwater due to hydraulic fracturing activities do not currently 

exist for the Susquehanna River Basin. 

8.6.4 Conclusions

Oil and gas operations in the United States generated an estimated 2.43 billion gal of wastewater 

per day (about 60 million bbls/day) in 2012 (Veil, 2015). This includes wastewater associated with 

hydraulic fracturing activities, although what portion of this oil and gas wastewater is attributable 

to hydraulic fracturing operations is difficult to estimate. Available information indicates that the 

majority of hydraulic fracturing wastewater is injected into Class IID wells regulated under the UIC 

Program. In the Marcellus Shale region in Pennsylvania, this option is limited, and the majority of 

wastewater is reused (either with or without treatment) for new hydraulic fracturing jobs. 

Hydraulic fracturing wastewater may also be treated at a CWT and discharged by the CWT to 

surface water or to a POTW. In the western United States, wastewater is used in other ways (e.g., 

livestock watering) if water quality allows. Wastewater is also sent to evaporation ponds for 

disposal or stored on-site or in centralized pits or impoundments prior to final disposal or reuse. 

Impacts on drinking water resources have resulted from discharges of inadequately treated 

wastewater and from leaks, spills, and percolation associated with pits. Other mechanisms for 

impacts include improper handling of treatment residuals or pit and tank sludges as well as 

leaching and runoff associated with other wastewater management practices. The impacts related 

to pits and residuals/sludges affect both surface water and groundwater; unlined pits or those with 

compromised liners present a particular concern (see Chapter 7 for additional discussion of spills). 

The constituents that have received the greatest attention in the literature include TDS, DBP 

precursors (especially bromide), and radium, although hydraulic fracturing wastewater can contain 

elevated concentrations of a number of organic and inorganic constituents of concern. Regardless of 

the management option utilized, if the wastewater is not thoroughly characterized or sampling is 

not conducted for analytes of concern, the severity and frequency of the impacts will be unknown 

or unquantified. The nature and volume of wastewater generated through hydraulic fracturing 

activities necessitate careful consideration of handling, treatment, and ultimate reuse or disposal to 

ensure that water resources are not adversely impacted. There is also a need for reliable and 

consistent waste generation data collection and reporting, improved efforts to characterize 

wastewater quality (both treated and untreated), and systematic monitoring efforts to be able to 

detect impacts on drinking water resources.
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Chapter 9. Identification and Hazard 

Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle

Abstract 

This chapter identifies chemicals associated with hydraulic fracturing and provides an overview of the 

potential human health effects associated with these chemicals, as well as variables that could affect 

chemical occurrence in drinking water. The EPA has identified 1,606 chemicals associated with 

hydraulic fracturing, including 1,084 chemicals that are used in hydraulic fracturing fluid and 599

chemicals that have been detected in produced water. There is some uncertainty surrounding this 

chemical list, as it does not include a subset of chemicals that are classified as confidential business 

information, and because understanding of produced water composition is constrained by limitations of 

analytical chemistry as well as site-specific variations in the geochemistry of hydraulically fractured 

rock formations. 

The EPA used selected federal, state, and international sources of toxicological data to identify toxicity 

values that can be used to support risk assessment for these chemicals, including chronic oral reference 

values (RfVs) for noncancer effects and oral slope factors (OSFs) for cancer. Chronic oral RfVs or OSFs 

were available for 173 (11%) of the total 1,606 chemicals. Health effects associated with chronic oral 

exposure to these chemicals include carcinogenicity, neurotoxicity, immune system effects, changes in 

body weight, changes in blood chemistry, liver and kidney toxicity, and reproductive and developmental 

toxicity. 

For the majority of chemicals that lack chronic oral RfVs or OSFs, risk assessors will have to turn 

towards other sources of toxicological information that may have greater uncertainty than RfVs and 

OSFs, including quantitative structure-activity relationship (QSAR) models or additional data from the 

EPA’s Aggregated Computational Toxicology Resource (ACToR) database. To understand whether 

specific chemicals can affect human health through their presence in drinking water, data on chemical 

concentrations in drinking water are needed. In the absence of these data, a preliminary analysis of 

relative hazard potential for drinking water resources can be conducted using the multi-criteria decision 

analysis (MCDA) approach outlined in this chapter. The MCDA combines data on toxicity, occurrence, 

and physicochemical properties for selected subsets of chemicals and was used in this chapter to 

highlight several chemicals that may be more likely than others to reach drinking water resources and 

present a health hazard. 

Overall, while evidence suggests that hydraulic fracturing has the potential to impact human health, the 

actual human health implications are not well understood or well documented. Given that chemicals in 

hydraulic fracturing fluids and produced water are likely to vary on a regional basis and even between 

individual wells, the materials presented in this chapter are best applied for risk assessment and risk 

management decision-making at the local level.
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9. Identification and Hazard Evaluation of Chemicals

across the Hydraulic Fracturing Water Cycle

9.1 Introduction 

In this chapter, we present and integrate what is known about chemicals in the hydraulic fracturing 

water cycle, and provide an initial assessment of the potential for these chemicals to impact human 

health. The discussion is focused on the availability of toxicity values and qualitative assessments 

that can be used to inform the risk assessment of these chemicals for oral exposure via drinking 

water—in particular, the available noncancer oral reference values (RfVs), cancer oral slope factors 

(OSFs), and qualitative cancer classifications.1,2,3

 Public health impacts will depend upon both the 

inherent toxicity of these chemicals and the potential for human exposure. We highlight several 

field studies that have detected hydraulic fracturing-related chemicals in drinking water resources, 

and discuss properties of chemicals related to environmental fate and transport that could affect 

their potential impact on drinking water resources. To the extent information was available to do 

so, knowledge of toxicological and chemical properties was combined to illustrate a preliminary 

analysis of the relative hazard that these chemicals could pose to drinking water resources. The 

data are presented in this chapter as follows:

Section 9.2 provides a brief background on public health concerns surrounding hydraulic fracturing 

and unconventional oil and gas extraction, which have been highlighted in several recent studies. 

Section 9.3 discusses how information sources were used to create a list of chemicals used in or 

detected in various stages of the hydraulic fracturing water cycle. The consolidated chemical list 

includes chemicals reportedly added to hydraulic fracturing fluids in the chemical mixing stage, as 

well as fracturing fluid chemicals, formation chemicals, or their reaction products that may be 

carried in produced water. 

Section 9.4 provides an overview of the methods that were used for gathering information on 

toxicity and physicochemical properties for all chemicals identified in Section 9.3, and outlines the 

number of chemicals that had available data on these properties. For toxicological data, the primary 

focus is on chronic oral RfVs, OSFs, and qualitative cancer classifications from selected data sources 

that met the EPA’s criteria for inclusion in this assessment. This section also discusses other 

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 (U.S. EPA, 2011f). In the context of this report, the term RfV refers to 

reference values for non-cancer effects occurring via the oral route of exposure and for chronic durations, except where 

noted.

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 (U.S. EPA, 2011f). 

3 Qualitative cancer classifications are a system used for the hazard identification of probable carcinogens, in which 

human data, animal data, and other supporting evidence are combined to characterize the weight of evidence (WOE) 

regarding the potential of an agent to cause cancer in humans. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-4 

potential sources of toxicity information: the use of quantitative structure-activity relationship 

(QSAR) modeling to estimate chemical toxicity, as well as the availability of toxicological 

information on the EPA’s Aggregated Computational Toxicology Resource (ACToR) database. A 

brief description of other potential tools and approaches that may be used by stakeholders for sitespecific evaluation of chemical hazards, but are not used in this report, is provided in Appendix G.

Section 9.5 describes the potential hazards of subsets of chemicals identified as being of interest in 

previous chapters of this report. This includes chemicals in hydraulic fracturing fluid (Chapter 5); 

organic chemicals, inorganic chemicals, and pesticides detected in produced water (Chapter 7); 

stray gas, such as methane (Chapter 6); and disinfection byproducts (DBPs) formed from 

constituents of hydraulic fracturing fluid wastewaters (Chapter 8). We discuss instances in which 

these chemicals have been detected in drinking water resources in areas of hydraulic fracturing 

activity, and provide an overview of the available toxicological information for these chemicals.

Section 9.6 uses a multi-criteria decision analysis (MCDA) framework to provide a preliminary 

analysis of the potential hazards of chemicals used in hydraulic fracturing fluids or detected in 

produced water. The MCDA framework is used to integrate data on chemical toxicity, occurrence, 

and physicochemical properties. In this context, occurrence and physicochemical properties are 

used as metrics to estimate the likelihood that a chemical will reach and impact drinking water 

resources. Chemicals considered in these hazard evaluations include a subset of chemicals 

identified in the EPA FracFocus 1.0 project database, as well as a subset of organic chemicals that 

have been detected in produced water.

This chapter is not a human health risk assessment. As shown in Text Box 9-1, risk assessment 

consists of four basic steps: hazard identification, dose-response assessment, exposure assessment, 

and risk characterization. This chapter provides an overview of hazard identification and doseresponse assessment for these chemicals, but lacks information to fully characterize exposure and 

risk. In Section 9.5, we highlight instances in which these chemicals have been detected in drinking 

water resources, but these data are only available for a small number of chemicals. The MCDA 

approach in Section 9.6 provides a method for integrating data on toxicity and exposure potential, 

but should be considered only as a preliminary analysis, and should not be used in place of local 

data on chemical exposure. 

This chapter is focused on potential human health hazards of chemicals for the oral route of 

exposure (drinking water); therefore, the toxicological properties and physicochemical ranking 

metrics described herein do not necessarily apply to other routes of exposure that may occur with 

these chemicals, such as inhalation or dermal exposure. We additionally note that this analysis is 

focused on individual chemicals, rather than mixtures of chemicals used as additives. 

In general, characterizing chemicals and their properties on a national scale is challenging and the 

use and occurrence of chemicals is likely to differ between geological basins and possibly on a wellto-well basis (Chapters 5 and 7). Therefore, for the protection of human health at the local level, 

chemical hazard evaluations are best conducted on a regional or site-specific scale. This level of 

analysis is outside the scope of this report; however, the methods of hazard evaluation presented 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-5 

here can also be applied on a regional or site-specific scale in order to identify chemicals that may 

present a potential human health hazard.

Text Box 9-1. Applying Toxicological Data for Human Health Risk Assessment. 

Understanding potential human health impacts requires knowledge not only of the inherent toxicity of the 

chemicals found in contaminated environmental media, but also of the potential for exposure to these 

chemicals. The process of evaluating the nature and probability of such impacts is known as human health 

risk assessment. Overall, human health risk assessment includes four basic steps (U.S. EPA, 2016a): 

1. Hazard identification: Examining whether a chemical has the potential to cause harm to humans and/or 

ecological systems, and if so, under what circumstances.

2. Dose-response assessment: Examining the numerical relationship between exposure and effects.

3. Exposure assessment: Examining what is known about the frequency, timing, and levels of contact with a 

chemical.

4. Risk characterization: Examining how well the data support conclusions about the nature and extent of 

risk from exposure to a chemical. Information from the hazard identification, dose-response assessment, and 

exposure assessment are summarized and integrated into quantitative and qualitative expressions of risk.

The RfVs and OSFs compiled by the EPA in this study pertain to the first two steps of human health risk 

assessment: identifying chemicals that have the potential to affect human health (hazard identification), and 

characterizing the exposure levels at which those effects occur (dose-response assessment). These toxicity 

values may be used in combination with site-specific chemical exposure information (exposure assessment) 

in order to evaluate potential human health risks (risk characterization). Qualitative cancer classifications 

characterize the weight of evidence regarding the potential for a chemical to cause cancer, and therefore 

provide additional information that can be used for hazard identification.

Toxicity information spans a wide range with respect to extent, quality and reliability. The RfVs, OSFs, and 

qualitative cancer classifications compiled in this study are those identified by the EPA as being of the highest 

quality and reliability, per the criteria discussed in this chapter. The QSAR-based toxicity estimates discussed 

in this chapter are considered to be lower on the continuum of quality and reliability, but may provide useful 

information pertaining to hazard identification and dose-response assessment when a chemical does not 

have an RfV or OSF available. The EPA’s ACToR database provides an aggregation of a wide range of 

toxicological data that may also be useful for supporting the risk assessment of these chemicals. This chapter 

provides information on whether a chemical has data available from ACToR; however, it is beyond the scope 

of this report to evaluate the quality and reliability of data for these chemicals within ACToR, or to provide 

guidance on how the data within ACToR should be used to support human health risk assessment.

9.2 Overview: Hydraulic Fracturing and Potential Impacts on Human Health

As discussed in the previous chapters of this assessment, a variety of chemicals are associated with 

the hydraulic fracturing water cycle. Chemicals are added to hydraulic fracturing fluids at the 

chemical mixing stage (Chapter 5), and then injected into the well (Chapter 6). These chemical 

additives may return to the surface in produced water, along with chemicals from the formation 

(Chapter 7). The chemicals in produced water may persist in wastewater effluents, with some 

constituents contributing to the formation of disinfection byproducts in treated wastewater 

(Chapter 8). Through events such as large volume spills (Figure 9-1), mechanical integrity failures, 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-6 

hydraulic fracturing directly into groundwater resources, or discharge of inadequately treated 

hydraulic fracturing wastewater, there are specific instances in which these chemicals have been 

demonstrated to enter drinking water resources. Thus, there is potential for human exposure to 

these chemicals, and the potential for adverse human health effects resulting from exposure.

Figure 9-1. Fate and transport schematic for a hydraulic fracturing-related spill or release. 

Multiple authors have noted with the recent increase in hydraulic fracturing operations there may 

be an increasing potential for significant public health and environmental impacts (Goldstein et al., 

2014; Finkel et al., 2013; Korfmacher et al., 2013; Weinhold, 2012). These concerns have been 

highlighted in several recent studies. An epidemiological study in Colorado demonstrated 

residential proximity of pregnant mothers to natural gas wells is associated with an increased 

incidence of congenital heart defects, and, to a lesser extent, neural tube malformations (Mckenzie 

et al., 2014). A similar study in Pennsylvania found pregnant mothers living closer to 

unconventional natural gas wells were more likely to have infants that were small for gestational 

age, with lower birth weights compared to infants from mothers living farther from wells (Stacy et 

al., 2015). Residential proximity to natural gas wells in the Marcellus Shale is associated with an 

increase the number of self-reported health symptoms, particularly upper respiratory and dermal 

symptoms (Rabinowitz et al., 2015), chronic rhinosinusitis, migraine headache, and fatigue 

symptoms (Tustin et al., 2016). Laboratory studies have found that endocrine disrupting activity 

measured using in vitro bioassays may be elevated in surface and groundwater at known hydraulic 

fracturing spill sites (Kassotis et al., 2014) and in surface water downstream from a hydraulic 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-7 

fracturing wastewater injection facility (Kassotis et al., 2016). Although none of these studies 

demonstrate a direct effect of hydraulic fracturing activity on human health, and none of the 

epidemiological studies provided measures of individual or population level exposures or 

differentiated between drinking water contamination and other potential routes of exposure (e.g., 

air pollution), all are suggestive of a relationship between unconventional oil and gas development 

and adverse health outcomes. 

Previous chapters of this report have identified cases in which contamination of drinking water 

resources could clearly be linked to hydraulic fracturing activity. For example, equipment failure 

and human error have led to spills of hydraulic fracturing fluids across the country and have 

affected the quality of drinking water resources (U.S. EPA, 2015m; Brantley et al., 2014; COGCC, 

2014; Gradient, 2013). Other studies highlighted in previous chapters provide indirect evidence 

hydraulic fracturing activity has contaminated surface water or groundwater. For example, two 

recent studies in the Marcellus Shale detected known hydraulic fracturing-related chemicals in 

nearby groundwater wells, and used multiple lines of evidence to link the origin of these chemicals 

to hydraulic fracturing activity (Drollette et al., 2015; Llewellyn et al., 2015). 

There have also been documented impacts on ecological receptors. In Knox County, Kentucky, 

retention pits holding hydraulic fracturing flowback fluids overflowed into Acorn Fork Creek during 

the development of four natural gas wells, causing a decrease in pH and increase in conductivity.1

Organics and metals including iron and aluminum formed precipitates in the stream, and fish and 

aquatic invertebrates were killed or displaced in a 2.7 km length of the stream affected by the 

release (Papoulias and Velasco, 2013). A field report from the Pennsylvania Department of 

Environmental Protection (PADEP) described a leak in an overland pipe carrying a mixture of 

flowback and freshwater between two impoundments that impacted a 0.6 km length of a stream, in 

which 168 fish and 6 salamanders were killed (PA DEP, 2009b). 

In some instances, chemical concentrations in drinking water resources impacted or potentially 

impacted by hydraulic fracturing activity exceeded their respective primary or secondary 

maximum contaminant level (MCL), or health advisory levels provided by the EPA’s National 

Primary Drinking Water Regulations (NPDWRs) and Drinking Water Standards and Health 

Advisories (DWSHA) tables (U.S. EPA, 2012b), indicating that these chemicals are present at levels 

that may impact human health.2 Examples will be discussed in Section 9.5. These studies generally 

did not indicate the contaminated water was used directly for human consumption, so it is not clear 

that people are being exposed to these chemicals at these levels. Nevertheless, these studies 

indicate that hydraulic fracturing activity may contribute to the entry of chemicals into drinking 

water resources at potentially harmful levels.

 

1 “Flowback” refers to fluids containing predominantly hydraulic fracturing fluid that return from a well to the surface. 

Flowback is a type of produced water. See Chapter 7 for more details. 

2 Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as 

close to the maximum contaminant level goal (MCLG) as feasible using the best available analytical and treatment 

technologies and taking cost into consideration. MCLs are enforceable standards. The MCLG is a non-enforceable health 

benchmark goal which is set at a level at which no known or anticipated adverse effect on the health of persons is 

expected to occur and which allows an adequate margin of safety (U.S. EPA, 2012b). 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Risk assessment and risk management decisions will be informed by scientific information on the 

toxicity of chemicals in hydraulic fracturing fluid and wastewater. The U.S. House of 

Representatives’ Committee on Energy and Commerce Minority Staff released a report in 2011 

noting that more than 650 products (i.e., chemical mixtures) used in hydraulic fracturing contain 29 

chemicals that are either known or possible human carcinogens or are currently regulated under 

the Safe Drinking Water Act (House of Representatives, 2011). More recently, several studies have 

performed a reconnaissance of toxicity and/or physicochemical property data for specific subsets 

of chemicals used in hydraulic fracturing fluids (Elliott et al., 2016; Wattenberg et al., 2015; 

Stringfellow et al., 2014; Colborn et al., 2011), and have provided discussion on the hazards 

inherent to these chemicals. In all cases, authors reported toxicity data was not available for many 

of the chemicals assessed in these studies, with some studies indicating significant data gaps. For 

instance, Wattenberg et al. (2015) evaluated 168 chemicals commonly used in hydraulic fracturing 

fluids in North Dakota, and reported that 59% did not have chronic toxicity data available, and 35% 

did not have acute toxicity data available. Elliott et al. (2016) performed a systematic evaluation of 

reproductive and developmental toxicity for 1021 chemicals used in hydraulic fracturing fluids or 

detected in wastewater, and found this toxicity information was lacking for 76% of these chemicals. 

Overall, while combined evidence suggests hydraulic fracturing has the potential to impact human 

health via contamination of drinking water resources, the actual public health impacts are not well 

understood and not well documented. Available information indicates there are many chemicals 

within the hydraulic fracturing water cycle that are known to be hazardous to human health, as 

well as hundreds of chemicals for which toxicological data is limited or unavailable. 

In this chapter, our primary goal is to evaluate the availability of toxicity data for a list of chemicals 

used in hydraulic fracturing fluids or present in produced water, focusing primarily on toxicity 

values from sources that meet the criteria for inclusion in this assessment, and to highlight 

chemicals that may pose human health hazards. 

9.3 Identification of Chemicals Associated with the Hydraulic Fracturing Water 

Cycle

As the initial step towards evaluating the hazards of chemicals in the hydraulic fracturing water 

cycle, the EPA compiled a list of chemicals used in or released by hydraulic fracturing operations 

across the country.1 This section describes the compilation of that list. This consolidated list 

includes a total of 1,606 chemicals, and can be broken down into two sublists: (1) a list of chemicals 

used in hydraulic fracturing fluids, and (2) a list of chemicals detected in produced water from 

hydraulically fractured wells (Text Box 9-2). 

This list demonstrates the range and variety of chemicals that are associated with the hydraulic 

fracturing industry. These chemicals should not be considered unique to the hydraulic fracturing 

 

1 We use the word “chemical” to refer to any individual chemical or chemical substance that has been assigned a CASRN 

(Chemical Abstracts Service Registry Number). A CASRN is a unique identifier for 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 C9 to C16 hydrocarbons). For simplicity, we refer to both pure 

chemicals and chemical substances that are mixtures, which have a single CASRN, as “chemicals.”
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-9 

industry; many of the chemicals used in hydraulic fracturing fluids are widely used industrial 

chemicals, and many of the chemicals in produced water are naturally occurring. Although this list 

represents the best information available to the EPA at the time of the assessment, it should not be 

considered comprehensive. It is likely that, as industry practices change, chemicals may be used or 

detected that are not included on these lists. Some additional limitations to this chemical list are 

described in the subsections below. 

Text Box 9-2. The EPA’s List of Chemicals Identified in Hydraulic Fracturing Fluids and/or 

Produced Water.

This chemical list progressed through multiple iterations as the EPA’s hydraulic fracturing study was 

developed, culminating in the list of 1,606 chemicals presented in this report. 

The first iteration of this chemical list was published in the interim progress report (U.S. EPA, 2012h), and 

included 1,026 chemicals that were identified from ten sources of information. Seven of these information 

sources were documents from federal and state governmental units—including the EPA (U.S. EPA, 2011a, e, 

2004a; Material Safety Data Sheets), the U.S. House of Representatives (House of Representatives, 2011), the 

New York State Department of Environmental Conservation (NYSDEC, 2011), and the Pennsylvania 

Department of Environmental Protection (PA DEP, 2010a)—which obtained data directly from industry. This 

includes a list of chemicals provided directly to the EPA by nine well operating companies, representing 

chemicals used in hydraulic fracturing fluids between 2005 and 2009, and a list of chemicals detected by 

these companies in produced water from 81 wells. The remaining three sources are as follows: a technical 

report prepared by the Gas Technology Institute for the Marcellus Shale Coalition, which is a drilling industry 

trade group (Hayes, 2009); a peer-reviewed journal article by Colborn et al. (2011); and the FracFocus 

Chemical Disclosure Registry, which is a national hydraulic fracturing chemical registry developed by the 

Ground Water Protection Council and the Interstate Oil and Gas Compact Commission (GWPC, 2012). 

In the external review draft of the EPA’s hydraulic fracturing study report (U.S. EPA, 2015d), this chemical list 

was updated to 1,173 chemicals. The updated chemical list includes the 1,026 chemicals published in the 

progress report, along with additional chemicals that were identified in the EPA FracFocus 1.0 report (U.S. 

EPA, 2015a). 

For the final version of this assessment, the list has again been updated to include additional chemicals in 

produced water, which were identified from 18 additional literature sources. The final list includes a total of 

1,606 chemicals that have been reported as used in hydraulic fracturing fluids or detected in produced water. 

The complete list of sources used to compile the final chemical list is provided in Appendix Table H-1. To the 

extent possible, after chemicals were identified from the sources in Table H-1, the EPA verified the identity of 

the chemicals used in hydraulic fracturing fluids and detected in produced water of hydraulically fractured 

wells as described in Appendix Section H.1.

9.3.1 Chemicals Used in Hydraulic Fracturing Fluids

Of the 1,606 total chemicals, the EPA identified 1,084 chemicals as being used in hydraulic 

fracturing fluids. This list was originally introduced in Chapter 5 of this assessment (Section 5.4), 

which describes some of the chemical classes and their purpose, and identifies the most frequently 

used chemicals. This list of 1,084 chemicals is shown in Appendix Table H-2.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Although a total of 8 sources were used to identify the list of chemicals used in hydraulic fracturing 

fluids, only one source—the EPA analyses based on disclosures submitted to FracFocus—had 

sufficient information for estimating the frequency with which these chemicals were used (Section 

5.4, Text Box 5-1). 1Of the 1,084 chemicals, 688 were identified in the EPA FracFocus 1.0 report

(U.S. EPA, 2015a).2 Frequency of use for individual chemicals ranged from low (480 chemicals on 

the list were reported in less than 1% of disclosures nationally) to very high (methanol was 

reported in 73% of disclosures nationally). 

As discussed in Chapter 5, this list provides valuable information on the chemicals used in hydraulic 

fracturing fluids, but should not be considered complete. For example, in the analysis of the 

disclosures submitted to the FracFocus 1.0 registry, the EPA was only able to assign standardized 

chemical names to 65% of ingredient records. The remaining 35% of ingredient records did not 

have valid CASRNs and were excluded from the analysis because they could not be assigned a 

standardized chemical name (U.S. EPA, 2015a). In a more recent analysis of data reported to the 

FracFocus registry through April 2015, Konschnik and Dayalu (2016) found that 80% of chemicals 

had valid CASRN. That analysis identified an additional 263 CASRNs that are not on the EPA’s list of 

chemicals used in hydraulic fracturing fluids (Dayalu and Konschnik, 2016). 

Industry use of CBI is another factor that likely limits the completeness of this chemical list and 

introduces uncertainty. For example, companies submitting to FracFocus 1.0 were not required to 

disclose chemicals claimed as CBI. EPA determined that approximately 70% of the disclosures 

submitted to FracFocus 1.0 contain at least one CBI chemical, and for those disclosures, the average 

number of CBI chemicals per disclosure was five. Overall, 11% of ingredients were reported to 

FracFocus 1.0 as CBI (U.S. EPA, 2015a). Konschnik and Dayalu (2016) report a 5.6% increase in the 

number of CBI ingredients, as well as an increase in the number of disclosures reporting the use of 

at least one CBI ingredient (Section 5.4; Text Box 5-2). 

Although FracFocus disclosures do not provide the name or CASRN of CBI chemicals, the chemical 

family is sometimes provided. The EPA determined that 79% of CBI ingredient records submitted 

to FracFocus 1.0 had enough information to partially define the chemical and assign it to a chemical 

family (U.S. EPA, 2015a). This resulted in the designation of 448 standardized chemical families to 

which these chemicals could be assigned. The most common standardized chemical families for CBI 

ingredients were oxyalkylated alcohol (4.7% of CBI ingredient records), petroleum distillates (4.0% 

of CBI ingredient records), and quaternary ammonium compounds (3.6% of CBI ingredient 

records) (U.S. EPA, 2015a) (Appendix Table B-1). These standardized chemical family designations 

are not discussed further in this chapter, but may be useful for site-specific risk assessment, as they 

 

1 The FracFocus frequency of use data presented in this chapter is based on 35,957 FracFocus disclosures that were 

deduplicated, within the study time period (January 1, 2011 to February 28, 2013), and with ingredients that have a valid 

CASRN. In the interest of including as many chemicals as possible, this analysis includes chemicals that do not have valid 

concentration data. The 692 chemicals includes 16 chemicals that are listed as being used as proppants.

2 EPA analyses based on disclosures submitted to FracFocus identified 692 unique CASRN. Of these 692, we determined 

that 4 chemicals are listed under two different CASRN (indicated in the footnote of Appendix Table H-2). Frequency of use 

data is therefore available for 688 chemicals that were included on EPA’s list of chemicals in hydraulic fracturing fluids.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-11 

may provide insight into potential physicochemical properties and toxicity of CBI chemicals used at 

a particular site.

9.3.2 Chemicals Detected in Produced Water

Of the 1,606 total chemicals, the EPA identified 599 as having been detected in produced water. 

Included among these chemicals are naturally occurring organic compounds, metals, radionuclides, 

industrial chemicals, and pesticides. These chemicals were originally introduced in Chapter 7 of this 

assessment, and were compiled from a total of 21 sources. Seventy-seven of the total 599 chemicals 

in produced water were also identified by at least one of the sources in Appendix H as being used in 

hydraulic fracturing fluid. However, the EPA used different sets of sources to identify chemicals 

used in hydraulic fracturing fluids versus those detected in produced water, and there is not a 

matched comparison between the chemicals used in hydraulic fracturing fluids and returned in 

produced water at each particular well. Therefore, it is difficult to draw direct comparisons 

between these two chemical lists, or to use these lists to draw conclusions on the persistence of 

chemicals in produced water from hydraulically fractured wells. The list of 599 chemicals identified 

in produced water is shown in Appendix Table H-4.

Although this list provides useful information on the chemical composition of produced water, it is 

not likely that the data sources were able to capture all of the chemicals present. Chemicals and

their metabolites may go undetected in produced water because they were not targeted in the 

analytical protocols, they were below the limit of detection, or because no standard analytical 

method exists. Additionally, as discussed in Chapter 7, the composition and concentration of 

chemicals in produced water will differ depending upon factors like the geology of the formation, 

the chemicals used for hydraulic fracturing, and the amount of time that has elapsed since hydraulic 

fracturing. There is therefore expected to be a high degree of local and temporal variation in these 

chemicals, and there was not sufficient information to determine the frequency with which these 

chemicals were detected on a national basis. 

Concentration data in produced water are available for 175 of these 599 chemicals (Appendix E), 

including inorganic contributors to salinity (Appendix Tables E-4 and E-5), metals (Appendix 

Tables E-6 and E-7), radioactive constituents (Appendix Table E-8), and organic constituents 

(Appendix Tables E-9, E-11, E-12, and E-13). The remaining chemicals were detected in produced 

water, but concentration was not reported. For these chemicals with concentration data, the 

measured concentrations spanned several orders of magnitude. For instance, for organic chemicals 

in produced water from the Marcellus shale formation (Appendix Table E-11), average or median 

measured concentrations ranged from 2.7 μg/L for N-nitrosodiphenylamine to 400 μg/L for carbon 

disulfide. 

9.4 Toxicological and Physicochemical Properties of Hydraulic Fracturing 

Chemicals

As the next step towards evaluating the hazards of chemicals in the hydraulic fracturing water 

cycle, toxicological and physicochemical data were collected as available for each of the chemicals 

identified in Appendix H. This section describes the compilation of these data, and discusses the 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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extent to which toxicological and physicochemical property data are available for this list of 

chemicals.

The primary focus of the toxicological analysis in this chapter is on the availability of chronic oral 

RfVs and OSFs from sources that met the EPA’s criteria for inclusion in this study. Qualitative cancer 

classifications were also identified from these sources when available. This is not intended to be an 

exhaustive compilation of toxicity values for this chemical list. Rather, it is intended to be a 

reconnaissance of high-quality toxicological information that met the EPA’s criteria for inclusion in 

this study. If a source of RfVs, OSFs, or qualitative cancer classifications was not included here, that 

only means that it did not meet the criteria for the purposes of the EPA’s study, which are described 

in this chapter in Section 9.4.1.

Section 9.4.1 describes the criteria used to identify and select RfVs, OSFs, and qualitative cancer 

classifications, and describes the availability of these toxicological data for the chemicals on the 

EPA’s list of hydraulic fracturing-related chemicals. The next two sections describe additional 

sources of toxicological information, which may be useful for hazard evaluation when chronic oral 

RfVs and OSFs are not available: Section 9.4.2 describes the use of a QSAR model to estimate 

chronic oral toxicity, and Section 9.4.3 describes the availability of additional toxicological 

information on the EPA’s ACToR database. Section 9.4.4 describes other available software tools 

and approaches that may be used by stakeholders for site-specific risk assessment, but are not 

utilized in this report. Section 9.4.5 discusses the methods used in this report to generate 

physicochemical property data, and presents the availability of physicochemical property data for 

the chemicals on the EPA’s list. A brief overview of the toxicity values discussed in the chapter is 

presented in Text Box 9-3. 

As a resource that can be used to support risk assessment at hydraulic fracturing sites, all of the 

selected RfVs, OSFs, qualitative cancer classifications, QSAR-based toxicity estimates, and 

physicochemical property data described in this chapter will be compiled into an electronic 

database that will be publicly accessible via the EPA’s website. Additionally, the EPA’s compilation 

of toxicity data for this chemical list has been discussed in two recent manuscripts, both of which 

focused on the list of 1,173 chemicals that was presented in the external review draft of the EPA’s 

hydraulic fracturing study report (U.S. EPA, 2015d). Yost et al. (2016b) describes the compilation of 

RfVs and OSFs for the list of 1,173 chemicals. Yost et al. (2016a) describes the use of a QSAR model 

to estimate toxicity for the list of 1,173 chemicals. 

Text Box 9-3. Toxicity Values for Hydraulic Fracturing-Related Chemicals. 

Here we provide a brief description of the toxicity values that are presented in this chapter, and how they 

should be interpreted and used to evaluate chemical hazards. Formal definitions of these terms are footnoted 

in the chapter and can also be found in the glossary (Appendix J).

Reference value (RfV): RfVs are health-protective values, which describe the dose of a chemical that is likely 

to be without an appreciable risk of adverse health effects. In general, lower RfVs indicate greater toxicity; 

however, comparison of RfVs among a set of chemicals requires careful consideration. RfVs are developed by 

considering the full database of epidemiological and experimental studies available for a particular chemical. 

(Text Box 9-3 is continued on the following page.) 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Text Box 9-3 (continued). Toxicity Values for Hydraulic Fracturing-Related Chemicals. 

These data are used to identify the critical effect, which is the first adverse effect, or its known precursor, that 

occurs as the dose rate increases (U.S. EPA, 2011f). An RfV is then derived by starting with a quantitative 

point of departure (POD), which is the toxicological dose-response point that marks the beginning of a lowdose extrapolation for the critical effect, and applying uncertainty factors (UFs) to derive a value for the 

protection of human health. UFs are applied to account for 5 areas of uncertainty: (1) intraspecies variability; 

(2) interspecies uncertainty; (3) extrapolation from a subchronic study; (4) extrapolating from a noobserved-adverse-effect level (NOAEL); and (5) deficiencies in the database. A UF of 1, 3, or 10 can be applied 

for any of these areas of uncertainty depending upon the amount and/or type data available, up to a 

maximum total UF of 3,000 (U.S. EPA, 2002). Thus, a chemical with a low RfV may reflect high uncertainty in 

the value, and not necessarily the toxicity of the chemical. Chemicals with a lower total UF generally have 

more reliable and robust health effect information. 

Oral slope factor (OSF): An OSF is a measure of the increased cancer risk from a lifetime oral exposure to an 

agent. Higher OSFs indicate greater carcinogenic potency. As with RfVs, OSFs are developed by considering

the full database of epidemiological and experimental studies for a particular chemical, and evaluating the

increase in cancer incidence as dose rate increases. OSFs should be considered in conjunction with qualitative 

cancer classifications, which characterize the weight of evidence regarding the agent’s potential to cause 

cancer in humans. 

No-observed-adverse-effect level (NOAEL): NOAEL is defined as the highest exposure level at which there 

are no biologically significant increases in the frequency or severity of adverse effect between the exposed 

population and its appropriate control; some effects may be produced at this level, but they are not 

considered adverse or precursors of adverse effects (U.S. EPA, 2011f). 

Lowest-observed-adverse-effect level (LOAEL): LOAEL is defined as the lowest exposure level at which 

there are biologically significant increases in the frequency or severity of adverse effects between the 

exposed population and its appropriate control group (U.S. EPA, 2011f). Lower LOAELs indicate greater 

toxicity. 

Maximum contaminant level (MCL): MCLs are the highest level of a contaminant that is allowed in drinking 

water. MCLs are set as close to the maximum contaminant level goal (MCLG) as feasible using the best 

available analytical and treatment technologies and taking cost into consideration. MCLs are enforceable 

standards. The MCLG is a non-enforceable health benchmark goal which is set at a level at which no known or 

anticipated adverse effect on the health of persons is expected to occur and which allows an adequate margin 

of safety (U.S. EPA, 2012b). Whereas RfVs, LOAELs, and NOAELs are expressed in terms of dose (mg/kg-day), 

MCLs are expressed in terms of the concentration of an agent in water (μg/L).

9.4.1 Reference Values (RfVs), Oral Slope Factors (OSFs), and Qualitative Cancer 

Classifications

For the purpose of this study, the EPA’s primary goal was to identify high quality toxicity values 

that met the criteria for inclusion in this study, and that could be used by stakeholders to support 

the risk assessment of hydraulic fracturing chemicals (Text Box 9-1). Briefly, the sources of RfVs, 

OSFs, and qualitative cancer classifications selected by the EPA for the purposes of this chapter met 

the following key criteria: 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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1. The body or organization generating or producing the peer-reviewed RfVs, peer-reviewed 

OSFs, or peer-reviewed qualitative assessment must be a governmental or 

intergovernmental body. 

2. The data source must include peer-reviewed RfVs, peer-reviewed OSFs, or peer reviewed 

qualitative assessments. 

3. The RfVs, OSFs, or qualitative assessments must be based on peer-reviewed scientific data.

4. The RfVs, OSFs, or qualitative assessments must be focused on protection of the general 

public.

5. The body generating the RfVs, OSFs, or qualitative assessments must be free of conflicts of 

interest with respect to the chemicals for which it derives reference values or qualitative 

assessments. 

These five criteria were developed by the EPA specifically for the purpose of this assessment, and 

are similar to the EPA Office of Solid Waste and Emergency Response (OSWER) recommendations 

for selecting toxicity values in conducting site-specific risk assessments (Regional Tier 3 Toxicity 

Value Workgroup, 2013; U.S. EPA, 2003a, 1989).1 The OSWER directives provide recommendations 

on the appropriate sources of toxicity values and toxicological information that should be 

considered in risk assessments, and were designed to recognize toxicity values that were developed 

using the best available scientific information. In addition, these directives outline references to 

various resources that provide guidance on the approaches and issues considered in deriving 

toxicity values. This type of information can be especially important in cases in which multiple 

sources of toxicity values need to be considered or evaluated, or in which a value needs to be 

developed. More detail on these criteria for selection and inclusion of data sources, as well as the 

full list of data sources that were considered for this study, are available in Appendix G. 

Table 9-1 shows the data sources that met these five criteria for the selection of toxicological 

information. The federal databases of RfVs or OSFs that met these criteria are the EPA’s Integrated 

Risk Information System (IRIS) database, the EPA’s Provisional Peer-Reviewed Toxicity Value 

(PPRTV) database, the EPA’s Human Health Benchmarks for Pesticides (HHBP) database, and the 

Agency for Toxic Substances and Disease Registry (ATSDR) database. IRIS and PPRTV also provide 

qualitative cancer classifications. One state source of RfVs and OSFs, the California Environmental 

Protection Agency (CalEPA) Toxicity Criteria Database, met the criteria for inclusion.2 One 

intergovernmental source of RfVs, the World Health Organization (WHO) International Programme 

on Chemical Safety (IPCS) Concise International Chemical Assessment Documents (CICAD), met the 

criteria for inclusion. The International Agency for Research on Cancer (IARC) and U.S. National 

Toxicology Program (NTP) Report on Carcinogens (RoC) also met the criteria and were used as 

additional sources for qualitative cancer classifications.

 

1 OSWER changed its name to the Office of Land and Emergency Management (OLEM), effective December 15, 2015.

2 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.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Table 9-1. Sources of selected RfVs, OSFs, and qualitative cancer classifications. 

Type of toxicological 

Information Data source Website

RfVs, OSFs, and 

qualitative cancer 

classifications

EPA Integrated Risk Information System (IRIS) 

database 

http://cfpub.epa.gov/ncea/iris/index.cf

m?fuseaction=iris.showSubstanceList

RfVs, OSFs, and 

qualitative cancer 

classifications

EPA Provisional Peer-Reviewed Toxicity Value 

(PPRTV) database 

http://hhpprtv.ornl.gov/index.html 

RfVs, OSFs EPA Human Health Benchmarks for Pesticides 

(HHBP) database 

http://iaspub.epa.gov/apex/pesticides/

f?p=HHBP:home

RfVs Agency for Toxic Substances and Disease 

Registry (ATSDR) Minimum Risk Levels 

http://www.atsdr.cdc.gov/toxprofiles/i

ndex.asp#bookmark05 

RfVs, OSFs California Environmental Protection Agency 

(CalEPA) Toxicity Criteria Database 

http://oehha.ca.gov/tcdb/index.asp

RfVs World Health Organization (WHO) 

International Programme on Chemical Safety 

(IPCS) Concise International Chemical 

Assessment Documents (CICAD)

http://www.who.int/ipcs/publications/

cicad/en/ 

Qualitative cancer 

classifications

National Toxicology Program (NTP) 13th

Report on Carcinogens (RoC)

https://ntp.niehs.nih.gov/pubhealth/

roc/

Qualitative cancer 

classifications

International Agency for Research on Cancer 

(IARC) Monographs 

http://monographs.iarc.fr/

In addition to the sources in Table 9-1, we also consulted the NPDWRs and DWSHA tables (U.S. EPA, 

2014a) to determine whether the chemicals on this list are regulated as drinking water 

contaminants. NPDWRs provide a list of MCLs, which are legally enforceable standards on the 

concentration of a substance that is allowed in drinking water under the Safe Drinking Water Act. In 

this chapter, MCL values are referenced as a means of comparison with reported concentration data 

where appropriate, and are reported in Appendix G and are compiled on the EPA’s electronic 

database for the hydraulic fracturing study. 

As noted above, this chapter focuses on the presentation and use of chronic RfVs. Chronic RfVs 

account for the potential that chemical exposure may be continuous, in low concentration, and over 

a longer duration. In the absence of reliable information on the potential duration of chemical 

exposure, this is a conservative assumption for the protection of human health. Chronic RfVs are 

also lower than less-than-chronic RfVs (e.g., acute, intermediate, or subchronic toxicity values), and 

are therefore more health protective. For these reasons, chronic RfVs are generally preferred as the 

default by risk assessors when conducting site-specific risk assessments (U.S. EPA, 1989) and when 

developing regional screening levels (U.S. EPA, 2016b). In contrast, acute RfVs are more applicable 

for single exposures and/or exposures of limited frequency to high concentration and shorter 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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durations (e.g., emergencies). However, the availability of less-than chronic RfVs are also presented 

for the sake of completeness.

Some chemicals had chronic oral RfVs or OSFs available from more than one of the sources in Table 

9-1. For these chemicals, we selected a single value for use in this chapter by applying a 

modification of the EPA OSWER Directives 9285.7-53 and 9285.7-86 tiered hierarchy of toxicity 

values (U.S. EPA, 2003a). A single RfV and/or OSF was selected from the sources in this order: 

HHBP (pesticides only), IRIS, PPRTV, ATSDR, and then other available values. The RfVs considered 

from these sources included chronic oral reference doses (RfDs) from the IRIS, PPRTV, and HHBP 

programs; chronic oral minimal risk levels (MRLs) from ATSDR; oral maximum allowable daily 

levels (MADLs) from CalEPA; and tolerable daily intakes (TDIs) from CICAD.1,2,3,4,5

Of the 1,606 chemicals identified by the EPA, 173 (11%) have federal, state, or international chronic 

oral RfVs and/or OSFs from sources listed in Table 9-1. Chronic oral RfVs and/or OSFs from the 

selected sources are lacking for the remaining 1,433 (89%) chemicals that the EPA has identified as 

associated with hydraulic fracturing. All available chronic oral RfVs and OSFs from the sources 

listed in Table 9-1 are tabulated in Appendix G. Chronic oral RfVs and OSFs for chemicals used in 

hydraulic fracturing fluids are listed in Appendix Tables G-1a through G-1c, and chronic oral RfVs 

and OSFs for chemicals reported in hydraulic fracturing flowback or produced water are listed in 

Appendix Tables G-2a through G-2c. The EPA’s IRIS database was the most abundant source of 

these toxicity values. 

Overall, when chemicals in hydraulic fracturing fluid and chemicals in produced water are 

considered separately, the availability of chronic RfVs and OSFs can be summarized as follows: 

• For the 1,084 chemicals used in hydraulic fracturing fluid, chronic oral RfVs or OSFs from 

at least one of the selected federal, state, and international sources were available for 98 

chemicals (9%). From the US federal sources alone, chronic oral RfVs were available for 81

chemicals (7%), and OSFs were available for 15 chemicals (1%).

 

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 that are 

pesticides. 

2 An RfD 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. It can be derived from a NOAEL, LOAEL, or benchmark dose, with uncertainty factors generally applied to reflect 

limitations of the data used. Generally used in the EPA's non-cancer health assessments (U.S. EPA, 2011f). This estimate is 

expressed in terms of mg/kg-day.

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), non-cancerous 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 (ATSDR, 2016). Chronic MRL: Duration of exposure is 365 days or longer. This 

estimate is expressed in terms of mg/kg-day.

4 An MADL is 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 (OEHHA, 2012). This estimate is 

expressed in terms of μg/day.

5 A TDI is 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 (WHO, 2015). This estimate is 

expressed in terms of mg/kg-day.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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• For the 599 chemicals reported in produced water, chronic oral RfVs or OSFs from at least

one of the selected federal, state, and international sources were available for 120

chemicals (20%). From the US federal sources alone, chronic oral RfVs were available for

97 chemicals (16%), and OSFs were available for 30 chemicals (5%).

In addition to these chronic values, some of the chemicals also have less-than-chronic oral RfVs 

available from the sources listed in Table 9-1. Subchronic, acute, or intermediate oral RfVs were 

identified for 103 chemicals on the consolidated list, including 60 chemicals used in hydraulic 

fracturing fluid (Appendix Table G-1d), and 73 chemicals reported in produced water (Appendix 

Table G-2d). The majority of these chemicals also had chronic oral RfVs available, although there 

were 10 chemicals that had less-than-chronic oral RfVs but lacked a chronic oral RfV. All of these 

less-than-chronic RfVs were found on the PPRTV, ATSDR, or HHBP databases. As stated above, 

chronic values more protective of human health than less-than-chronic values, and are generally 

preferred for risk assessment. These less-than-chronic values are therefore not discussed further in 

this report, but are provided in Appendix G as supporting information. 

Of the 1,606 chemicals identified by EPA, 207 (13%) had a qualitative cancer classification available 

from at least one of the sources listed in Table 9-1, which include IRIS, PPRTV, IARC, and RoC. These 

classifications are based on the weight-of-evidence (WOE) that a chemical causes cancer in humans. 

Of these 207 chemicals: 

• 21 were reported by at least one source to be a known carcinogen in humans.

• 66 were reported by at least one source to be a probable or possible carcinogen in

humans. These chemicals have been demonstrated to be carcinogenic in animal models,

but have limited or insufficient data to adequately assess carcinogenicity in humans.

• 117 were reported to be not classifiable as to carcinogenicity in humans. These chemicals

have been evaluated by at least one of these sources for their potential to cause cancer, but

had inadequate evidence from human exposure and animal studies to assess carcinogenic

potential.

• 3 were reported as not likely to be a human carcinogen.

The complete list of chemicals with qualitative cancer classifications are shown in Appendix Table 

G-1e (chemicals in hydraulic fracturing fluids) and Appendix Table G-2e (chemicals in produced

water).

9.4.2 Estimating Toxicity Using Quantitative Structure Activity Relationship (QSAR) 

Modeling

Because the majority of chemicals identified in this report do not have RfVs and/or OSFs from the 

selected sources, it is likely that risk assessors at the local and regional level may turn to alternative 

sources of toxicological information. One potential resource is QSAR modeling software, which is 

able to provide estimates or predictions of toxicity based on chemical structure. A key advantage to 

QSAR models is that they are able to rapidly and inexpensively estimate toxicity values for 

chemicals. A disadvantage is that QSAR estimates may be of higher uncertainty and less reliable 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-18 

than values generated using traditional toxicological methods. However, because they increase the 

available pool of toxicity information, QSAR estimates may be a useful resource for risk assessors 

that are faced with evaluating potential exposures to data-poor chemicals. 

A recent study by Yost et al. (2016a) used TOPKAT (Toxicity Prediction by Komputer Assisted 

Technology) QSAR software to estimate toxicity for the EPA’s list of chemicals used in hydraulic 

fracturing fluids or detected in produced water, and evaluated how effectively these toxicity 

estimates could be used to rank chemicals based on toxicity. The chemical list examined in this 

study is the list of 1,173 chemicals published in the external review draft of the EPA’s hydraulic 

fracturing study report (U.S. EPA, 2015d) (Text Box 9-2), so the full list of 1,606 chemicals was not 

assessed using the QSAR model. TOPKAT is commercially available QSAR software that is able to 

estimate the rat chronic oral lowest-observed-adverse-effect level (LOAEL), which is the LOAEL 

measured in a rat model following chronic oral exposure to a chemical.1

The authors of this study used TOPKAT to generate rat chronic oral LOAEL estimates for EPA’s list 

of chemicals, and assigned qualitative confidence scores (high, medium, or low) to each estimate 

based on parameters reported by the model. The authors then examined a list of 48 chemicals that 

had both a high-confidence TOPKAT LOAEL estimate and a chronic oral reference dose (RfD) from 

EPA’s IRIS database. The authors ranked these 48 chemicals from most toxic to least toxic based on 

either TOPKAT LOAEL estimate or on IRIS chronic oral RfD, and then used Spearman rank 

correlation to examine the similarity between these chemical rankings.

Of the 1,173 hydraulic fracturing chemicals, TOPKAT was able to generate toxicity estimates for 

515 (44%) of the chemicals, including 453 chemicals that are used in hydraulic fracturing fluids, 

and 86 chemicals that have been detected in produced water. The authors found a strong and 

statistically significant correlation between chemical rankings based on high-confidence TOPKAT 

LOAEL estimates and on IRIS chronic oral RfDs, indicating that high-confidence TOPKAT LOAEL 

estimates can effectively be used to rank chemicals based on toxicity when experimentally derived 

toxicity values are not available. Overall, TOPKAT LOAEL estimates were available for 417 

chemicals in this study that lack chronic oral RfVs or OSFs from the sources identified by EPA. Of 

these, 389 were found to be high-confidence estimates. 

When available, the high-confidence TOPKAT LOAEL estimates from Yost et al. (2016b) are 

discussed in this chapter as an additional resource that can be used to rank chemicals based on 

toxicity. Low- or medium-confidence TOPKAT LOAEL estimates are not shown in this chapter, as 

the use of these values for chemical ranking has not been validated. 

 

1 LOAEL is defined as the lowest exposure level at which there are biologically significant increases in the frequency or 

severity of adverse effects between the exposed population and its appropriate control group following chronic (lifetime) 

exposure.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.4.3 Chemical Data Available from EPA’s Aggregated Computations Toxicology Resource 

(ACToR) Database

An additional tool for obtaining information focused on toxicology and risk assessment is the EPA’s 

ACToR database.

1 ACToR is a large data warehouse developed by the EPA to consolidate large and 

disparate amounts of public data on chemicals, including data on chemical identity, structure, 

physicochemical properties, in vitro assay results, and in vitro toxicology data. The primary goals of 

ACToR are to make information on chemical health effects and exposure potential readily 

accessible, to characterize chemical toxicological data gaps, and to provide a resource for model 

building to address data gaps in environmental risk information (Judson et al., 2012). 

ACToR contains data on over 500,000 chemicals from over 2,500 data sources, covering many 

domains including hazard, exposure, risk assessment, risk management, and use. Data sources and 

collections in ACToR include the US EPA, National Institutes of Health (NIH), the Centers for Disease 

Control and Prevention (CDC), US Food and Drug Administration (FDA), State Agencies, the 

European Chemicals Agency (ECHA), corresponding government agencies in Canada (e.g., Health 

Canada), Europe and Japan, the World Health Organization (WHO), and non-governmental 

organizations (NGOs). Data within ACToR ranges from the federal RfVs and OSFs discussed in 

Section 9.3.1, which have undergone extensive peer review, to other toxicity values and study and 

test results that have undergone little to no peer review. 

ACToR organizes these data into several levels of “assays” and “assay categories,” which serve to 

classify data sets according to the nature of the data. For instance, the “Hazard” assay category 

includes all data that are associated directly or indirectly with toxicology experiments. The “Risk 

Management” assay category includes regulatory and non-regulatory risk management 

benchmarks. Considering the diversity and overlapping nature of the data resources within ACToR, 

a single data set may fall into multiple assay categories (Judson et al., 2012). 

We searched the ACToR database for information related to the list of 1,606 hydraulic fracturingrelated chemicals. Specifically, we searched within the “Hazard” and “Risk Management” assay 

categories of ACToR. Results of the query were then filtered to include the assays that are most 

relevant to chemical exposure via drinking water. These assays were assigned into the following 

nine data classes: carcinogenicity, dose response values, drinking water criteria, genotoxicity or 

mutagenicity, hazard identification, LOAEL/NOAEL, RfV, OSF, and water quality criteria.2 

Of the 1,606 chemicals, it was found that 735 (46%) have some data available within these data 

classes on ACToR, with the total number of data points found for individual chemicals ranging from 

1 to 243. Figure 9-2 shows the percentage of the total 1,606 chemicals that had data available in 

each of the nine ACToR data classes, and indicates the fraction of those chemicals that also had a 

chronic oral RfV or OSF available from at least one of the selected sources in Table 9-1. As can be 

seen in Figure 9-2, 37% of the chemicals had some information on hazard identification, 25% had 

 

1 The ACToR database, including the full list of data collections and assays, is available at: http://actor.epa.gov. 

2 NOAEL is defined as the highest exposure level at which there are no biologically significant increases in the frequency 

or severity of adverse effect between the exposed population and its appropriate control; some effects may be produced 

at this level, but they are not considered adverse or precursors of adverse effects. Source: U.S. EPA (2011f). 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-20 

information on carcinogenicity, and 24% had a LOAEL or NOAEL identified. A LOAEL and/or 

NOAEL identified from a well conducted dose-response study are often considered the minimum 

data needed for RfV derivation (U.S. EPA, 2002). 

Focusing on the 1,433 chemicals that lacked a chronic RfV and/or OSF from the selected sources 

described in Section 9.3.1, 567 (40%) had available data within at least one of these data classes on 

ACToR. Thus, ACToR has a significant amount of potentially useful data on chemical hazards, 

including for some data-poor chemicals, and might help to fill data gaps in the ongoing effort to 

understand potential hazards of hydraulic fracturing chemicals.

It is outside the scope of this assessment to evaluate the quality and reliability of data within ACToR 

that has not already undergone peer review. Therefore, with the exception of data from the sources 

listed in Table 9-1, data from ACToR was not considered in the hazard evaluation presented in this 

chapter. However, as a potential resource for risk assessors, the tables in this chapter indicate 

whether a chemical had data available on ACToR.

Figure 9-2. Percentage of hydraulic fracturing-related chemicals (out of 1,606 total) with at 

least one data point in each ACToR data class.

9.4.4 Additional Tools for Hazard Evaluation

In addition to the methods and approaches utilized in this chapter, there are other potential tools 

and approaches that could be used by stakeholders to prioritize and estimate toxicity of chemicals 

that have a limited toxicity database. We briefly describe three such approaches in Appendix G 

(Section G.4): the Threshold of Toxicological Concern (TTC) approach, the Organisation for 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-21 

Economic Co-operation and Development (OECD) QSAR Toolbox, and the application of data from 

high throughput screening (HTS) assays. Toxicity predictions from these additional data sources 

can be either quantitative or qualitative, and may be used to fill and address gaps related to risk 

assessment. 

Although these additional tools may be potentially useful for the evaluation of chemical hazards, 

they currently have limited utility in this chapter, and are not discussed further. The TTC approach 

requires an estimate of human intake, which is challenging for hydraulic fracturing-related 

chemicals, since the potential for human exposure is generally not clear. The OECD QSAR Toolbox is 

potentially useful for qualitative assessment, and may be useful for quantitative toxicity assessment 

as its human health hazard and repeated dose toxicity databases expand. HTS assays are an 

emerging technology, and the potential application of these data for human health risk assessment 

is not well understood. These tools would be more appropriately applied by stakeholders on a sitespecific basis, as preliminary steps to identify potential chemicals of concern.

9.4.5 Physicochemical Properties

As presented in Chapter 5, EPI SuiteTM software was used to generate data on the physicochemical 

properties of the hydraulic fracturing-related chemicals identified by EPA. EPI Suite provides an 

estimation of physicochemical properties based upon chemical structure, and will additionally 

provide experimentally measured values for these properties when they are available for a given 

chemical. For more details on this software and on the use of physicochemical properties for fate 

and transport estimation, see Chapter 5.

From the total list of 1,606 chemicals associated with hydraulic fracturing, EPI Suite was able to 

generate data on physicochemical properties for 917 (57%) of the chemicals (Appendix H). This 

includes 455 chemicals that are reported in hydraulic fracturing fluids, 521 chemicals that have 

been reported in produced water, and 59 chemicals that were both used in hydraulic fracturing 

fluids and reported in produced water. The remaining 689 chemicals on EPA’s total list lacked the 

structural information necessary to generate estimates.

In addition to EPI Suite, two other software programs were consulted to generate physicochemical 

property data for EPA’s list of hydraulic fracturing-related chemicals. QikProp (Schrodinger, 

2012) and LeadScope (Leadscope Inc., 2012) are commercial products designed primarily as drug 

development and screening tools, which are able to estimate properties related to chemical fate and 

transport as well as pharmacokinetics. Properties generated by QikProp and LeadScope are 

generally more relevant to drug development than to environmental assessment. The properties 

generated by QikProp and LeadScope were not used in the analysis presented in this report, but 

will be compiled on the electronic database for EPA’s hydraulic fracturing study.

9.4.6 Summary of Available Toxicological and Physicochemical Information for Hydraulic 

Fracturing Chemicals

Figure 9-3 summarizes the toxicological and physicochemical information that is available for the 

list of hydraulic fracturing chemicals identified by EPA in this study. This figure also summarizes 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-22 

the availability of data on the occurrence of these chemicals in hydraulic fracturing fluids 

(frequency of use) or in produced water (measured concentrations).

Figure 9-3. Overall representation of the selected toxicological, physicochemical, and 

occurrence data available for the 1,606 hydraulic fracturing-related chemicals identified by 

the EPA. 

Overall, there is a clear paucity of chronic oral RfVs and OSFs for this list of chemicals, indicating 

that the majority of chemicals associated with hydraulic fracturing activity have not undergone 

significant toxicological assessment. QSAR-based toxicity estimates (TOPKAT LOAELs) were 

available for a larger number of these chemicals, and were often available for chemicals that lack 

chronic oral RfVs and OSFs. EPA’s ACToR database offers additional toxicological data that may be 

useful for the hazard evaluation of these chemicals, although the quality and reliability of the data 

for these chemicals within ACToR was not evaluated here.

9.5 Hazard Identification of Hydraulic Fracturing Chemicals

This section focuses on the hazard identification of subsets of chemicals that were identified as 

being of particular interest in previous chapters of this report, or which otherwise may be of 

particular interest to risk assessors. For these chemicals, we summarize what is known about 

events that may lead to the entry of these chemicals into drinking water resources. We provide 

examples of recent studies that have reported these chemicals in drinking water resources, 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-23 

including examples in which these chemicals have been reported at concentrations exceeding 

MCLs. We then summarize the available toxicological data for these chemicals, including chronic 

oral RfVs, OSFs, cancer classifications, QSAR-based toxicity estimates (TOPKAT LOAELs), and the 

availability of relevant toxicological information from EPA’s ACToR database—and indicate which 

chemicals are regulated by EPA as drinking water contaminates. 

We focused on the following subsets of chemicals:

1. Chemicals used in hydraulic fracturing fluids (Chapter 5)

6. Organic chemicals that may be returned to the surface in produced water, including 

naturally occurring hydrocarbons such as BTEX (Chapter 7)

7. Inorganic chemicals that may be returned to the surface in produced water, including 

metals, inorganic ions, and technologically enhanced naturally occurring radioactive 

material (TENORM) (Chapter 7)

8. Methane in stray gas, which has been reported in drinking water resources in areas of 

hydraulic fracturing activity (Chapter 6)

9. Disinfection byproducts (DBPs) that may be formed from wastewater constituents 

(Chapter 8)

10. Banned chemicals reported in produced water, specifically organochlorine pesticides and 

polychlorinated biphenyls (PCBs). 

11. Chemicals on EPA’s consolidated list that were reported in both hydraulic fracturing fluids 

and produced water

The hazard identification for these subsets of chemicals is presented below. 

9.5.1 Chemicals Used in Hydraulic Fracturing Fluids

Chapter 5 provided an overview of chemicals that are used in hydraulic fracturing fluids. These 

chemicals have the potential to enter drinking water resources through events such as spills of 

hydraulic fracturing fluids, injection of hydraulic fracturing fluids directly into groundwater, and 

leakoff of fluids into the formation. These chemicals may also persist in produced water, and may 

enter drinking water resources through spills or releases of produced water or inadequately 

treated wastewater.

Several recent field studies have detected chemicals that are commonly used in hydraulic fracturing 

fluids in groundwater near hydraulically fractured wells. In some cases, the origin of the chemicals 

could be clearly linked to hydraulic fracturing activity. For example, in Killdeer, North Dakota 

(Section 6.2.2.1), evidence strongly suggests a well blowout during hydraulic fracturing led to the 

contamination of a drinking water aquifer with tert-butyl alcohol, a degradation product of tertbutyl hydroperoxide used in hydraulic fracturing fluids at that site (U.S. EPA, 2015i). In 

groundwater monitoring wells in the Pavillion Field in Wyoming, Digiulio and Jackson (2016)

reported detections of organic chemicals used in hydraulic fracturing fluids at that site, including 2-
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-24 

butoxyethanol, naphthalene, 1,2,4-trimethylbenzene, diethylene glycol, methanol, ethanol, and 

isopropanol, likely as a result of shallow hydraulic fracturing in that region. 

Other studies provide indirect evidence that chemical contaminants originated from hydraulic 

fracturing activity. For example, in the Marcellus Shale in Pennsylvania, Llewellyn et al. (2015)

detected trace levels of 2-butoxyethanol in water wells near several hydraulically fractured wells, 

with multiple lines of evidence suggesting that the chemical originated from a surface spill or leak 

related to hydraulic fracturing activity. In northeastern Pennsylvania, Drollette et al. (2015) found 

trace concentrations of known constituents of hydraulic fracturing fluid in private residential 

groundwater wells, including di(2-ethylhexyl) phthalate, with evidence suggesting that the 

chemicals originated from known surface spills of hydraulic fracturing fluids. In the Barnett Shale, 

Texas, a survey of water quality in public and residential wells reported chemicals that are known 

to be used in hydraulic fracturing fluids, including methanol, ethanol, isopropanol, and propargyl 

alcohol, but it was not clear whether these chemicals originated from hydraulic fracturing activity 

or from other potential sources (Hildenbrand et al., 2015). 

Table 9-2 shows the list of chemicals that were reported in at least 10% of disclosures nationally in 

the EPA FracFocus 1.0 project database (excluding water, quartz, and sodium chloride), and shows 

the noncancer toxicity data (chronic oral RfVs and TOPKAT LOAEL estimates) and ACToR data 

available for these chemicals.1 Cancer information is provided in Table 9-3. Nine (26%) of these 34 

chemicals have a chronic oral RfV available from at least one of the sources in Table 9-1. Chronic 

oral RfVs ranged from 0.002 mg/kg-day (propargyl alcohol) to 2 mg/kg-day (methanol and 

ethylene glycol). Critical effects for these chemicals include kidney/renal toxicity, hepatotoxicity, 

developmental toxicity (extra cervical ribs), reproductive toxicity, neurotoxicity, and decreased 

terminal body weight. Only one of these chemicals, sodium chlorite, is regulated in drinking water 

under the NPDWRs.

Of the 25 chemicals that lack chronic oral RfVs, 11 have high-confidence TOPKAT LOAEL estimates 

available. Of these, methenamine (~14% of disclosures) had the lowest TOPKAT LOAEL estimate, 

and choline chloride (~15% of disclosures) had the second lowest. All but five of these chemicals 

had at least some relevant toxicological data available on EPA’s ACToR database.

 

1 The analysis of the FracFocus 1.0 project database presented in this chapter did not exclude chemicals that lacked valid 

concentration data, in order to present a more inclusive analysis of the potential toxicity of chemicals used in hydraulic 

fracturing fluids. The chemical list and percent disclosures listed for each chemical is therefore slightly different that 

those shown in Chapter 5 (Table 5-3), which excluded chemicals lacking valid concentration data. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-25 

Table 9-2. 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. 

Chronic oral RfVs, TOPKAT LOAEL estimates, and availability of ACToR data are shown when 

available.

Chemicals are ordered in the table, from high to low, based on their number of disclosures in the EPA FracFocus 

1.0 project database. Water, quartz, and sodium chloride are excluded from this analysis. Asterisk (*) indicates 

chemicals that are regulated as drinking water contaminants under the NPDWRs.

Chronic oral RfVb QSAR ACToR

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kg

-day)

Source 

of RfV Critical effectc

TOPKAT 

LOAELd

(mg/kg)

# of 

data 

pointse

Methanol 67-56-1 73% 2 IRIS Extra cervical ribs 122

Distillates, 

petroleum, 

hydrotreated light

64742-47-8 67% 4 

Hydrochloric acid 7647-01-0 66% 50

Ethylene glycol 107-21-1 47% 2 IRIS Kidney toxicity 130 102

Isopropanol 67-63-0 46% 81.4 26

Diammonium 

peroxydisulfate 7727-54-0 44% 11

Guar gum 9000-30-0 39% 2

Sodium hydroxide 1310-73-2 39% 26

Propargyl alcohol 107-19-7 33% 0.002 IRIS Renal and 

hepatotoxicity 42

Glutaraldehyde 111-30-8 33% 398 13

Ethanol 64-17-5 31% 59.2 182

Potassium hydroxide 1310-58-3 31% 21

Acetic acid 64-19-7 25% 183 35

Citric acid 77-92-9 24% 55.8 25

2-Butoxyethanol 111-76-2 23% 0.1 IRIS 

Hemosiderin 

deposition in the 

liver

707 44

Solvent naphtha, 

petroleum, heavy 

arom.

64742-94-5 21% 5 

Naphthalene 91-20-3 19% 0.02 IRIS Decreased terminal 

body weight 67.5 157
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-26 

Chronic oral RfVb QSAR ACToR

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kg

-day)

Source 

of RfV Critical effectc

TOPKAT 

LOAELd

(mg/kg)

# of 

data 

pointse

2,2-Dibromo-3-

nitrilopropionamide 10222-01-2 16% 52.4

Choline chloride 67-48-1 15% 20.8 24

Phenol-formaldehyde 

resin 9003-35-4 14%

Carbonic acid, 

dipotassium salt 584-08-7 14% 137 3 

Methenamine 100-97-0 14% 12.3 15

Thiourea, polymer 

with formaldehyde 

and 1-

phenylethanone

68527-49-1 13%

1,2,4-

Trimethylbenzene 95-63-6 13% 0.01 IRIS Decreased pain sensitivity 91.5 71

Polyethylene glycol 25322-68-3 13% 5

Polyethylene glycol 

nonylphenyl ether 9016-45-9 13% 4 

Quaternary 

ammonium 

compounds, benzylC12-16-alkyldimethyl, 

chlorides

68424-85-1 12% 0.44 HHBP 

Decreased body 

weight and weight 

gain

3 

Poly(oxy-1,2-

ethanediyl)-

nonylphenyl-hydroxy 

branched

127087-87-0 12%

Ammonium chloride 12125-02-9 12% 18

Formic acid 64-18-6 11% 0.9 PPRTV Reproductive 

toxicity 72

Tetrakis(hydroxymethyl) 

phosphonium sulfate

55566-30-8 11% 148 3 

Sodium chlorite* 7758-19-2 11% 0.03 IRIS 

Neurodevelopmental 

effects

66
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-27 

Chronic oral RfVb QSAR ACToR

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kg

-day)

Source 

of RfV Critical effectc

TOPKAT 

LOAELd

(mg/kg)

# of 

data 

pointse

Alcohols, C12-14, 

ethoxylated 

propoxylated

68439-51-0 11% 1450

Sodium persulfate 7775-27-1 10% 6

CASRN = Chemical Abstract Service Registry Number; RfV = Reference value; IRIS = Integrated Risk Information System; PPRTV = 

Provisional Peer-Reviewed Toxicity Value; HHBP = Human Health Benchmarks for Pesticides; QSAR = Quantitative structureactivity relationship; TOPKAT = Toxicity Prediction by Komputer Assisted Technology; ACToR = EPA’s Aggregated Computational 

Toxicology Online Resource

a The FracFocus frequency of use data presented in this chapter is based on 35,957 FracFocus disclosures that were 

deduplicated, within the study time period (January 1, 2011 to February 28, 2013), and with ingredients that have a valid 

CASRN.

b Reference value (RfV): 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. RfVs considered in this 

analysis include chronic oral reference doses (RfDs) from IRIS, PPRTV, and HHBP; chronic oral minimal risk levels (MRLs) from 

ATSDR; maximum allowable daily levels (MADLs) from CalEPA; and tolerable daily intake (TDI) from CICAD. See Section 9.4.1.

c Critical effect: The first adverse effect, or its known precursor, that occurs to the most sensitive species as the dose rate of an 

agent increases.

d TOPKAT LOAEL: The LOAEL is the lowest exposure level at which there are biologically significant increases in frequency or 

severity of adverse effects between the exposed population and its appropriate control group. TOPKAT LOAELs were predicted 

using a QSAR-based software model, as described in Section 9.4.2. Values are rounded to 3 significant figures.

e Indicates the total number of data points available for a chemical in the relevant data classes on EPA’s ACToR database, as 

described in Section 9.4.3.

Table 9-3 shows the chemicals reported in at least 10% of disclosures nationally in the EPA 

FracFocus 1.0 project database that are considered by at least one of the sources in Table 9-1 to be 

known, probable, or possible human carcinogens. Ethanol is classified as a “carcinogenic to 

humans” (Group 1) by IARC. Naphthalene is classified by IARC as “possibly carcinogenic to humans” 

(Group 2B), and is classified by RoC as “reasonably anticipated to be a human carcinogen,” while 

IRIS classifies naphthalene as having inadequate data to assess carcinogenic potential. Neither 

chemical has an available OSF.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-28 

Table 9-3. List of OSFs and qualitative cancer classifications available for all carcinogenic 

chemicals reported to FracFocus 1.0 from January 1, 2011 to February 28, 2013 in 10% or 

more disclosures.

Includes all chemicals from Table 9-2 that are classified as known, probable, or possible human carcinogens by at 

least one of the sources in Table 9-1. 

OSFa Qualitative cancer classification

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRISb PPRTVc IARCd RoCe

Ethanol 64-17-5 1

Naphthalene 91-20-3

“Data are inadequate to 

assess human 

carcinogenic potential”

2B RAHC

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer 

Reviewed Toxicity Values; IARC = International Agency for Research on Cancer Monographs; RoC = National Toxicology Program 

13th Report on Carcinogens

a 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. OSFs considered in this analysis include values from IRIS, PPRTV, HHBP, and CalEPA. See Section 9.4.1.

b IRIS assessments use EPA’s 1986, 1996, 1999, or 2005 guidelines to establish descriptors for summarizing the weight of 

evidence as to whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details. 

c PPRTV assessments use EPA’s 1999 guidelines to establish descriptors for summarizing the weight of evidence as to whether a 

contaminant is or may be carcinogenic. See glossary in Appendix G for details.

d The IARC summarizes the weight of evidence as to whether a contaminant is or may be carcinogenic using five weight of 

evidence classifications: Group 1: Carcinogenic to humans; Group 2A: Probably carcinogenic to humans; Group 2B: Possibly 

carcinogenic to humans; Group 3: Not classifiable as to its carcinogenicity to humans; Group 4: Probably not carcinogenic to 

humans. See glossary in Appendix G for details.

e The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated 

to be a human carcinogen.

In addition to evaluating chemicals that are frequently used in hydraulic fracturing fluids, we also 

evaluated the availability of toxicological data for subsets of chemicals that are used less frequently 

on a national basis (Figure 9-4). For this analysis, we binned the chemicals according to frequency 

of use as identified from the EPA FracFocus 1.0 project database (>10% of disclosures, 5-10% of 

disclosures, 1-5% of disclosures, <1% of disclosures, or unknown frequency of use), and evaluated 

the percentage of chemicals within each bin that have available chronic oral RfVs or OSFs, TOPKAT 

LOAEL estimates, and relevant data on ACToR. This analysis demonstrates that the availability of 

chronic oral RfVs and OSFs is low across all of these subsets of chemicals. Proportionately, the 

availability of chronic oral RfVs, OSFs, and data on ACToR is slightly higher for chemicals that are 

used in >10% of disclosures, compared to chemicals that are used less frequently. 

Of the chemicals on the EPA’s list that had frequency of use data available from the EPA FracFocus 

1.0 project database, the majority were used in <1% of disclosures (n=480), suggesting that 

potential exposure to these chemicals is more likely to be a local issue rather than a national issue. 

Given that the analysis of the EPA FracFocus 1.0 project database presented in this chapter was 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-29 

based on 35,957 disclosures, a chemical used in <1% of wells nationally could still be used in 

several hundred wells. Chemicals used infrequently on a national basis could still be used more 

frequently within certain areas or counties, increasing the potential for local exposure to that 

chemical.

Figure 9-4. Availability of toxicity data (chronic oral RfVs/OSFs, TOPKAT LOAEL estimates, and 

relevant data on ACToR) for subsets of chemicals used at various frequencies in hydraulic 

fracturing fluids, as determined based on the number of disclosures in the EPA FracFocus 1.0 

project database. 

As described in Chapter 5, many of the chemicals used in hydraulic fracturing fluids can be 

classified as chemical mixtures. Among the most common chemical mixtures on EPA’s list of 

chemicals are petroleum distillates (i.e., hydrocarbon solvents), which are complex mixtures of 

petroleum hydrocarbons.

1 Two of the most frequently used chemicals in Table 9-2 are petroleum 

distillates. (Petroleum) hydrotreated light distillates is a mixture of hydrocarbons having carbon 

numbers predominantly in the range of C9 through C16, and was reported as used in 67% of 

disclosures in the EPA FracFocus 1.0 project database. Heavy aromatic (petroleum) solvent 

naphtha is a mixture consisting predominantly of aromatic hydrocarbons in carbon fraction range 

of C9 through C16, and was reported as used in 21% of disclosures in the EPA FracFocus 1.0 project 

database. These petroleum distillates lack chronic oral RfVs or OSFs, and have little information 

available in ACToR. However, a methodology that describes the toxicity and derivation of surrogate 

 

1 Total petroleum hydrocarbons (TPH) is a term used to describe a large family of several hundred chemical compounds 

that originally come from crude oil. TPH is a mixture of chemicals, but they are all made mainly from hydrogen and 

carbon, called hydrocarbons. TPH are divided into groups of petroleum hydrocarbons that act alike in soil or water. These 

groups are called petroleum hydrocarbon fractions. Each hydrocarbon fraction contains many individual chemicals. Some 

chemicals that may be found in TPH are hexane, jet fuels, mineral oils, benzene, toluene, xylenes, naphthalene, and 

fluorene, as well as other petroleum products and gasoline components. Source: ATSDR (2011). 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-30 

toxicity values for such mixtures was developed by the Total Petroleum Hydrocarbon Criteria 

Working Group (TPHCWG) (Edwards et al., 1997). This indicator/surrogate approach uses a 

combination of toxicity data and existing RfVs on individual compounds and fraction-specific 

mixtures. Examples of compounds present in each fraction include: toluene, ethylbenzene, and 

styrene (C5-C8) and isopropylbenzene (cumene), naphthalene, fluorene, pyrene, and 

methylnaphthalene (C9-C16). No data was available for consideration for C>16. Applying their 

methodology, the TPHCWG derived surrogate aliphatic and aromatic oral toxicity values for

fractions in the C5-C8, C9-C16, and C17-C35 ranges. For aromatics, the toxicity ranking was C9-C16 

and C17-C35 > C5-C8; and for aliphatics, the toxicity ranking was C9-C16 > C17-C35 > C5-C8. As 

reviewed by the TPHCWG, compounds above C20 are likely not volatile or soluble in groundwater 

and will remain at the release site and compounds above C35 are typically not likely to be 

bioavailable by the oral route of exposure. These surrogate toxicity values are not included in EPA’s 

analysis in this report, but this methodology might be useful for risk assessors at sites where these 

petroleum distillates are used.

We additionally note that several of the frequently used chemicals in Table 9-2 are designated as 

being “generally recognized as safe” (GRAS) for use in food additives or food contact substances by 

the U.S. Food and Drug Administration (FDA). This includes hydrochloric acid, guar gum, sodium 

hydroxide, sodium chloride, potassium hydroxide, acetic acid, citric acid, choline chloride, carbonic 

acid dipotassium salt, ammonium chloride, and formic acid. Overall, 103 chemicals on EPA’s list of 

chemicals used in hydraulic fracturing fluids have GRAS designations by the FDA. GRAS chemicals 

may be used by hydraulic fracturing industry operators in an effort to avoid more hazardous 

chemicals and minimizes concern in the public perception (Loveless et al., 2011). However, GRAS 

determinations are often specific to certain conditions as expressed in the FDA GRAS Notification 

Database and therefore do not indicate that the same chemical is safe for use in hydraulic fracturing 

fluids. For instance, formic acid is considered GRAS for specific use in paper food packaging 

materials (U.S. FDA, 2016), but has a chronic oral RfD of 0.9 mg/kg-day based on reproductive 

effects (U.S. EPA, 2010b). For human health risk assessment in areas of hydraulic fracturing activity, 

hazard and dose-response relations for these chemicals need to be assessed in the context of the 

use and levels that are likely to be encountered in an appropriate exposure scenario. 

9.5.2 Organic Chemicals in Produced Water

Chapter 7 discussed the detection of volatile and semi-volatile organic chemicals in produced 

water. Many of these chemicals, including the BTEX chemicals and related hydrocarbons, occur 

naturally in hydrocarbon formations and are characteristic of produced water from oil and gas 

production wells in both conventional and unconventional reservoirs. Some of these chemicals 

have anthropogenic origins, such as di(2-ethylhexyl) phthalate, which does not occur naturally but 

has known use in hydraulic fracturing fluids. Naphthalene is an example of a chemical that may 

occur naturally in hydrocarbon formations but is also used frequently in hydraulic fracturing fluids 

(19% of disclosures in the EPA FracFocus 1.0 project database; Table 9-2). These chemicals have 

the potential to enter drinking water resources through events such as spills of produced water, 

mechanical integrity failures, infiltration into groundwater from produced water storage pits, and 

persistence in inadequately treated wastewater. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-31 

Several recent field studies have reported these organic constituents in surface water and 

groundwater in areas of hydraulic fracturing activity. For example, the BTEX chemicals, dieselrange organics, gasoline-range organics, and naphthalene were detected in groundwater 

monitoring wells in Pavillion Field, Wyoming, likely as a result of legacy contamination from leaking 

unlined production fluid storage pits (Digiulio and Jackson, 2016). BTEX chemicals were also found 

to be elevated above their respective MCLs following spills by the oil and gas industry in Colorado, 

and were reduced to lower concentrations following remediation (Gross et al., 2013). Ferrar et al. 

(2013) reported mean concentrations of the BTEX chemicals in effluent from a centralized waste 

treatment (CWT) facility in Pennsylvania ranged from about 2 to 46 μg/L, with significantly lower 

concentrations observed after oil and gas well operators were asked to stop discharging waste at 

this facility (Text Box 8-1). In a survey of 500 private and public water supply wells overlying and 

adjacent to the Barnett Shale in Texas, Hildenbrand et al. (2015) reported that benzene 

concentrations exceeded their MCL in all 34 wells where benzene was detected, while toluene, 

ethylbenzene, and xylenes were prevalent at trace levels; the authors noted that BTEX detections 

occurred at a high rate in an area that houses a large number of underground injection wells for 

drilling waste disposal, but it was not clear that these chemicals originated from hydraulic 

fracturing activity or from another potential source. 

As there were a large number of organic chemicals identified on EPA’s list, this section focuses on 

the toxicological evaluation of those organic chemicals that had measured concentration data 

available in Appendix E and had at least some toxicity data available from the sources in Table 9-1, 

TOPKAT, or ACToR (69 chemicals total).1 There were an additional 46 organic chemicals that had 

measured concentration data in Chapter 7 or Appendix E that did not have any toxicity data 

available. Organic chemicals that lacked concentration data and are not discussed here.

For this subset of 69 organic chemicals, noncancer toxicity values (chronic oral RfVs and high 

confidence TOPKAT LOAEL estimates) and ACToR data availability are shown in Table 9-4, and 

cancer information (OSFs and qualitative cancer classifications) are shown in Table 9-5. Chronic 

oral RfVs were available for 31 of these chemicals, and ranged from 0.001 mg/kg-day (pyridine) to 

0.9 mg/kg-day (acetone). Critical effects for these chemicals include kidney/renal toxicity, 

hepatotoxicity, neurotoxicity, reproductive toxicity (decreased maternal weight gain), 

developmental toxicity (decreased offspring body weight, fetal toxicity), and decreased terminal 

body weight. Six of the chemicals in Table 9-4 are regulated as drinking water contaminants under 

the NPDWRs: the BTEX chemicals (benzene, ethylbenzene, toluene, xylenes), benzo(a)pyrene, and 

di(2-ethylhexyl) phthalate.

Of the 38 chemicals in Table 9-4 that lack chronic oral RfVs, 10 have high-confidence TOPKAT 

LOAEL estimates available. Several of these had similarly low LOAEL estimates: 

benzo(g,h,i)perylene, indeno(1,2,3-cd)pyrene, benzo(b)fluoranthene, benzo(k)fluoranthene, 

benzo(a)pyrene, dibenz(a,h)anthracene, and N-nitrosodiphenylamine. Notably, 33 of the chemicals 

 

1 Note that chemical names presented in this chapter and in Appendix H sometimes differ from the chemical names 

presented with the concentration data in Appendix E. This is because Appendix E uses the chemical names provided by 

the original sources of chemical data, while this chapter and Appendix H use chemical names that were verified by EPA 

during the curation of the chemical list. See Appendix H for details on the curation of the chemical list. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-32 

in Table 9-4 were added to EPA’s chemical list after the release of the external review draft (Text 

Box 9-2), and therefore were not included in the QSAR analysis (Section 9.4.2). 

Table 9-4. List of a subset of organic chemicals that have been detected in produced water, 

with respective chronic oral RfVs, TOPKAT LOAEL estimates, and availability of ACToR data 

shown when available.

Includes organic chemicals that were identified on the EPA’s list of chemicals in produced water (Appendix H) that 

have measured concentration data available in Appendix E and have at least some toxicity data available from the 

sources consulted by the EPA. Chemicals are ordered in the table from most toxic to least toxic based on chronic 

oral RfV. Chemicals without RfVs were ordered based on TOPKAT LOAEL, and then by number of data points on 

ACToR. *Indicates chemicals that are regulated as drinking water contaminants under the NPDWRs.

Chronic oral RfVa QSAR 

estimate ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical Effectb

TOPKAT 

LOAELc

(mg/day)

# of 

data 

pointsd

Pyridine 110-86-1 0.001 IRIS Increased liver weight 69.5 114

Benzidine 92-87-5 0.003 IRIS 

Brain cell vacuolization; 

liver cell alterations in 

females

127

2,4-Dichlorophenol 120-83-2 0.003 IRIS Decreased delayed 

hypersensitivity response 122

Benzene* 71-43-2 0.004 IRIS Decreased lymphocyte 

count

77.6 238

2-Methylnaphthalene 91-57-6 0.004 IRIS Pulmonary alveolar 

proteinosis 103 52

1,3,5-Trimethylbenzene 108-67-8 0.01 IRIS Decreased pain sensitivity 63 76

1,2,4-Trimethylbenzene 95-63-6 0.01 IRIS Decreased pain sensitivity 91.5 71

Chloroform 67-66-3 0.01 IRIS 

Moderate/marked fatty 

cyst formation in the liver 

and elevated serum 

glutamic pyruvic 

transaminase (SGPT)

47.1 221

Naphthalene 91-20-3 0.02 IRIS Decreased mean terminal 

body weight in males 67.5 157

2,4-Dimethylphenol 105-67-9 0.02 IRIS 

Clinical signs (lethargy, 

prostration, and ataxia) 

and hematological 

changes

112 88

Di(2-ethylhexyl) 

phthalate* 117-81-7 0.02 IRIS Increased relative liver weight 4040 229
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-33 

Chronic oral RfVa QSAR 

estimate ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical Effectb

TOPKAT 

LOAELc

(mg/day)

# of 

data 

pointsd

Pyrene 129-00-0 0.03 IRIS 

Kidney effects (renal 

tubular pathology, 

decreased kidney 

weights)

36.1 129

1,4-Dioxane 123-91-1 0.03 IRIS Liver and kidney toxicity 207 148

Fluoranthene 206-44-0 0.04 IRIS 

Nephropathy, increased 

liver weights, 

hematological alterations, 

and clinical effects

44.6 103

Fluorene 86-73-7 0.04 IRIS 

Decreased RBC, packed 

cell volume and 

hemoglobin

95.1 120

m-Cresol 108-39-4 0.05 IRIS Decreased body weights 

and neurotoxicity 123 103

o-Cresol 95-48-7 0.05 IRIS Decreased body weights 

and neurotoxicity 229 94

Toluene* 108-88-3 0.08 IRIS Increased kidney weight 163 188

Diphenylamine 122-39-4 0.1 HHBP 

Alterations in clinical 

chemistry; increased 

kidney. liver, and spleen 

weights

30.8 86

Carbon disulfide 75-15-0 0.1 IRIS Fetal toxicity/ 

malformations 126 89

Benzyl alcohol 100-51-6 0.1 PPRTV

Effects on survival, 

growth, and tissue 

histopathology

210 45

Ethylbenzene* 100-41-4 0.1 IRIS Liver and kidney toxicity 226 207

Cumene 98-82-8 0.1 IRIS Increased average kidney 

weight in female rats 246 101

Acetophenone 98-86-2 0.1 IRIS General toxicity 274 58

Dibutyl phthalate 84-74-2 0.1 IRIS Increased mortality 2090 143

Xylenes* 1330-20-7 0.2 IRIS Decreased body weight, 

increased mortality 110 174

Benzyl butyl phthalate 85-68-7 0.2 IRIS 

Significantly increased 

liver-to-body weight and 

liver-to-brain weight 

ratios

194

Phenol 108-95-2 0.3 IRIS Decreased maternal 

weight gain 134 170
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-34 

Chronic oral RfVa QSAR 

estimate ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical Effectb

TOPKAT 

LOAELc

(mg/day)

# of 

data 

pointsd

Biphenyl 92-52-4 0.5 IRIS 

Renal papillary 

mineralization in male 

F344 rats

103

Caprolactam 105-60-2 0.5 IRIS Reduced offspring body 

weight 39

Acetone 67-64-1 0.9 IRIS Nephropathy 119 79

Benzo(g,h,i)perylene 191-24-2 29.1 68

Indeno(1,2,3-cd)pyrene 193-39-5 38.6 111

Dibenz(a,h)anthracene 53-70-3 38.9 96

Benzo(b)fluoranthene 205-99-2 39 121

Benzo(k)fluoranthene 207-08-9 39 118

N-Nitrosodiphenylamine 86-30-6 39.4 99

Benzo(a)pyrene* 50-32-8 43 184

Phenanthrene 85-01-8 61.3 69

p-Cresol 106-44-5 95.5 98

Dioctyl phthalate 117-84-0 4740 61

Caffeine 58-08-2 134

Benz(a)anthracene 56-55-3 122

Chrysene 218-01-9 114

2-Mercaptobenzothiazole 149-30-4 95

1,2-Diphenylhydrazine 122-66-7 83

Dimethyl phthalate 131-11-3 79

N-Nitroso-Nmethylethylamine 10595-95-6 42

4-(1,1,3,3-

Tetramethylbutyl)phenol 140-66-9 30

p-Tert-butylphenol 98-54-4 27

2,6-Di-tert-butylphenol 128-39-2 22

Dimethylphenol 1300-71-6 17

2-Ethylhexyl diphenyl

phosphate (Octicizer) 1241-94-7 14

2,5-Cyclohexadiene-1,4-

dione 106-51-4 12

Cholesterol 57-88-5 11
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-35 

Chronic oral RfVa QSAR 

estimate ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical Effectb

TOPKAT 

LOAELc

(mg/day)

# of 

data 

pointsd

Benzothiazole 95-16-9 10

Octadecanoic acid 57-11-4 9

Butanoic acid, butyl ester 109-21-7 9

Tetradecanoic acid 544-63-8 7

Triphenyl phosphate 115-86-6 7

Dodecanoic acid 143-07-7 6

Drometrizole 2440-22-4 6

3-(4-Methoxyphenyl)-2-

ethylhexylester-2-

propenoic acid

5466-77-3 6 

2,6-Bis(dimethylethyl)-

2,5-cyclohexadiene-1,4-

dione

719-22-2 3 

Diphenylmethane 101-81-5 3

Isopropyl myristate 110-27-0 2

2-[2-[4-(1,1,3,3-

tetramethylbutyl)phenoxy]ethoxy]-ethanol

2315-61-9 2 

Sterane 50-24-8 1

3-(4-Methoxyphenyl)-2-

propenoic acid 830-09-1 1 

CASRN = Chemical Abstract Service Registry Number; RfV = Reference value; IRIS = Integrated Risk Information System; PPRTV = 

Provisional Peer-Reviewed Toxicity Value; HHBP = Human Health Benchmarks for Pesticides; QSAR = Quantitative structureactivity relationship; TOPKAT = Toxicity Prediction by Komputer Assisted Technology; ACToR = EPA’s Aggregated Computational 

Toxicology Online Resource

a Reference value (RfV): 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. RfVs considered in this 

analysis include chronic oral reference doses (RfDs) from IRIS, PPRTV, and HHBP; chronic oral minimal risk levels (MRLs) from

ATSDR; maximum allowable daily levels (MADLs) from CalEPA; and tolerable daily intake (TDI) from CICAD. See Section 9.4.1.

b Critical effect: The first adverse effect, or its known precursor, that occurs to the most sensitive species as the dose rate of an 

agent increases.

c TOPKAT LOAEL: The LOAEL is the lowest exposure level at which there are biologically significant increases in frequency or 

severity of adverse effects between the exposed population and its appropriate control group. TOPKAT LOAELs were predicted 

using a QSAR-based software model, as described in Section 9.4.2. Values are rounded to 3 significant figures.

d Indicates the total number of data points available for a chemical in the relevant data classes on EPA’s ACToR database, as 

described in Section 9.4.3.

Of the organic chemicals in produced water listed in Table 9-4, 17 have available OSFs and 23 are 

classified as known, probable, or possible carcinogens (Table 9-5). Benzidine and benzene were 

both classified as human carcinogens by IRIS, IARC, and RoC, with benzidine being the most potent 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-36 

carcinogen listed in Table 9-5 (OSF of 230 per mg/kg-day). Benzo(a)pyrine is classified as a human 

carcinogen by IARC, and as a probable human carcinogen by IRIS. The remaining chemicals were 

classified as probable or possible human carcinogens. 

Table 9-5. List of OSFs and qualitative cancer classifications available for a subset of organic 

chemicals that have been reported in produced water.

Includes organic chemicals that were identified on EPA’s list of chemicals in produced water (Appendix H) that 

have measured concentration data available in Chapter 7 or Appendix E (Table 9-4) and are classified as known, 

probable, or possible carcinogens. Chemicals that had OSFs available are ordered in this table from most potent 

(highest OSF) to least potent (lowest OSF). 

OSFsa Qualitative Cancer Classifications

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRIS b PPRTV c IARC d RoC e

Benzidine 92-87-5 230 IRIS A (Human 

carcinogen) 1 Known

N-Nitroso-Nmethylethylamine 10595-95-6 22 IRIS 

B2 (Probable 

human 

carcinogen)

2B

Benzo(a)pyrene 50-32-8 7.3 IRIS 

B2 (Probable 

human 

carcinogen)

1 RAHC

Dibenz(a,h)anthracene

53-70-3 4.1 CalEPA 2A RAHC

Indeno(1,2,3-

cd)pyrene 193-39-5 1.2 CalEPA 2B RAHC

Benzo(b)fluoranthene 205-99-2 1.2 CalEPA 2B RAHC

Benzo(k)fluoranthene 207-08-9 1.2 CalEPA 2B RAHC

1,2-

Diphenylhydrazine 122-66-7 0.8 IRIS 

B2 (Probable 

human 

carcinogen)

RAHC

Benz(a)anthracene 56-55-3 0.7 PPRTV

B2 (Probable 

human 

carcinogen)

2B RAHC

Chrysene 218-01-9 0.12 CalEPA

B2 (Probable 

human 

carcinogen)

2B

1,4-Dioxane 123-91-1 0.1 IRIS 

"Likely to be 

carcinogenic to 

humans"

2B RAHC
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-37 

OSFsa Qualitative Cancer Classifications

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRIS b PPRTV c IARC d RoC e

Benzene 71-43-2 0.015-

0.055 IRIS A (Human carcinogen) 1 Known

Chloroform 67-66-3 0.019 CalEPA

B2 (Probable 

human 

carcinogen)

2B RAHC

Di(2-ethylhexyl) 

phthalate 117-81-7 0.014 IRIS 

B2 (Probable 

human 

carcinogen)

2B RAHC

Ethylbenzene 100-41-4 0.011 CalEPA

D (Not 

classifiable as to 

human 

carcinogenicity)

2B

Biphenyl 92-52-4 0.008 IRIS 

"Suggestive 

evidence of 

carcinogenic 

potential"

N-Nitrosodiphenylamine 86-30-6 0.0049 IRIS 

B2 (Probable 

human 

carcinogen)

3 

Naphthalene 91-20-3

“Data are 

inadequate to 

assess human 

carcinogenic 

potential”

2B RAHC

Cumene 98-82-8

D (Not 

classifiable as to 

human 

carcinogenicity)

2B RAHC

2-Mercaptobenzothiazole 149-30-4 2A

m-Cresol 108-39-4

C (Possible 

human 

carcinogen)

o-Cresol 95-48-7

C (Possible 

human 

carcinogen)

“Data are 

inadequate for 

the assessment 

of human 

carcinogenic 

potential”
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-38 

OSFsa Qualitative Cancer Classifications

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRIS b PPRTV c IARC d RoC e

Benzyl butyl 

phthalate 85-68-7

C (Possible 

human 

carcinogen)

3 

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer

Reviewed Toxicity Values; HHBP = Human Health Benchmarks for Pesticides; CalEPA = California Environmental Protection

Agency; IARC = International Agency for Research on Cancer Monographs; RoC = National Toxicology Program 13th Report on

Carcinogens 

a

 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. OSFs considered in this analysis include values from IRIS, PPRTV, HHBP, and CalEPA. See Section 9.4.1. 

b

 IRIS assessments use EPA’s 1986, 1996, 1999, or 2005 guidelines to establish descriptors for summarizing the weight of 

evidence as to whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details. 

c

 PPRTV assessments use EPA’s 1999 guidelines to establish descriptors for summarizing the weight of evidence as to whether a 

contaminant is or may be carcinogenic. See glossary in Appendix G for details. 

d

 The IARC summarizes the weight of evidence as to whether a contaminant is or may be carcinogenic using five weight of 

evidence classifications: Group 1: Carcinogenic to humans; Group 2A: Probably carcinogenic to humans; Group 2B: Possibly

carcinogenic to humans; Group 3: Not classifiable as to its carcinogenicity to humans; Group 4: Probably not carcinogenic to

humans. See glossary in Appendix G for details. 

e

 The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated 

to be a human carcinogen.

9.5.3 Inorganic Chemicals and TENORM in Produced Water

Chapter 7 discussed the detection of inorganic constituents such as metals, inorganic ions, and

TENORM in produced water. Examples include barium, cadmium, chromium, copper, lead,

manganese, nickel, zinc, and radium. In general, these chemicals are naturally occurring, and are

characteristic of produced water from both conventional and unconventional reservoirs. These

chemicals have the potential to enter drinking water resources through events such as spills of

produced water, mechanical integrity failures, infiltration into groundwater from produced water

storage pits, and persistence in inadequately treated wastewater.

The entry of inorganic constituents of produced water into drinking water resources has been 

documented in numerous studies. In Pennsylvania, elevated levels of barium and strontium have

been observed in CWT effluent (PA DEP, 2015a), with effluent concentrations dropping after oil and

gas well operators were asked to stop discharging waste at this facility (see Text Box 8-1 for details 

on temporal trends in wastewater management in Pennsylvania). Likewise, effluent concentrations

at two publicly owned treatment words (POTWs) that had accepted Marcellus wastewater were

found to have lower concentrations of bromide, chloride, barium, strontium, and sulfate after oil

and gas well operators were asked to stop discharging waste at this facility in May 2011 (Ferrar et

al., 2013). Effluents from POTWs and CWTs that handle Marcellus Shale wastewater have been

found to have levels of radium-226 and radium-228 that exceed the MCL for radium and are
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-39 

significantly higher than typical background levels of radium in river water (PA DEP, 2015b). 

Radium-226 and radium-228 have been demonstrated to accumulate in sediments near the outfalls 

of CWTs and of POTWs that handle oil and gas wastewater from CWTs (PA DEP, 2015b; Warner et 

al., 2013a), and in sediments receiving effluent from landfills that accept oil and gas wastes (PA 

DEP, 2015b). In West Virginia, water samples collected downstream of a hydraulic fracturing 

wastewater injection facility had elevated specific conductance and total dissolved solids, elevated 

bromide, chloride, sodium, barium, strontium, and lithium concentrations, and different strontium 

isotope ratios compared to those found in upstream, background waters (Akob et al., 2016). In a 

survey of 500 groundwater wells overlying and adjacent to the Barnett Shale in Texas, Hildenbrand 

et al. (2015) reported a variety of metals and anions that are known produced water constituents at 

concentrations that sometimes exceeded primary or secondary MCLs, health advisory levels, or 

other suggested levels as provided in the EPA Drinking Water Standards, although it was not clear 

that these chemicals originated from nearby hydraulic fracturing activity or from other potential 

sources. 

For the inorganic chemicals that were identified in produced water on EPA’s chemical list, 

noncancer toxicity values (chronic oral RfVs) and ACToR data availability for these chemicals are 

shown in Table 9-6, and cancer information (OSFs and qualitative cancer classifications) are shown 

in Table 9-7. As shown in Table 9-6, chronic oral RfVs were available for 26 of these chemicals, 

ranging from 0.00002 mg/kg-day (phosphorus) to 1.6 mg/kg-day (nitrate). Critical effects for these 

metals include neurotoxicity, developmental and liver toxicity, hyperpigmentation and keratosis of 

the skin, and decrements in blood copper status and enzyme activity. Nineteen of the inorganic 

chemicals in Table 9-6 are regulated as drinking water contaminants under the NPDWR.

All but one of these inorganic chemicals had at least some relevant data available on EPA's ACToR 

database. However, none of the inorganic chemicals have TOPKAT LOAEL estimates available, as 

this QSAR model is only able to generate estimates for organic chemicals (Section 9.4.2). 

Table 9-6. List of inorganics and TENORM reported in produced water, and respective chronic 

oral RfVs and OSFs when available. 

Includes inorganic chemicals that were identified on EPA’s list of chemicals in produced water (Appendix H). 

Chemicals are ordered from most toxic to least toxic based on chronic oral RfV. Chemicals without chronic oral 

RfVs were ordered in terms of the number of data points on ACToR. *Indicates chemicals are regulated as drinking 

water contaminants under the NPDWR.

Chronic oral RfVsa ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical effectb

# of 

data 

pointsc

Phosphorus 7723-14-0 0.00002 IRIS Parturition mortality; 

forelimb hair loss 113

Vanadium 7440-62-2 0.00007 PPRTV Kidney histopathology 76

Arsenic* 7440-38-2 0.0003 IRIS Hyperpigmentation and 

vascular complications 243
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-40 

Chronic oral RfVsa ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical effectb

# of 

data 

pointsc

Cobalt 7440-48-4 0.0003 PPRTV Decreased iodine uptake 76

Antimony* 7440-36-0 0.0004 IRIS 

Hematological; 

alterations in glucose 

and cholesterol

163

Cadmium* 7440-43-9 0.0005 IRIS Proteinuria 230

Beryllium* 7440-41-7 0.002 IRIS Intestinal lesions 186

Mercury 7439-97-6 0.002 CICAD Renal toxicity 177

Lithium 7439-93-2 0.002 PPRTV Adverse effects in 

multiple organ systems 43

Chromium (VI) 18540-29-9 0.003 IRIS None reported 120

Selenium* 7782-49-2 0.005 IRIS Clinical selenosis 232

Silver 7440-22-4 0.005 IRIS Argyria 120

Molybdenum 7439-98-7 0.005 IRIS Increased uric acid levels 73

Iodine 7553-56-2 0.01 CICAD 27

Nitrite* 14797-65-0 0.1 IRIS Methemoglobinemia 109

Chlorine 7782-50-5 0.1 IRIS No adverse effect level 116

Manganese 7439-96-5 0.14 IRIS Central nervous system 

(CNS) effects 128

Barium* 7440-39-3 0.2 IRIS Nephropathy 167

Boron 7440-42-8 0.2 IRIS Decreased fetal weight 

(developmental) 93

Zinc 7440-66-6 0.3 IRIS 

Decreases in erythrocyte 

Cu, Zn-superoxide 

dismutase (ESOD) 

activity in humans

163

Lead* 7439-92-1 0.5 μg/day d CalEPA Reproductive Toxicity 168

Strontium 7440-24-6 0.6 IRIS Rachitic bone 67

Iron 7439-89-6 0.7 PPRTV Adverse gastrointestinal 

effects 73

Aluminum 7429-90-5 1 PPRTV Neurotoxicity 88

Chromium (III) 16065-83-1 1.5 IRIS No effects observed 71
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-41 

Chronic oral RfVsa ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical effectb

# of 

data 

pointsc

Nitrate* 14797-55-8 1.6 IRIS 

Clinical signs of 

methemoglobinemia in 

excess of 10%

130

Nickel 7440-02-0 181

Copper* 7440-50-8 163

Thallium* 7440-28-0 136

Chromium 7440-47-3 125

Uranium-238* 7440-61-1 100

Ammonia 7664-41-7 90

Zirconium 7440-67-7 55

Alpha particle* 12587-46-1 55

Fluoride* 16984-48-8 53

Radium* 7440-14-4 52

Beta particle* 12587-47-2 51

Magnesium 7439-95-4 40

Tin 7440-31-5 40

Chloride 16887-00-6 32

Sodium 7440-23-5 31

Sulfate 14808-79-8 27

Potassium 7440-09-7 25

Titanium 7440-32-6 25

Calcium 7440-70-2 24

Radium-226* 13982-63-3 13

Radium-228* 15262-20-1 11

Sulfide 18496-25-8 11

Caesium 7440-46-2 7

Caesium-137 10045-97-3 6

Silicon 7440-21-3 5

Rubidium 7440-17-7 5
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-42 

Chronic oral RfVsa ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical effectb

# of 

data 

pointsc

Bromide 24959-67-9 2

Sulfite 14265-45-3 1

Uranium-235* 15117-96-1 1

Octasulfur 10544-50-0

CASRN = Chemical Abstract Service Registry Number; RfV = Reference value; IRIS = Integrated Risk Information System; PPRTV = 

Provisional Peer-Reviewed Toxicity Value; CalEPA = California Environmental Protection Agency; CICAD = Concise International 

Chemical Assessment Documents; ACToR = EPA’s Aggregated Computational Toxicology Online Resource

a Reference value (RfV): 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. RfVs considered in this 

analysis include chronic oral reference doses (RfDs) from IRIS, PPRTV, and HHBP; chronic oral minimal risk levels (MRLs) from

ATSDR; maximum allowable daily levels (MADLs) from CalEPA; and tolerable daily intake (TDI) from CICAD. See Section 9.4.1.

b Critical effect: The first adverse effect, or its known precursor, that occurs to the most sensitive species as the dose rate of an 

agent increases.

c Indicates the total number of data points available for a chemical in the relevant data classes on EPA’s ACToR database, as 

described in Section 9.4.3.

d CalEPA MADLs are in units of μg/day, while all other chronic oral RfVs in this table are in units of mg/kg-day.

OSFs were available for 4 of the inorganic chemicals reported in produced water, and 14 are 

classified as known or probable carcinogens (Table 9-7). OSFs ranged from 15 per mg/kg-day for 

cadmium to 0.0085 mg/kg-day for lead. Chromium (VI), arsenic, alpha particle, beta particle,

radium-226, and radium-288 are all classified as known human carcinogens by all sources 

reporting in this table. Beryllium and cadmium are both classified as known human carcinogens by 

IARC and NTP, and as probable human carcinogens by EPA. Lead, cobalt, nickel, nitrate, and nitrite

are classified by these sources as possible or probable human carcinogens.

Table 9-7. List of qualitative cancer classifications available for inorganics and NORM that 

were reported in produced water.

Includes inorganic chemicals that were identified on EPA’s list of chemicals in produced water (Appendix H) that 

classified as known, probable, or possible carcinogens by at least one of the sources in Table 9-1. Chemicals that 

had OSFs available are ordered in this table from most potent (highest OSF) to least potent (lowest OSF).

OSFa Qualitative Cancer Classifications

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRISb PPRTVc IARCd RoCe

Cadmium 7440-43-9 15 CalEPA

B1 (Probable 

human 

carcinogen)

1 Known

Arsenic 7440-38-2 1.5 IRIS A (Human 

carcinogen) 1 Known
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-43 

OSFa Qualitative Cancer Classifications

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRISb PPRTVc IARCd RoCe

Chromium (VI) 18540-29-9 0.5 CalEPA

Inhaled: A 

(Human 

carcinogen)

Oral: D (Not 

classifiable as to 

human 

carcinogenicity)

1 Known

Lead 7439-92-1 0.0085 CalEPA

B2 (Probable 

human 

carcinogen)

2B RAHC

Alpha particle 12587-46-1 1

Beryllium 7440-41-7 

B1 (Probable 

human 

carcinogen)

1 Known

Beta particle 12587-47-2 1

Radium 7440-14-4 1

Radium-226 13982-63-3 1

Radium-228 15262-20-1 1

Cobalt 7440-48-4 

Likely to be 

carcinogenic to 

humans

2B

Nickel 7440-02-0 2B RAHC

Nitrate 14797-55-8 2A

Nitrite 14797-65-0 2A

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer 

Reviewed Toxicity Values; HHBP = Human Health Benchmarks for Pesticides; CalEPA = California Environmental Protection 

Agency; IARC = International Agency for Research on Cancer Monographs; RoC = National Toxicology Program 13th Report on 

Carcinogens

a 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. OSFs considered in this analysis include values from IRIS, PPRTV, HHBP, and CalEPA. See Section 9.4.1.

b IRIS assessments use EPA’s 1986, 1996, 1999, or 2005 guidelines to establish descriptors for summarizing the weight of 

evidence as to whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details. 

c PPRTV assessments use EPA’s 1999 guidelines to establish descriptors for summarizing the weight of evidence as to whether a 

contaminant is or may be carcinogenic. See glossary in Appendix G for details.

d The IARC summarizes the weight of evidence as to whether a contaminant is or may be carcinogenic using five weight of 

evidence classifications: Group 1: Carcinogenic to humans; Group 2A: Probably carcinogenic to humans; Group 2B: Possibly 

carcinogenic to humans; Group 3: Not classifiable as to its carcinogenicity to humans; Group 4: Probably not carcinogenic to 

humans. See glossary in Appendix G for details.

e The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated 

to be a human carcinogen.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-44 

9.5.4 Organochlorine Pesticides and Polychlorinated Biphenyls (PCBs) in Produced Water

EPA’s list of chemicals detected in produced water includes several chemicals that have been 

banned from commercial use: specifically, organochlorine pesticides and Aroclor 1248, which is a 

commercial PCB mixture. These chemicals were reported by two of the sources used to compile 

EPA’s chemical list (Appendix H): a technical report prepared by the Gas Technology Institute for 

the Marcellus Shale Coalition (MSC), which is a drilling industry trade group (Hayes, 2009); and a 

report by the New York State Department of Environmental Conservation (NYSDEC), which 

referenced the results of the MSC study (NYSDEC, 2011). These chemicals are listed in Table 9-8

along with their respective noncancer toxicity values (chronic oral RfVs and TOPKAT LOAELs) and 

availability of relevant toxicological information on ACToR. Cancer information (OSF or qualitative 

cancer classification) for these chemicals is listed in Table 9-9. 

There is uncertainty about why organochlorine pesticides and PCBs were detected, as they are not 

used in hydraulic fracturing fluids and are not naturally occurring. The MSC study stated the 

banned substances were detected sporadically and at low concentrations, and suggested they may 

have originated from laboratory contamination. The NYSDEC report suggested that the banned 

substances may have been introduced to the shale or the water as a result of drilling or fracturing 

operations. It is possible that these chemicals were present as legacy contaminants in the source 

water used for hydraulic fracturing fluid formulation, or were mobilized from the environment near 

the well. Although these chemicals are notable for their high toxicity, the extent to which these 

chemicals may be detected in produced water from other hydraulic fracturing sites is not clear. 

Chronic oral RfVs for these organochlorine pesticides ranged from 0.000013 mg/kg-day 

(Heptachlor epoxide) to 0.0005 mg/kg-day (heptachlor), and were all based on liver toxicity. All of 

these pesticides had TOPKAT LOAEL estimates, and all have relevant data available within EPA’s 

ACToR database.). Heptachlor epoxide, heptachlor, and lindane are regulated as drinking water 

contaminants under the NPDWR.

Table 9-8. List of organochlorine pesticides and PCBs that were reported in produced water, 

and their respective chronic oral RfVs, TOPKAT LOAEL estimates, and availability of data in 

EPA’s ACToR database. 

Includes banned chemicals that were identified on EPA’s list of chemicals in produced water (Appendix H).

Chemicals are ordered from most toxic to least toxic based on chronic oral RfV. Chemicals without chronic oral 

RfVs were ordered in terms of the number of data points on ACToR. *Indicates chemicals that are regulated as 

drinking water contaminants under the NPDWRs.

Chronic oral RfVa QSAR ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical effectb

TOPKAT 

LOAELc

(mg/kg)

# of 

data 

pointsd

Heptachlor epoxide* 1024-57-3 0.000013 IRIS 

Increased liver-to-body 

weight ratio in both 

males and females

0.595 168

Aldrin 309-00-2 0.00003 IRIS Liver toxicity 0.743 166
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-45 

Chronic oral RfVa QSAR ACToR

Chemical Name CASRN

RfV 

(mg/kgday)Source 

of RfV Critical effectb

TOPKAT 

LOAELc

(mg/kg)

# of 

data 

pointsd

Dieldrin 60-57-1 0.00005 IRIS Liver lesions 0.442 167

Lindane* 58-89-9 0.0003 IRIS Liver and kidney 

toxicity 23.9 238

Heptachlor* 76-44-8 0.0005 IRIS Liver weight increases 

in males 0.927 203

betaHexachlorocyclohexane 319-85-7 23.9 88

deltaHexachlorocyclohexane 319-86-8 23.9 22

Aroclor 1248 12672-29-6 21.87 35

p,p'-DDE 72-55-9 14.6 103

Endrin aldehyde 7421-93-4 4.09 27

Endosulfan I 959-98-8 2.27 32

Endosulfan II 33213-65-9 2.27 32

CASRN = Chemical Abstract Service Registry Number; RfV = Reference value; IRIS = Integrated Risk Information System; QSAR = 

Quantitative structure-activity relationship; TOPKAT = Toxicity Prediction by Komputer Assisted Technology; ACToR = EPA’s 

Aggregated Computational Toxicology Online Resource

a Reference value (RfV): 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. RfVs considered in this 

analysis include chronic oral reference doses (RfDs) from IRIS, PPRTV, and HHBP; chronic oral minimal risk levels (MRLs) from

ATSDR; maximum allowable daily levels (MADLs) from CalEPA; and tolerable daily intake (TDI) from CICAD. See Section 9.4.1.

b Critical effect: The first adverse effect, or its known precursor, that occurs to the most sensitive species as the dose rate of an 

agent increases.

c TOPKAT lowest-observed-adverse-effect level (LOAEL): The LOAEL is the lowest exposure level at which there are biologically 

significant increases in frequency or severity of adverse effects between the exposed population and its appropriate control 

group. TOPKAT LOAELs were predicted using a QSAR-based software model, as described in Section 9.4.2.

d Indicates the total number of data points available for a chemical in the relevant data classes on EPA’s ACToR database, as 

described in Section 9.4.3.

OSFs were available for 7 of the organochlorine pesticides that are classified as known, probable, or 

possible human carcinogens (Table 9-9). OSFs ranged from 17 per mg/kg-day (aldrin) to 0.34 per 

mg/kg-day (p,p’-DDE). Aldrin, dieldrin, heptachlor epoxide, heptachlor, betahexachlorocyclohexane, and p,p’-DDE are classified as probable or possible carcinogens. Lindane is 

classified as a known carcinogen by IARC, and as “reasonably anticipated to be a human 

carcinogen” by RoC.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Table 9-9. List of OSFs and qualitative cancer classifications available for organochlorine 

pesticides reported in produced water. 

Includes banned chemicals that were identified on EPA’s list of chemicals in produced water (Appendix H) that are 

classified as known, probable, or possible carcinogens by at least one of the sources in Table 9-1. Chemicals are 

ordered in this table from most potent (highest OSF) to least potent (lowest OSF).

OSFa Qualitative cancer classifications

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF IRISb PPRTVc IARCd RoCe

Aldrin 309-00-2 17 IRIS B2 (Probable human 

carcinogen) 3 

Dieldrin 60-57-1 16 IRIS B2 (Probable human 

carcinogen) 3 

Heptachlor 

epoxide 1024-57-3 9.1 IRIS B2 (Probable human carcinogen)

Heptachlor 76-44-8 4.5 IRIS B2 (Probable human 

carcinogen) 2B

betaHexachlorocyclohe

xane

319-85-7 1.8 IRIS C (Possible human 

carcinogen)

Lindane 58-89-9 1.1 CalEPA 1 RAHC

p,p'-DDE 72-55-9 0.34 IRIS B2 (Probable human 

carcinogen)

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; CalEPA = California 

Environmental Protection Agency; IARC = International Agency for Research on Cancer Monographs; RoC = National Toxicology 

Program 13th Report on Carcinogens

a 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. OSFs considered in this analysis include values from IRIS, PPRTV, HHBP, and CalEPA. See Section 9.4.1.

b IRIS assessments use EPA’s 1986, 1996, 1999, or 2005 guidelines to establish descriptors for summarizing the weight of 

evidence as to whether a contaminant is or may be carcinogenic. See glossary in Appendix G for details. 

c PPRTV assessments use EPA’s 1999 guidelines to establish descriptors for summarizing the weight of evidence as to whether a 

contaminant is or may be carcinogenic. See glossary in Appendix G for details.

d The IARC summarizes the weight of evidence as to whether a contaminant is or may be carcinogenic using five weight of 

evidence classifications: Group 1: Carcinogenic to humans; Group 2A: Probably carcinogenic to humans; Group 2B: Possibly 

carcinogenic to humans; Group 3: Not classifiable as to its carcinogenicity to humans; Group 4: Probably not carcinogenic to 

humans. See glossary in Appendix G for details.

e The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated 

to be a human carcinogen.

9.5.5 Methane in Stray Gas 

Chapter 6 discussed stray gas as a potential hazard in areas of hydraulic fracturing activity (Text 

Box 6-3). Stray gas refers to the phenomenon of natural gas (primarily methane, plus lesser 

amounts of ethane) migrating into shallow groundwater, into water wells, or to the surface (e.g., 

cellars, streams, or springs). As discussed in Chapter 6, some studies indicate an association 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-47 

between hydraulic fracturing activity and elevated methane concentrations in drinking water, while 

other studies did not find such a correlation. Potential pathways for migration of stray gas into 

aquifers include pathways along production wells with casing and/or cement issues, through 

naturally existing fractures, through induced fractures, or via a route that is some combination of 

these pathways.

Although ingestion of methane is not considered to be toxic, it has the potential to pose a physical 

hazard. Methane can accumulate to explosive levels when allowed to exsolve (degas) from 

groundwater in closed environments. High concentrations of methane may also displace oxygen 

and act as an asphyxiant (NIOSH, 2000), potentially causing suffocation, loss of consciousness, or 

symptoms such as headache and nausea. Methane is not a regulated drinking water contaminant. 

Methane does not have an RfV, OSF, or qualitative cancer classification available from any of the 

sources consulted by EPA, and did not have a high-confidence TOPKAT LOAEL estimate. 

Information on methane is available within the ACToR database. 

9.5.6 Disinfection Byproducts (DBPs) Formed from Wastewater Constituents

Some of the inorganic constituents of hydraulic fracturing produced water, including chloride, 

bromine, iodine, and ammonium, can contribute to the formation of DBPs during wastewater 

treatment (Harkness et al., 2015; Parker et al., 2014). The entry of these constituents into drinking 

water resources—e.g., as a result of wastewater spills or from the discharge of inadequately treated 

hydraulic fracturing wastewater—can result in DBPs in finished drinking water from downstream 

drinking water treatment plants (States et al., 2013). DBPs may also be formed when hydraulic 

fracturing produced water is treated at a centralized or publicly owned treatment works, and may 

reach drinking water resources when the treated wastewater is discharged to surface water (Hladik 

et al., 2014). Currently, there are no data available on the concentrations of DBPs in finished 

drinking water as related to contributions of DBP precursors from hydraulic fracturing wastewater. 

Regulated DBPs such as bromate, chlorite, haloacetic acids, and trihalomethanes are a small subset 

of the full spectrum of DBPs that include other chlorinated and brominated DBPs as well as 

nitrogenous and iodated DBPs. Long term exposure to these DBPs can result in an increased risk of 

cancer, anemia, liver and kidney effects, and central nervous system effects. Some of the 

unregulated DBPs may be more toxic than their regulated counterparts (Harkness et al., 2015; 

McGuire et al., 2014; Parker et al., 2014). In addition, brominated forms of DBPs are considered to 

be more cytotoxic, genotoxic, and carcinogenic than chlorinated species based on studies using 

rodents, various types of human cells, and a salmonella strain containing human P450 genes 

(McGuire et al., 2014; Parker et al., 2014; States et al., 2013; Krasner, 2009; Richardson et al., 2007). 

As with brominated DBPs, there is concern that some iodinated forms of DBPs are more cytotoxic 

and genotoxic than chlorinated species (McGuire et al., 2014; Parker et al., 2014; Krasner, 2009; 

Richardson et al., 2007), as evidenced by studies involving rodent research and human cell research 

(Plewa et al., 2010; Plewa and Wagner, 2009; Richardson et al., 2007). The MCLs (mg/L) for the 

regulated DBPs are: 0.01 for bromate, 1.0 for chlorite, 0.06 for haloacetic acid, and 0.08 for total 

trihalomethanes.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.5.7 Chemicals Detected in Multiple Stages of the Hydraulic Fracturing Water Cycle

As mentioned in Section 9.3 above, there were a total of 77 chemicals on EPA’s list that were 

identified as being used in hydraulic fracturing fluids and detected in produced water. The presence 

of these chemicals within both of these stages of the hydraulic fracturing water cycle may indicate 

that these chemicals persist after they are injected into the well. However, this is not necessarily the 

case, as some of these chemicals (e.g., BTEX, naphthalene, metals) also occur naturally in oil and gas 

reservoirs. Additionally, the EPA’s list of chemicals used in hydraulic fracturing fluids and list of 

chemicals in produced water were compiled from different sets of sources, and does not provide a 

matched comparison between the chemicals used in hydraulic fracturing fluid and the chemicals 

present in produced water at a particular site. There may have been other chemicals in present in

produced water that were not detected by these studies due to limitations of analytical chemistry. 

Thus, the EPA’s composited chemical list cannot reliably be used to draw conclusions on the 

persistence of hydraulic fracturing chemicals following well injection. 

Of the 77 chemicals identified in both hydraulic fracturing fluids and produced water, 45 have a 

chronic oral RfV or OSF available from at least one of the sources in Table 9-1. These 45 chemicals 

and their respective toxicity values are shown in Table 9-10, with frequency of use data from the 

EPA FracFocus 1.0 project database provided when available. Eleven of these chemicals are 

regulated as drinking water contaminants. 

Table 9-10. List of 45 chemicals on EPA’s list that were used in hydraulic fracturing fluids and 

detected in produced water and have an RfV or OSF available. 

Frequency of use data from the EPA FracFocus 1.0 project database is provided when available. Chemicals with 

available data from the FracFocus 1.0 project database are ordered from high to low based on frequency of use. 

Chemicals without frequency of use data are ordered from most toxic to least toxic based on chronic oral RfV.

*Indicates chemicals that are regulated as drinking water contaminants under the NPDWRs.

Chronic oral RfVsb OSFsd

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kgday)Source 

of RfV Critical Effectc

OSF 

(per mg/kgday)Source 

of OSF

Methanol 67-56-1 73% 2 IRIS Extra cervical ribs

Ethylene glycol 107-21-1 47% 2 IRIS Kidney toxicity

Propargyl alcohol 107-19-7 33% 0.002 IRIS Renal and 

hepatotoxicity

2-Butoxyethanol 111-76-2 23% 0.1 IRIS 

Hemosiderin 

deposition in liver 

(inhalation study)

Naphthalene 91-20-3 19% 0.02 IRIS 

Decreased mean 

terminal body 

weight in males
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Chronic oral RfVsb OSFsd

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kgday)Source 

of RfV Critical Effectc

OSF 

(per mg/kgday)Source 

of OSF

1,2,4-

Trimethylbenzene 95-63-6 13% 0.01 IRIS Decreased pain sensitivity

Formic acid 64-18-6 11% 0.9 PPRTV Reproductive 

Toxicity

N,NDimethylformamide 68-12-2 9% 0.1 PPRTV

Increase in ALT 

enzyme and liver 

weight

Benzyl chloride 100-44-7 6% 0.002 PPRTV Cardiotoxicity 0.17 IRIS

1,2-Propylene glycol 57-55-6 4% 20 PPRTV

Reduced RBC 

counts and 

hyperglycemia

Xylenes* 1330-20-7 2% 0.2 IRIS 

Decreased body 

weight, increased 

mortality

D-Limonene 5989-27-5 2% 0.1 CICAD Increased liver 

weight

1-Butanol 71-36-3 1% 0.1 IRIS Hypoactivity and 

ataxia

Toluene* 108-88-3 0.7% 0.08 IRIS Increased kidney 

weight

Bis(2-chloroethyl) 

ether 111-44-4 0.7% 1.1 IRIS 

2-(2-

Butoxyethoxy)ethan

ol

112-34-5 0.6% 0.03 PPRTV Changes in red 

blood cells (RBC)

1,3,5-

Trimethylbenzene 108-67-8 0.5% 0.01 IRIS Decreased pain sensitivity

Cumene 98-82-8 0.5% 0.1 IRIS 

Increased average 

kidney weight in 

female rats

Iron 7439-89-6 0.4% 0.7 PPRTV

Adverse 

gastrointestinal 

effects

1,2,3-

Trimethylbenzene 526-73-8 0.4% 0.01 IRIS Decreased pain sensitivity
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Chronic oral RfVsb OSFsd

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kgday)Source 

of RfV Critical Effectc

OSF 

(per mg/kgday)Source 

of OSF

Phenol 108-95-2 0.4% 0.3 IRIS 

Decreased 

maternal weight 

gain

Ethylbenzene* 100-41-4 0.4% 0.1 IRIS Liver and kidney 

toxicity 0.011 CalEPA

1,4-Dioxane 123-91-1 0.3% 0.03 IRIS Liver and kidney 

toxicity 0.1 IRIS 

Acetone 67-64-1 0.2% 0.9 IRIS Nephropathy

Boron 7440-42-8 0.05% 0.2 IRIS Decreased fetal 

weight

o-Xylene* 95-47-6 0.05% 0.2 ATSDR Neurotoxicity

Acetophenone 98-86-2 0.04% 0.1 IRIS General toxicity

Quinoline 91-22-5 0.02% 3 IRIS

Dichloromethane* 75-09-2 0.02% 0.006 IRIS 

Hepatic effects 

(hepatic 

vacuolation, liver 

foci)

0.002 IRIS 

Trimethylbenzene 25551-13-7 0.01% 0.01 IRIS Decreased pain 

sensitivity

Benzene* 71-43-2 0.01% 0.004 IRIS Decreased 

lymphocyte count 0.015-0.055 IRIS 

Bisphenol A 80-05-7 0.01% 0.05 IRIS Reduced mean 

body weight

Aluminum 7429-90-5 0.003% 1 PPRTV Neurotoxicity

Hydrazine 302-01-2 0.003% 3 IRIS

Chlorobenzene* 108-90-7 0.003% 0.02 IRIS Histopathologic 

changes in liver

Arsenic* 7440-38-2 0.0003 IRIS 

Hyperpigmentation 

and vascular 

complications

1.5 IRIS 

Acrolein 107-02-8 0.0005 IRIS Decreased survival

Chromium (VI) 18540-29-9 0.003 IRIS None reported 0.5 CalEPA

Tributyl phosphate 126-73-8 0.01 PPRTV Occasional 

salivation 0.009 PPRTV
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Chronic oral RfVsb OSFsd

Chemical Name CASRN

% of 

Disclosuresa

RfV 

(mg/kgday)Source 

of RfV Critical Effectc

OSF 

(per mg/kgday)Source 

of OSF

Di(2-ethylhexyl) 

phthalate* 117-81-7 0.02 IRIS Increased relative liver weight 0.014 IRIS 

Chlorine 7782-50-5 0.1 IRIS No adverse effect 

level

p-Xylene* 106-42-3 0.2 ATSDR Neurotoxicity

Zinc 7440-66-6 0.3 IRIS 

Decreases in 

erythrocyte Cu, Znsuperoxide 

dismutase (ESOD) 

activity in humans

Lead* 7439-92-1 0.5 

μg/day e

CalEPA Reproductive 

toxicity 0.0085 CalEPA

Chromium (III) 16065-83-1 1.5 IRIS

CASRN = Chemical Abstract Service Registry Number; RfV = Reference value; IRIS = Integrated Risk Information System; PPRTV =

Provisional Peer-Reviewed Toxicity Value; HHBP = Human Health Benchmarks for Pesticides; ATSDR = Agency for Toxic 

Substances and Disease Registry; CalEPA = California Environmental Protection Agency; CICAD = Concise International Chemical

Assessment Documents; QSAR = Quantitative structure-activity relationship; TOPKAT = Toxicity Prediction by Komputer Assisted

Technology; ACToR = EPA’s Aggregated Computational Toxicology Online Resource

a The FracFocus frequency of use data presented in this chapter is based on 35,957 FracFocus disclosures that were

deduplicated, within the study time period (January 1, 2011 to February 28, 2013), and with ingredients that have a valid

CASRN.

b Reference value (RfV): 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. RfVs considered in this 

analysis include chronic oral reference doses (RfDs) from IRIS, PPRTV, and HHBP; chronic oral minimal risk levels (MRLs) from

ATSDR; maximum allowable daily levels (MADLs) from CalEPA; and tolerable daily intake (TDI) from CICAD. See Section 9.4.1. 

c Critical effect: The first adverse effect, or its known precursor, that occurs to the most sensitive species as the dose rate of an 

agent increases.

d 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. OSFs considered in this analysis include values from IRIS, PPRTV, HHBP, and CalEPA. See Section 9.4.1. 

e CalEPA MADLs are in units of μg/day, while all other chronic oral RfVs in this table are in units of mg/kg-day.

9.6 Hazard Evaluation of Selected Subsets of Hydraulic Fracturing Chemicals 

Using Multi-Criteria Decision Analysis (MCDA): Integrating Toxicity, 

Occurrence, and Physicochemical Data

Based on the information presented in Section 9.5, it is clear that there are a variety of chemicals 

used in hydraulic fracturing fluids or detected in produced water that are known to be hazardous to 

human health. However, there are gaps in our understanding of the potential for human exposure 

to these chemicals. Although there are subsurface and surface pathways by which these chemicals 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-52 

may be introduced into drinking water resources—including spills, leaks, mechanical integrity 

failures, intersection of the fracture network with groundwater, or discharge of wastewater, as 

described in previous chapters of this report—there are significant limitations associated with the 

publicly available data on these potential impacts, and the potential for human exposure has not 

been systematically characterized. This makes it difficult to determine which chemicals are of the 

greatest concern for human exposure in drinking water, and creates a challenge for hazard 

evaluation.

Although exposure assessment data are limited, some of the chemicals identified by EPA have other 

data available that might provide preliminary insight into relative hazard potential. This includes 

data on toxicity, frequency of use in hydraulic fracturing fluids, detected concentrations in

produced water, and data on physicochemical properties. By integrating these types of data, we can 

place the severity of potential impacts (i.e., the toxicity of specific chemicals) into the context of 

factors that affect the likelihood of impacts (i.e., frequency of use, environmental fate and 

transport). 

Multi-criteria decision analysis (MCDA) is one possible approach that can be used to facilitate data 

integration. MCDA is a well-established decision support tool, which is used to integrate multiple 

lines of evidence to develop an overall ranking or classification (Hristozov et al., 2014; Mitchell et 

al., 2013b; Huang et al., 2011; Linkov et al., 2011). Using MCDA, a problem is approached by 

dividing it into smaller criteria that need to be evaluated; the criteria are each analyzed 

individually, and then combined to provide an integrated evaluation. This approach is structured 

yet flexible, and offers a transparent means of combining information to provide weight of evidence 

and insight into a complex problem. MCDA has gained increasing popularity as an environmental 

decision-making tool (Huang et al., 2011). A recent publication by Yost et al. (In Press) described 

the use of an MCDA framework to evaluate the hazard potential of chemicals associated with 

hydraulic fracturing. 

Here, to demonstrate one possible method for exploring the potential hazards of these chemicals, 

we use an adaptation of the MCDA framework developed by Yost et al. (In Press) to analyze and 

rank selected subsets of chemicals that have data available.1 Chemicals were assigned scores based 

on toxicity, occurrence, and physicochemical properties that describe transport in water. These 

scores were then combined to develop a relative ranking of chemicals based on hazard potential. 

The MCDA scores provide a preliminary evaluation of hazard potential, and serve as a qualitative 

metric for making comparison between chemicals when exposure assessment data is limited or 

unavailable. This analysis is not intended to define whether or not a chemical will present a human 

health hazard or indicate that one chemical is safer than another, and should not be used in place of 

1 Yost et al. (In Press) used the MCDA framework to analyze and rank the hazards of chemicals used in hydraulic 

fracturing fluids, using data from the FracFocus 1.0 project database as the metric of occurrence. This chapter uses that 

same framework for the analysis of chemicals used in hydraulic fracturing fluids. For chemicals detected in produced 

water, this chapter modifies the MCDA framework by using measured concentration in produced water as the metric of 

occurrence.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-53 

site-specific data on chemical exposures. An overview of the MCDA framework and selection of 

chemicals for inclusion in the MCDA is described below.

9.6.1 Overview of the MCDA Framework for Hazard Evaluation

The MCDA framework employed in this chapter was designed specifically to fit the scope of EPA’s 

hydraulic fracturing study (Yost et al., In Press). A basic schematic of the model is shown in Figure 

9-5, and the methods for assigning scores are outlined below. Under the MCDA framework, each

chemical was assigned three scores:

1. A Toxicity Score;

2. An Occurrence Score; and

3. A Physicochemical Properties score.

The three scores were each standardized based on the highest and lowest respective score within 

the given subset of chemicals, and then summed to develop a Total Hazard Potential Score for each 

chemical. The Total Hazard Potential Scores reflect a relative ranking of each chemical within the 

given subset of chemicals, and offer a means of making comparisons between chemicals.

Figure 9-5. Overview of the MCDA framework for hazard evaluation. 

Source: Yost et al. (In Press). 

9.6.2 Selection of Chemicals for Hazard Evaluation in the MCDA Framework

From the overall list of 1,606 chemicals identified in this assessment, subsets of chemicals were 

selected for hazard evaluation in the MCDA framework if they had sufficient data for inclusion, 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-54 

using an adaptation of the criteria outlined by Yost et al. (In Press). Specifically, chemicals were 

selected if they had the following information available: 

1. Had a chronic oral RfV or OSF from a US federal source (IRIS, PPRTV, ATSDR, HHBP);

2. Had available data on frequency of use in hydraulic fracturing fluids (data available from

the EPA FracFocus 1.0 project database) or measured concentrations in produced water

(data available from Appendix E)1; and

3. Had data on physicochemical properties available from EPI Suite.

The rationale for applying these criteria is as follows: 

1. Federal toxicity values generally undergo more extensive peer review compared to other

sources of toxicity values, and are based on the best available scientific information. For

this reason, EPA generally prefers to apply RfVs and OSFs from US federal sources for

human health risk assessment.

2. Data on frequency of use (in hydraulic fracturing fluids) or measured concentration (in

produced water) provide a metric to help assess the likelihood of chemical occurrence in

the hydraulic fracturing water cycle.

3. Information on physicochemical properties enables estimation of the likelihood a

chemical will be transported in water.

Chemicals used in hydraulic fracturing fluids and chemicals detected in produced water were 

evaluated separately using the MCDA framework. To explore the different types of toxicity values 

identified by EPA, two versions of the MCDA were performed on each of these subsets of chemicals: 

a noncancer MCDA, in which the Toxicity Score is calculated using chronic oral RfVs; and a cancer 

MCDA, in which the Toxicity Score is calculated using OSFs. For chemicals used in hydraulic 

fracturing fluids, the noncancer MCDA was repeated for specific subsets of chemicals used in three 

states that have a significant amount of hydraulic fracturing activity: Texas, Pennsylvania, and 

North Dakota. Thus, seven iterations of the MCDA were performed: 1-4) noncancer MCDAs for 

chemicals used in hydraulic fracturing fluids on a national or state-specific basis, 5) a cancer MCDA 

for chemicals used in hydraulic fracturing fluids, 6) a noncancer MCDA for chemicals detected in 

produced water, and 7) a cancer MCDA for chemicals detected in produced water.

In total, 42 chemicals used in hydraulic fracturing fluid and 29 chemicals detected in produced 

water had sufficient information available for inclusion in noncancer MCDAs (Figure 9-6), while 10 

chemicals used in hydraulic fracturing fluid and 7 chemicals detected in produced water had 

sufficient information available for inclusion in cancer MCDAs (Figure 9-7).

1 Chemicals in produced water were considered for the MCDA if they had average or median measured concentrations 

from any of the tables in Appendix E. Chemicals with only a maximum or minimum concentration listed in Appendix E 

were not considered for the MCDA.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-6. The subsets of chemicals selected for hazard evaluation using the noncancer MCDA framework included 42 chemicals 

used in hydraulic fracturing fluids and 29 chemicals detected in produced water.

For chemicals used in hydraulic fracturing fluids, subsets of these chemicals were also considered in state-specific analyses for Texas (36 chemicals), 

Pennsylvania (20 chemicals), and North Dakota (21 chemicals).
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-7. The subsets of chemicals selected for hazard evaluation using the cancer MCDA framework included 10 chemicals used 

in hydraulic fracturing fluids, and 7 chemicals detected in produced water.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.6.3 Calculation of MCDA Scores

For each iteration of the MCDA, chemicals were assigned scores based on toxicity, occurrence, and 

physicochemical properties according to the protocol outlined by Yost et al. (In Press). These scores 

were then standardized to the highest and lowest score within the given subset of chemicals, and 

then summed to determine a total score and relative ranking for each chemical. The methods used 

to assign each score and calculate a total score are outlined below. 

9.6.3.1 Toxicity Score (Noncancer MCDA)

For each noncancer MCDA, Toxicity Scores were calculated based on chronic oral RfVs from US 

federal sources (IRIS, PPRTV, ATSDR, and HHBP). If a chemical had a chronic oral RfV available 

from more than one of these sources, a single value was selected in this order, as described in 

Section 9.4: HHBP (pesticides), IRIS, PPRTV, ATSDR. Toxicity Scores for the noncancer MCDA were 

then assigned based on a relative ranking. Within each suite of chemicals considered in this analysis 

(chemicals used in hydraulic fracturing fluids, or chemicals detected in produced water), RfVs were 

ranked based on quartiles, and each chemical was assigned a Toxicity Score of 1 to 4 (Table 9-11). 

Chemicals in the lowest quartile received the highest Toxicity Score, as these chemicals have lower 

RfVs than other chemicals (i.e., may have lower thresholds for toxicity).

9.6.3.2 Toxicity Score (Cancer MCDA)

For each cancer MCDA, Toxicity Scores were calculated based on OSFs from US federal sources 

(IRIS, PPRTV, and HHBP). If a chemical had an OSF available from more than one of these sources, a 

single value was selected in this order, as described in Section 9.4: HHBP (pesticides), IRIS, PPRTV. 

Toxicity Scores for the cancer MCDA were assigned based on a relative ranking. Within each suite of 

chemicals considered in this analysis (chemicals used in hydraulic fracturing fluids, or chemicals 

detected in produced water), OSFs were ranked based on quartiles, and each chemical was assigned 

a Toxicity Score of 1 to 4 (Table 9-11). Chemicals in the highest quartile received the highest 

Toxicity Score, as these chemicals have higher OSFs than other chemicals (i.e., are associated with a 

higher increased risk of cancer per unit of exposure).

9.6.3.3 Occurrence Score 

For each of the noncancer and cancer MCDAs, an Occurrence Score was calculated based on the 

frequency or concentration at which each chemical was reported within the hydraulic fracturing 

water cycle. For chemicals used in hydraulic fracturing fluids, the Occurrence Score was based on 

the number of well disclosures for each chemical in the EPA FracFocus 1.0 project database. For 

chemicals detected in produced water, the Occurrence Score was based on the average or median 

measured concentration reported in Appendix E. If an average or median concentration of a 

chemical was reported by multiple studies in Appendix E, the highest of these reported average or 

median concentrations was used for this calculation. Once a value was determined for each 

chemical, Occurrence Scores were then assigned based on a relative ranking. Within each suite of 

chemicals considered in this analysis (chemicals used in hydraulic fracturing fluids, or chemicals 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-58 

detected in produced water), chemical occurrence was ranked based on quartiles, with each 

chemical assigned an Occurrence Score of 1 to 4 (Table 9-11).

9.6.3.4 Physicochemical Properties Score

For each of the noncancer and cancer MCDAs, a Physicochemical Properties Score was calculated 

based upon inherent physicochemical properties that describe the likelihood that a chemical will be 

transported in water. The total Physicochemical Properties Score was calculated as the sum of 

three subcriteria scores: a Mobility Score, a Volatility Score, and a Persistence Score. The Mobility 

Score was assessed based upon three physicochemical properties that describe chemical solvency 

in water: the octanol-water partition coefficient (Kow), the soil adsorption coefficient (Koc), and 

aqueous solubility. The Volatility Score was assessed based on the Henry’s law constant, which 

describes partitioning of a chemical between water and air. The Persistence Score was assessed 

based on estimated half-life in water, which describes how long a chemical will remain in water 

before it is degraded. 

For input into the MCDA, experimentally measured physicochemical property values (provided in 

EPI Suite) were used whenever available. Otherwise, estimated values from EPI Suite were used. To 

classify these values and assign a score, these numerical values were compared against threshold 

values (Table 9-11). Each chemical was assigned a Mobility Score, Volatility Score, and Persistence 

Score (each on a scale of 1 to 4), which were then summed to calculate the Physicochemical 

Properties Score. The threshold values in Table 9-11 are based upon previously published values 

employed by existing exposure assessment models, including the EPA’s Design for the Environment 

Alternatives Assessment Criteria for Hazard Evaluation (U.S. EPA, 2011b), the EPA’s Pollution 

Prevention (P2) Framework (U.S. EPA, 2012i), and a peer-reviewed publication by Mitchell et al. 

(2013b). More details on the Physicochemical Properties Score calculation are provided in the 

Chapter 9 Annex, Section 9.8.1. 

9.6.4 Total Hazard Potential Score

Within each iteration of the MCDA, the three criteria scores (Toxicity, Occurrence, Physicochemical 

Properties) were each standardized to the dataset by scaling to the highest and lowest respective 

score within the given subset of chemicals. The following equation was used:

Sx_final = (Sx – Smin) / (Smax – Smin) 

in which Sx is the raw score for a particular chemical, Smax is the highest observed raw score within 

the set of chemicals, and Smin is the lowest observed raw score within the set of chemicals. Sx_final is 

the standardized score for the chemical. Each standardized score (Toxicity, Occurrence, or 

Physicochemical Properties) falls on a scale of 0 to 1, and represents a relative ranking within the 

given subset of chemicals. 

The standardized Toxicity Score, Occurrence Score, and Physicochemical Properties Score were 

summed to calculate a Total Hazard Potential Score for each chemical. The Total Hazard Potential 

Scores fall on a scale of 0 to 3, with higher scores indicating chemicals that may be more likely to 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-59 

affect drinking water resources. Examples of the Total Hazard Potential Score calculation can be 

found in the Chapter 9 Annex, Section 9.8.2.

Table 9-11. Thresholds used for developing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score in this MCDA framework. 

Adapted from Yost et al. (In Press). 

Score

Criteria Sub-criteria Value 1 2 3 4

Toxicity 

(Noncancer MCDA) NA Chronic oral RfV (mg/kg-day)

>3rd

quartile

>2nd quartile to

≤3rd quartile

>1st quartile to

≤2nd quartile

≤1st 

quartile

Toxicity 

(Cancer MCDA) NA OSF (per mg/kgday)

<1st 

quartile

≥1st quartile to 

<2nd quartile

≥2nd quartile to 

<3rd quartile

≥3rd 

quartile

Occurrence NA

Frequency of 

use (% of 

disclosures in

EPA’s FracFocus 

1.0 project 

database) 

or 

Measured 

concentration in 

produced water 

(μg/L; Appendix 

E)

<1st 

quartile

≥1st quartile to 

<2nd quartile

≥2nd quartile to 

<3rd quartile

≥3rd 

quartile

Physico-chemical 

Properties 

Mobility 

Log KOW >5 >3 to ≤5 >2 to ≤3 ≤2

Log KOC >4.4 >3.4 to ≤4.4 >2.4 to ≤3.4 ≤2.4

Aqueous 

solubility (mg/L) <0.1 ≥0.1 to <100 ≥100 to <1000 ≥1000

Volatility Henry’s law 

constant

>10-1 >10-3 to ≤10-1 >10-5 to ≤10-3 ≤10-5

Persistence Half-life in 

water (days) <16 ≥16 to <60 ≥60 to <180 ≥180

9.6.5 MCDA Results

For each iteration of the MCDA, we first present the data used for input into the MCDA, including 

data on toxicity, occurrence, and physicochemical properties. We then present the results of each 

MCDA, which show a relative ranking of chemicals based on integration of these data. Lastly, we 

discuss the key limitations of this MCDA approach, which is intended as a preliminary analysis only.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.6.5.1 Results: Noncancer MCDA for Chemicals Used in Hydraulic Fracturing Fluids 

A total of 42 chemicals used in hydraulic fracturing fluids were evaluated in a noncancer MCDA 

(Table 9-12). Chronic oral RfVs within this suite of chemicals range from 0.001−20 mg/kg-day, with 

(E)-crotonaldehyde having the lowest chronic oral RfV and 1,2-propylene glycol having the highest. 

These RfVs were derived based on health effects including immune system effects, changes in body 

weight, changes in blood chemistry, cardiotoxicity, neurotoxicity, liver and kidney toxicity, and 

reproductive and developmental toxicity. The total UFs used in the derivation of these chronic oral 

RfVs (Table 9-12) reflect varying degrees of confidence surrounding the data sets for these 

chemicals. Three of the chemicals with the lowest chronic oral RfVs [(E)-crotonaldehyde, propargyl 

alcohol, benzyl chloride] have total UFs of 3000, indicating a relatively large amount of uncertainty 

in these values. Comparatively, chemicals such as benzene, acrylamide, and dichloromethane also 

have low chronic oral RfVs, but with much less uncertainty reflected in the values. 

Figure 9-8 presents the results of a noncancer MCDA for these 42 chemicals in hydraulic fracturing 

fluids. Of these 42 chemicals, propargyl alcohol received the highest overall Total Hazard Potential 

Score. Propargyl alcohol was reported in 33% of disclosures nationally in the EPA FracFocus 1.0 

project database, making it one of the most widely used chemicals that was considered in this 

analysis. It has physicochemical properties that are conducive to transport in water, and a low RfV. 

Given these properties, propargyl alcohol received the highest overall ranking based on hazard 

potential across all of the metrics that were considered in the MCDA. 

Several of the other chemicals that received high Occurrence Scores also received among the 

highest Total Hazard Potential Scores, including 2-butoxyethanol, naphthalene, 1,2,4-

trimethylbenzene, N,N-dimethylformamide, and formaldehyde (reported in 23%, 19%, 13%, 9%, 

and 7% of disclosures, respectively). Methanol, ethylene glycol, and formic acid (73%, 47%, and 

11% of disclosures, respectively) received lower Total Hazard Potential Scores as a result of having 

higher RfVs. Likewise, didecyldimethylammonium chloride and dodecylbenzenesulfonic acid (8% 

and 7% of disclosures, respectively) received lower Total Hazard Potential Scores as a result of 

having higher RfVs and more hydrophobic properties. 

The other chemicals that received high Toxicity Scores (i.e., had low chronic oral RfVs) received 

moderate to high Total Hazard Potential Scores overall. Acrylamide was reported in only 1% of 

disclosures, but has physicochemical properties that are very conducive to transport in water, and 

therefore received one of the highest overall Total Hazard Potential Scores. 1,2,4-

Trimethylbenzene, benzyl chloride, and epichlorohydrin (13%, 6%, and 1% of disclosures in the 

EPA FracFocus 1.0 project database, respectively) scored slightly lower than acrylamide with 

regards to physicochemical properties. Other chemicals, including 1,2,3-trimethylbenzene, 1,3,5-

trimethylbenzene, (E)-crotonaldehyde, benzene, dichloromethane, aniline, furfural, and 2-

(Thiocyanomethylthio)benzothiazole, received lower overall scores because they are used more 

infrequently (the trimethylbenzenes were reported in <1% of disclosures, and the rest reported in 

<0.1% of disclosures).
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.6.5.2 Results: Noncancer MCDA for Chemicals Used in Hydraulic Fracturing Fluids (Statespecific analysis for Texas, Pennsylvania, and North Dakota)

To investigate the extent of regional differences and examine the applicability of the MCDA model 

at the regional scale, we repeated the noncancer MCDA for hydraulic fracturing fluids for subsets of 

chemicals used in three representative states that have a significant amount of hydraulic fracturing 

activity: Texas, Pennsylvania, and North Dakota. The chemicals used in these state-specific analyses 

are subsets of the chemicals used nationally, and are indicated in Table 9-12. Some of the chemicals 

considered in the national analysis were not included in the state-specific analyses because they 

were not disclosed to FracFocus 1.0 as used in these states. 

Results are presented in Figure 9-9 (Texas), Figure 9-10 (Pennsylvania), and Figure 9-11 (North 

Dakota). By comparing these results to each other and to the national noncancer MCDA (Figure 

9-8), it is evident that there are some regional differences in the Total Hazard Potential Scores,

although many chemicals were commonly used and received similar overall rankings.

Methanol, ethylene glycol, and 2-butoxyethanol were among the most frequently reported 

chemicals in all three state-specific analyses, while other chemicals differed distinctly between 

states. For instance, propargyl alcohol was frequently reported in Texas (39% of disclosures) and 

Pennsylvania (58% of disclosures), but not North Dakota (1% of disclosures). Likewise, 

naphthalene was reported frequently in Texas (14% of disclosures) and North Dakota (43% of 

disclosures), but not in Pennsylvania (1% of disclosures). The most toxic chemicals (occurring in 

the lowest quartile of chronic oral RfVs) common among all three states include propargyl alcohol, 

benzyl chloride, acrylamide, and 1,2,4-trimethylbenzene. Other chemicals receiving high Toxicity 

Scores in these states include epichlorohydrine (Texas and Pennsylvania), 1,3,5-Trimethylbenzene

(Texas and Pennsylvania), 1,4-dioxane (North Dakota), naphthalene (North Dakota), benzene, 

aniline, and 1,2,3-Trimethylbenzene (Texas). 

Overall, in Texas, propargyl alcohol received the highest possible Total Hazard Potential Score, with 

acrylamide receiving the second highest score. In Pennsylvania, propargyl alcohol also received the 

highest possible Total Hazard Potential Score, with 2-butoxyethanol receiving the second highest 

score. In North Dakota, 2-butoxyethanol received the highest Total Hazard Potential Score, with 

naphthalene receiving the second highest score.

The results of these state-specific MCDAs support the concept presented in Chapter 5 that there is 

no single hydraulic fracturing fluid formulation, and that the chemicals of most potential concern 

will vary between regions or even between wells.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-62 

Table 9-12. Data on the selected subset of chemicals in hydraulic fracturing fluids used for input into a noncancer MCDA.

Chemicals within the table are ordered from most toxic to least toxic based on chronic oral RfV. 

Noncancer toxicity 

(chronic oral RfV)a

% disclosures in EPA 

FracFocus 1.0 project 

databaseb Mobility Volatility

Persistence

Chemical Name CASRN

RfV 

(mg/

kg-day)

Total 

UF Source National TX PA ND

Log 

KOW

Log 

KOC

Solubility 

(mg/L)

Henry's 

Law 

Constant

Half-life 

in water 

(days)

(E)-Crotonaldehyde 123-73-9 0.001 3000 PPRTV 0.06% 0.6 0.254 41480 1.94E-05 15

Propargyl alcohol 107-19-7 0.002 3000 IRIS 33% 39% 58% 1% -0.38 0.28 935500 1.15E-06 15

Benzyl chloride 100-44-7 0.002 3000 PPRTV 6% 7% 5% 0.80% 2.3 2.649 1030 4.12E-04 15

Acrylamide 79-06-1 0.002 30 IRIS 1% 2% 1% 1% -0.67 0.755 504000 1.70E-09 15

Benzene 71-43-2 0.004 300 IRIS 0.006% 0.01% 2.13 1.75 2000 5.55E-03 37.5

Epichlorohydrin 106-89-8 0.006 1000 PPRTV 1% 0.20% 0.08% 0.45 1 50630 3.04E-05 15

Dichloromethane 75-09-2 0.006 30 IRIS 0.02% 1.25 1.44 10950 3.25E-03 37.5

Aniline 62-53-3 0.007 1000 PPRTV 0.02% 0.05% 0.9 1.6 20820 2.02E-06 15

1,2,4-

Trimethylbenzene 95-63-6 0.01 300 IRIS 13% 11% 1% 25% 3.63 2.788 79.59 6.16E-03 37.5

1,3,5-

Trimethylbenzene 108-67-8 0.01 300 IRIS 0.5% 0.80% 1% 3.42 2.82 120.3 8.77E-03 37.5

1,2,3-

Trimethylbenzene 526-73-8 0.01 300 IRIS 0.4% 0.80% 3.66 2.8 75.03 4.36E-03 37.5

2-(Thiocyanomethylthio)benzothiazole21564-17-

0 0.01 300 HHBP 0.006% 3.3 3.528 41.67 6.49E-12 37.5

Furfural 98-01-1 0.01 3000 HHBP 0.003% 0.41 0.784 53580 3.77E-06 15

Naphthalene 91-20-3 0.02 3000 IRIS 19% 14% 1% 43% 3.3 2.96 142.1 4.40E-04 37.5
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-63 

Noncancer toxicity 

(chronic oral RfV)a

% disclosures in EPA 

FracFocus 1.0 project 

databaseb Mobility Volatility

Persistence

Chemical Name CASRN

RfV 

(mg/

kg-day)

Total 

UF Source National TX PA ND

Log 

KOW

Log 

KOC

Solubility 

(mg/L)

Henry's 

Law 

Constant

Half-life 

in water 

(days)

Chlorobenzene 108-90-7 0.02 1000 IRIS 0.003% 0.01% 2.84 2.15 400.5 3.11E-03 15

2-(2-Butoxyethoxy)

ethanol 112-34-5 0.03 3000 PPRTV 0.6% 0.40% 4% 0.56 1 71920 7.20E-09 8.67

1,4-Dioxane 123-91-1 0.03 300 IRIS 0.3% 0.50% 0.80% -0.27 0.421 213900 4.80E-06 15

1,3-Dichloropropene 542-75-6 0.03 100 IRIS 0.02% 2.04 1.82 1994 3.55E-03 37.5

Bisphenol A 80-05-7 0.05 1000 IRIS 0.006% 0.01% 3.32 4.576 172.7 9.16E-12 37.5

Toluene 108-88-3 0.08 3000 IRIS 0.7% 1% 2.73 2.07 573.1 6.64E-03 15

Ethylenediamine 107-15-3 0.09 100 PPRTV 0.01% 0.02% -2.04 1.172 1000000 1.73E-09 15

2-Butoxyethanol 111-76-2 0.1 10 IRIS 23% 27% 21% 15% 0.83 0.451 64470 1.60E-06 8.67

N,N-Dimethylformamide 68-12-2 0.1 1000 PPRTV 9% 10% 11% 0.60% -1.01 0 977900 7.39E-08 15

Didecyldimethylammonium chloride 7173-51-5 0.1 100 HHBP 8% 7% 12% 0.05% 4.66 5.546 0.9 6.85E-10 15

1-Butanol 71-36-3 0.1 1000 IRIS 1% 2% 0.70% 0.88 0.5 76700 8.81E-06 8.67

Cumene 98-82-8 0.1 1000 IRIS 0.5% 0.80% 1% 3.66 2.844 75.03 1.15E-02 15

Ethylbenzene 100-41-4 0.1 1000 IRIS 0.4% 0.50% 0.10% 3.15 2.23 228.6 7.88E-03 15

Acetophenone 98-86-2 0.1 3000 IRIS 0.04% 0.04% 1.58 1.8 4484 1.04E-05 15

Formaldehyde 50-00-0 0.2 100 IRIS 7% 8% 4% 8% 0.35 0 57020 3.37E-07 15

Xylenes 1330-20-7 0.2 1000 IRIS 2% 3% 1% 0.20% 3.2 2.25 207.2 7.18E-03 15
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-64 

Noncancer toxicity 

(chronic oral RfV)a

% disclosures in EPA 

FracFocus 1.0 project 

databaseb Mobility Volatility

Persistence

Chemical Name CASRN

RfV 

(mg/

kg-day)

Total 

UF Source National TX PA ND

Log 

KOW

Log 

KOC

Solubility 

(mg/L)

Henry's 

Law 

Constant

Half-life 

in water 

(days)

o-Xylene 95-47-6 0.2 30 ATSDR 0.05% 0.1% 3.12 2.25 224.1 5.18E-03 15

Phenol 108-95-2 0.3 300 IRIS 0.4% 0.80% 0.05% 1.46 1.9 26160 3.33E-07 15

2-Methyl-1-propanol 78-83-1 0.3 1000 IRIS 0.3% 4% 0.76 0.465 97120 9.78E-06 15

Dodecylbenzenesulfonic acid27176-87-

0 0.5 100 HHBP 7% 10% 2% 8% 4.71 4.066 0.8126 6.27E-08 15

Formic acid 64-18-6 0.9 300 PPRTV 11% 14% 8% 11% -0.54 0 955200 1.67E-07 8.67

Ethyl acetate 141-78-6 0.9 1000 IRIS 0.4% 0.70% 0.73 0.747 29930 1.34E-04 15

Acetone 67-64-1 0.9 1000 IRIS 0.2% 0.02% 1% -0.24 0.374 219900 3.50E-05 15

Methanol 67-56-1 2 100 IRIS 73% 80% 69% 54% -0.77 0.44 1000000 4.55E-06 8.67

Ethylene glycol 107-21-1 2 100 IRIS 47% 60% 35% 37% -1.36 0 1000000 6.00E-08 8.67

Hexanedioic acid 124-04-9 2 300 PPRTV 0.70% 1% 0.08 1.386 167300 4.71E-12 8.67

Benzoic acid 65-85-0 4 1 IRIS 0.06% 0.10% 0.04% 1.87 1.5 2493 3.81E-08 15

1,2-Propylene glycol 57-55-6 20 300 PPRTV 4% 4% 8% 8% -0.92 0.36 811100 1.29E-08 8.67

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for Toxic 

Substances and Disease Registry; HHBP = Human Health Benchmarks for Pesticides; KOW = octanol-water partitioning coefficient; KOC = soil adsorption coefficient

a Reference value (RfV): 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. RfVs considered in the MCDA include chronic oral reference doses (RfD) from IRIS, PPRTV, and HHBP; and chronic oral minimal risk 

levels (MRLs) from ATSDR.

b The FracFocus frequency of use data presented in this chapter is based on 35,957 FracFocus disclosures that were deduplicated, within the study time period (January 1, 2011 

to February 28, 2013), and with ingredients that have a valid CASRN.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-8. Noncancer MCDA results for 42 chemicals used in hydraulic fracturing fluids 

(national analysis), showing the Toxicity Score, Occurrence Score, and Physicochemical 

Properties Score for each chemical.

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the 

calculation. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-9. Noncancer MCDA results for 36 chemicals used in hydraulic fracturing fluids in 

Texas (state-specific analysis), showing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score for each chemical. 

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the 

calculation. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-10. Noncancer MCDA results for 20 chemicals used in hydraulic fracturing fluids in 

Pennsylvania (state-specific analysis), showing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score for each chemical. 

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the 

calculation.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-11. Noncancer MCDA results for 21 chemicals used in hydraulic fracturing fluids in 

North Dakota (state-specific analysis), showing the Toxicity Score, Occurrence Score, and 

Physicochemical Properties Score for each chemical.

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the 

calculation.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.6.5.3 Results: Cancer MCDA for Chemicals Used in Hydraulic Fracturing Fluids

A total of 10 chemicals used in hydraulic fracturing fluids were evaluated in a cancer MCDA (Table 

9-13). OSFs for these chemicals ranged from 0.002 to 3 per mg/kg-day, with quinoline having the

highest OSF, and dichloromethane having the lowest. Benzene is the only one of these chemicals

that is classified as a known human carcinogen by at least one of the sources in Table 9-1, while the

other chemicals in this subset are classified as probable carcinogens in humans (Appendix Table G1e).

Figure 9-12 presents the results from the cancer MCDA for chemicals used in hydraulic fracturing 

fluids. Of the 10 chemicals that were considered in this analysis, acrylamide received the highest 

Total Hazard Potential Score. Acrylamide has an OSF of 0.5 per mg/kg-day, which is one of the 

higher OSFs in this suite of chemicals, and has physicochemical properties that are highly conducive 

to transport in water. Acrylamide was reported in 1% of disclosures nationally in the EPA 

FracFocus 1.0 project database. This nevertheless places acrylamide in the top quartile in terms of 

frequency of use, as none of the chemicals within this subset were used with great frequency on a 

national basis. 

Bis(2-chloroethyl)ether and quinoline, which are the two most potent carcinogens considered in 

the analysis and received high Toxicity Score, received the second and third highest Total Hazard 

Potential Scores within this suite of chemicals. Bis(2-chloroethyl)ether was reported in 0.7% of 

disclosures, while quinoline was reported in 0.02% of disclosures. Both are expected to be readily 

transported in water.

In addition to acrylamide, the other two chemicals receiving high Occurrence Scores were benzyl 

chloride and epichlorohydrin (6% and 1% of disclosures, respectively). These two chemicals both 

received moderate Total Hazard Potential Scores. Benzyl chloride has an OSF of 0.17 per mg/kgday, while epichlorohydrine has an OSF of 0.0099 per mg/kg-day. Both received lower 

Physicochemical Properties Scores relative to other chemicals in this analysis, due in part to 

volatility.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Table 9-13. Data on the selected subset of chemicals in hydraulic fracturing fluids used for input into a cancer MCDA. 

Chemicals within the table are ordered from most potent to least potent based on OSF. 

Cancer-specific 

toxicity (OSF)a

% disclosures in 

EPA FracFocus 

1.0 project 

databaseb Mobility Volatility Persistence

Chemical Name CASRN

OSF (per 

mg/kgday) Source National Log KOW Log KOCSolubility 

(mg/L)

Henry's 

Law 

Constant

Half-life in 

water (days)

Quinoline 91-22-5 3 IRIS 0.02% 2.03 3.1 1711 1.67E-06 15

Bis(2-chloroethyl) 

ether 111-44-4 1.1 IRIS 0.7% 1.29 1.88 6435 1.70E-05 37.5

Acrylamide 79-06-1 0.5 IRIS 1% -0.67 0.755 504000 1.70E-09 15

Benzyl chloride 100-44-7 0.17 IRIS 6% 2.3 2.649 1030 4.12E-04 15

1,4-Dioxane 123-91-1 0.1 IRIS 0.3% -0.27 0.421 213900 4.80E-06 15

Benzene 71-43-2 0.015-

0.055c IRIS 0.006% 2.13 1.75 2000 5.55E-03 37.5

1,3-Dichloropropene 542-75-6 0.05 IRIS 0.02% 2.04 1.82 1994 3.55E-03 37.5

Epichlorohydrin 106-89-8 0.0099 IRIS 1% 0.45 1 50630 3.04E-05 15

Aniline 62-53-3 0.0057 IRIS 0.02% 0.9 1.6 20820 2.02E-06 15

Dichloromethane 75-09-2 0.002 IRIS 0.02% 1.25 1.44 10950 3.25E-03 37.5

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; KOW = octanol-water partitioning coefficient; KOC = soil adsorption coefficient

a 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. OSFs considered in the MCDA include values from IRIS, PPRTV, and HHBP.

b The FracFocus frequency of use data presented in this chapter is based on 35,957 FracFocus disclosures that were deduplicated, within the study time period (January 1, 2011 

to February 28, 2013), and with ingredients that have a valid CASRN.

c IRIS lists the OSF for benzene as a range from 0.015 to 0.055 per mg/kg-day. For input into the MCDA, we used the high end of this range (0.055 per mg/kg-day).
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-12. Cancer MCDA results for 10 chemicals used in hydraulic fracturing fluids, showing 

the Toxicity Score, Occurrence Score, and Physicochemical Properties Score for each 

chemical. 

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the 

calculation. 

9.6.5.4 Results: Noncancer MCDA for Chemicals in Produced Water 

A total of 29 chemicals detected in produced water were evaluated in a noncancer MCDA (Table 

9-14). Of these 29 chemicals, 13 were also included in the noncancer MCDA for hydraulic fracturing

fluids. Chronic oral RfVs within this suite of chemicals range from 0.001 to 0.9 mg/kg-day, with

pyridine having the lowest chronic oral RfV, and acetone having the highest. Chronic oral exposure

to these chemicals may induce a variety of adverse outcomes, including immune system effects,

changes in body weight, changes in blood chemistry, pulmonary toxicity, neurotoxicity, liver and

kidney toxicity, and reproductive and developmental toxicity. The total UFs used in the derivation

of these chronic oral RfVs (Table 9-14) reflect varying degrees of confidence surrounding the data

sets for these chemicals.

Figure 9-13 presents the results of a noncancer MCDA for these 29 chemicals detected in produced 

water. Benzene, pyridine, and naphthalene received the highest Total Hazard Potential Scores, 

followed by 2-methylnaphthalene. These four chemicals all received high Toxicity Scores and high 

Occurrence Scores (with maximum average concentrations of 1500 μg/L, 413 μg/L, 238 μg/L, and 

1362 μg/L in Barnett, Marcellus, or Powder River Basin produced water, respectively), but received 

moderate to low Physicochemical Property Scores. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-72 

Table 9-14. Data on the selected subset of chemicals detected in produced water used for input into a noncancer MCDA. 

Chemicals within the table are ordered from most toxic to least toxic based on chronic oral RfV.

Noncancer toxicity 

(chronic oral RfV)a

Occurrence 

(concentration in 

produced water)

b Mobility Volatility

Persistence

Chemical Name CASRN

RfV

(mg/kgday) Total UF Source

Average or 

Median 

Conc. (μg/L) Reference Log KOW Log KOC

Solubility 

(mg/L)

Henry's 

Law 

Constant

Half-life 

in water 

(days)

Pyridine 110-86-1 0.001 1000 IRIS 413 Table E-11 0.65 1.6 729800 1.10E-05 15

Benzene 71-43-2 0.004 300 IRIS 1500 Table E-13 2.13 1.75 2000 5.55E-03 37.5

2-Methylnaphthalene 91-57-6 0.004 1000 IRIS 1362 Table E-11 3.86 3.6 41.42 5.18E-04 15

1,2,4-

Trimethylbenzene 95-63-6 0.01 300 IRIS 173 Table E-11 3.63 2.788 79.59 6.16E-03 37.5

1,3,5-

Trimethylbenzene 108-67-8 0.01 300 IRIS 59 Table E-11 3.42 2.82 120.3 8.77E-03 37.5

Chloroform 67-66-3 0.01 1000 IRIS 28 Table E-11 1.97 1.6 2096 3.67E-03 37.5

Tributyl phosphate 126-73-8 0.01 1000 PPRTV 0.26 Table E-12 4 3.371 7.355 1.41E-06 8.67

Naphthalene 91-20-3 0.02 3000 IRIS 238 Table E-11 3.3 2.96 142.1 4.40E-04 37.5

Di(2-ethylhexyl) 

phthalatec 117-81-7 0.02 1000 IRIS 210 Table E-11 7.6 4.94 0.001132 2.70E-07 15

Chlorobenzened 108-90-7 0.02 1000 IRIS 100 Table E-13 2.84 2.15 400.5 3.11E-03 15

2,4-Dimethylphenol 105-67-9 0.02 3000 IRIS 14.5 Table E-11 2.3 2.692 4068 9.51E-07 15

Pyrene 129-00-0 0.03 3000 IRIS 13 Table E-11 4.88 4.9 0.2249 1.19E-05 60

1,4-Dioxane 123-91-1 0.03 300 IRIS 6.5 Table E-11 -0.27 0.421 213900 4.80E-06 15

Fluorene 86-73-7 0.04 3000 IRIS 8.4 Table E-11 4.1 3.614 20.13 1.59E-03 15

Fluoranthene 206-44-0 0.04 3000 IRIS 6.1 Table E-11 5.16 4.8 0.1297 8.86E-06 60

o-Cresole 95-48-7 0.05 1000 IRIS 28.3 Table E-11 1.95 2.486 9066 1.20E-06 15

Toluene 108-88-3 0.08 3000 IRIS 760 Table E-9 2.73 2.07 573.1 6.64E-03 15
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-73 

Noncancer toxicity 

(chronic oral RfV)a

Occurrence 

(concentration in 

produced water)

b Mobility Volatility

Persistence

Chemical Name CASRN

RfV

(mg/kgday) Total UF Source

Average or 

Median 

Conc. (μg/L) Reference Log KOW Log KOC

Solubility 

(mg/L)

Henry's 

Law 

Constant

Half-life 

in water 

(days)

Ethylbenzene 100-41-4 0.1 1000 IRIS 2010 Table E-13 3.15 2.23 228.6 7.88E-03 15

Carbon disulfide 75-15-0 0.1 100 IRIS 400 Table E-11 1.94 1.337 2928 1.44E-02 15

Cumenef 98-82-8 0.1 1000 IRIS 120 Table E-11 3.66 2.844 75.03 1.15E-02 15

Benzyl alcohol 100-51-6 0.1 1000 PPRTV 81.5 Table E-11 1.1 1.1 41050 3.37E-07 15

Dibutyl phthalateg 84-74-2 0.1 1000 IRIS 41 Table E-11 4.5 3.14 2.351 1.81E-06 8.67

Acetophenone 98-86-2 0.1 3000 IRIS 13 Table E-11 1.58 1.8 4484 1.04E-05 15

Diphenylamine 122-39-4 0.1 100 HHBP 5.3 Table E-11 3.5 2.78 63.61 2.69E-06 37.5

Xylenes 1330-20-7 0.2 1000 IRIS 360 Table E-9 3.2 2.25 207.2 7.18E-03 15

Benzyl butyl phthalate 85-68-7 0.2 1000 IRIS 34.3 Table E-11 4.73 3.72 0.9489 1.26E-06 0.04

Phenol 108-95-2 0.3 300 IRIS 63 Table E-11 1.46 1.9 26160 3.33E-07 15

Caprolactam 105-60-2 0.5 100 IRIS 0.75 Table E-12 0.66 1.3892 28720 2.53E-08 14508

Acetone 67-64-1 0.9 1000 IRIS 145 Table E-10 -0.24 0.374 219900 3.50E-05 15

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer Reviewed Toxicity Values; HHBP = Human Health 

Benchmarks for Pesticides; KOW = octanol-water partitioning coefficient; KOC = soil adsorption coefficient

a Reference value (RfV): 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. RfVs considered in the MCDA include chronic oral reference doses (RfD) from IRIS, PPRTV, and HHBP; and chronic oral minimal risk 

levels (MRLs) from ATSDR.

b From Appendix E. 

c Di(2-ethylhexyl) phthalate is listed under the name bis(2-ethylhexyl) phthalate in Appendix Table E-11. 

d Chlorobenzene is listed under the name chloro-benzene in Appendix Table E-13.

e o-Cresol is listed under the name 2-methylphenol in Appendix Table E-11.

f Cumene is listed under the name isopropylbenzene in Appendix Table E-11. 

g Dibutyl phthalate is listed under the name dibutyl-n-phthalate in Appendix Table E-11.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-74 

Figure 9-13. Noncancer MCDA results for a subset of 29 chemicals detected in produced 

water, showing the Toxicity Score, Occurrence Score, and Physicochemical Properties Score 

for each chemical. 

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the 

calculation.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-75 

The other chemicals that received high Toxicity Scores were 1,2,4-trimethylbenzene, 1,3,5-

trimethylbenzene, chloroform, 2,4,-dimethylphenol, tributyl phosphate, di(2-ethylhexyl) phthalate, 

and chlorobenzene. These chemicals received moderate Total Hazard Potential Scores, as all were 

detected at lower concentrations compared to other chemicals considered in this analysis and are 

expected to have moderate transport in water. 

The other chemicals that received high Occurrence Scores are ethylbenzene, toluene, xylenes, and 

carbon disulfide, which were detected at maximum average concentrations of 2010 μg/L, 760 μg/L, 

360 μg/L, and 400 μg/L in Barnett, Marcellus, or Powder River Basin produced water. These 

chemicals received moderate Total Hazard Potential Scores, as all have as all have higher chronic 

oral RfVs relative to many of the other chemicals in the hazard evaluation, and are all expected to 

have moderate transport in water relative to the other chemicals. 

9.6.5.5 Results: Cancer MCDA for Chemicals in Produced Water 

A total of 7 chemicals reported in produced water were evaluated in a cancer MCDA (Table 9-15). 

OSFs within this suite of chemicals ranged from 7.3 to 0.0049 per mg/kg-day, with benzo(a)pyrene 

having the highest OSF and N-nitrosodiphenylamine having the lowest. Of these 7 chemicals, 

benzene and 1,4-dioxane were also included in the cancer MCDA for chemicals used in hydraulic 

fracturing fluids. Benzene and benzo(a)pyrene are both classified by at least one of the sources in 

Table 9-1 as a known human carcinogen, while the other chemicals as classified as likely or 

probable carcinogens in humans (Appendix G: Tables G-1e and G-2e). 

Figure 9-14 presents the results of a cancer MCDA for these 7 chemicals in hydraulic fracturing 

fluids. Benzene and benzo(a)pyrene tied for highest Total Hazard Potential Scores. Of these, 

benzene was detected at the highest average concentrations in produced water (1500 μg/L in 

Power River Basin produced water), while benzo(a)pyrene were detected at lower average 

concentrations (6.7 μg/L in Barnett shale produced water). Benzo(a)pyrine and 1,2-

diphenylhydrazine were the most potent carcinogens within this suite of chemicals and received 

high Toxicity Scores. 

The other chemical that received a high Occurrence Score was di(2-ethylhexyl) phthalate, which 

was detected at an average concentration of 210 μg/L in Barnett Shale produced water. It received 

a moderate Total Hazard Potential Score because it is hydrophobic and not expected to be readily 

transported in water.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Table 9-15. Data on the selected subset of chemicals detected in produced water used for input into a cancer MCDA. 

Chemicals within the table are ordered from most potent to least potent based on OSF.

Cancer-specific 

toxicity (OSF)a

Occurrence

(concentration in 

produced water)

b Mobility Volatility

Persistence

Chemical Name CASRN

OSF (per 

mg/kgday)Source 

of OSF

Average or 

Median 

Conc. (μg/L) Reference Log KOW Log KOC

Solubility 

(mg/L)

Henry's Law 

Constant

Half-life 

in water 

(days)

Benzo(a)pyrene 50-32-8 7.3 IRIS 6.7 Table E-11 6.13 5.95 0.01038 4.57E-07 60

1,2-Diphenylhydrazine 122-66-7 0.8 IRIS 4.2 Table E-11 2.94 2.98 161.9 4.78E-07 28.17

1,4-Dioxane 123-91-1 0.1 IRIS 6.5 Table E-11 -0.27 0.421 213900 4.80E-06 15

Benzene 71-43-2 0.015-

0.055c IRIS 1500 Table E-13 2.13 1.75 2000 5.55E-03 37.5

Di(2-ethylhexyl) phthalated 117-81-7 0.014 IRIS 210 Table E-11 7.6 4.94 0.001132 2.70E-07 15

Tributyl phosphate 126-73-8 0.009 PPRTV 0.26 Table E-12 4 3.371 7.355 1.41E-06 8.67

N-Nitrosodiphenylamine 86-30-6 0.0049 IRIS 8.9 Table E-11 3.13 3.42 94.85 1.21E-06 37.5

CASRN = Chemical Abstract Service Registry Number; IRIS = Integrated Risk Information System; PPRTV = Provisional Peer-Reviewed Toxicity Values; KOW = octanol-water 

partitioning coefficient; KOC = soil adsorption coefficient

a 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. OSFs considered in the MCDA include values from IRIS, PPRTV, and HHBP.

b From Appendix E.

c IRIS lists the OSF for benzene as a range from 0.015 to 0.055 per mg/kg-day. For input into the MCDA, we used the high end of this range (0.055 per mg/kg-day).

d Di(2-ethylhexyl) phthalate is listed under the name bis(2-ethylhexyl) phthalate in Appendix Table E-11.
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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Figure 9-14. Cancer MCDA results for 7 chemicals detected in produced water, showing the 

Toxicity Score, Occurrence Score, and Physicochemical Properties Score for each chemical. 

Chemicals are ordered from high to low based on Total Hazard Potential Score. See Section 9.6.4 for details on the

calculation. 

9.6.6 Limitations and Uncertainty of the MCDA Framework

While this MCDA framework provides a simple and transparent tool for exploring the relative 

hazard potential of chemicals in the hydraulic fracturing water cycle, it is intended only as a 

preliminary analysis. It is important to acknowledge the limitations of this analysis, as well as the 

limitations of the parameters that were used for input in the MCDA. 

Chronic oral RfVs and OSFs were selected for the MCDA because they are a primary focus of the 

toxicological evaluation presented in this chapter. We were interested in placing these values in the 

context of variables that may impact the likelihood of human exposure. These toxicity values were 

available for a relatively small fraction of chemicals on EPA’s list, which limited the number of 

chemicals considered in the MCDA. 

The FracFocus 1.0 data used in the MCDA does not represent a complete record of hydraulic 

fracturing chemical usage in the United States, as described in more detail in Chapter 5 and in 

Section 9.3.1. Frequency of use also does not reflect the volume or concentration of chemical usage, 

and therefore is an incomplete metric for potential exposure. The EPA FracFocus 1.0 project 

database provides data on the maximum concentration of chemicals in additives and in hydraulic 

fracturing fluid, as discussed in Section 5.4, but we elected not to use this data in the MCDA because 

reported concentrations for each chemical varied widely between disclosures (see Table 5-5 and 

volume estimates in Figure 5-5), making it difficult to determine a chemical concentration to use in 

an MCDA. Additionally, many chemicals in the EPA FracFocus 1.0 project database did not have 

valid concentration data; for instance, the maximum concentrations of a chemical in additive often 

added up to greater than 100%. We therefore elected to focus on frequency of use as a general 

metric of chemical occurrence in the hydraulic fracturing water cycle. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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The produced water concentrations used in the MCDA are based on the compilation of data 

presented in Appendix E. While this data reflects the findings of recent studies, it does not 

represent a complete record of chemicals present in produced water, as described in more detail in 

Chapter 7 and in Section 9.3.2. Concentrations in produced water also do not necessarily reflect the 

concentrations in treated wastewater, drinking water wells, or residuals in soil or sediment. 

Concentrations of these chemicals in treated wastewater or well water would likely be more dilute 

compared to concentrations in produced water. Concentrations in soils or sediments may be higher, 

particularly for hydrophobic chemicals.

The physicochemical properties from EPI Suite used in the MCDA are useful for making comparison 

across chemicals, but these values are also subject to uncertainty. Many of the values used in the 

MCDA were estimated by EPI Suite, and therefore are subject to the inherent limitations of the EPI 

Suite model (Section 5.8). Chemical fate and transport will be also influenced by environmental and 

site-specific conditions, which are outside the scope of this analysis. For instance, the half-lives used 

to develop the Physicochemical Properties Score are estimated values that assume aerobic 

conditions, and thus may underestimate the expected half-life under anaerobic conditions (e.g., in a 

groundwater contaminant plume). If chemicals are present in a mixture, as inevitably occurs in 

hydraulic fracturing fluids and in the subsurface environment, fate and transport will be influenced 

by changes in solubility or degradation resulting from interactions with other chemicals. 

There are also fundamental limitations with regards to the scope of the MCDA. The chemicals used 

in these analyses may not be representative of chemicals at a specific field site. The analysis only 

examined organic chemicals, as EPI Suite is not able to estimate physicochemical properties of 

inorganic chemicals. Additionally, the physicochemical properties used in the MCDA were chosen 

specifically to reflect chemical transport in water, and therefore do not highlight the potential 

hazards of hydrophobic or volatile chemicals. Hydrophobic chemicals may serve as long-term 

sources of pollution by sorbing to soils or sediments at contaminated sites, and volatile chemicals 

may be hazardous when inhaled. This analysis also does not attempt to address bioavailability or 

toxicokinetics, which may be influenced by physicochemical properties such as log Kow. For 

instance, chemicals with log Kow of 2-4 tend to absorb well through biological membranes, while 

chemicals with log Kow > 4 tend not to absorb well, and those with log Kow of 5-7 tend to 

bioconcentrate (U.S. EPA, 2012i). 

9.6.7 Application of the MCDA Framework for Preliminary Hazard Evaluation

The MCDA framework presented here is intended as a preliminary analysis, and illustrates one 

possible method for integrating data to explore potential hazards. By combining multiple lines of 

data, we can stratify chemicals according to estimated hazard potential, and gain preliminary 

insight into those chemicals that may be of more concern than others to drinking water resources.

Researchers may find this approach useful in their efforts to explore the potential hazards of 

chemicals present at specific field sites, particularly in instances when exposure assessment data is 

not available. The MCDA framework is flexible, and could be adapted to incorporate site-specific 

data on chemical usage, different types of toxicity data, as well as other variables that may be of 

interest for risk assessment. For instance, rather than focusing on RfVs and OSFs from US federal 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-79 

sources, one could choose to derive the Toxicity Score using other sources of relevant toxicity 

information. Additionally, one could choose to perform this analysis using different 

physicochemical property inputs, to highlight chemical interactions with different environmental 

media (e.g., hydrophobic or volatile chemicals). Researchers could also choose to apply different 

weights to each of the three criteria considered in this analysis (toxicity, occurrence, 

physicochemical properties), to reflect expert judgement of each variable’s relative importance. 

9.7 Synthesis 

The overall objective of this chapter was to identify and provide information on the toxicological 

properties of chemicals used in hydraulic fracturing and of hydraulic fracturing wastewater 

constituents, and to evaluate the potential hazards of these chemicals for drinking water resources. 

Toward this end, the EPA developed a list of 1,606 chemicals that are reported to be associated 

with hydraulic fracturing, separating them into subsets based on whether they were reported to 

have been used in hydraulic fracturing fluids (1,084 chemicals total) or detected in produced water 

(599 chemicals total). To evaluate the potential hazards of these chemicals, the EPA compiled 

chronic oral RfVs, OSFs, and qualitative cancer classifications from selected federal, state, and 

international sources that met the EPA’s criteria for consideration in this assessment. This 

toxicological information was used to conduct an initial identification of the potential human health 

hazards associated with several subsets of chemicals identified as being of particular interest in 

previous chapters of this report. Finally, in order to illustrate how data integration could be used to 

explore potential hazards, an MCDA framework was used to evaluate selected subsets of chemicals 

based on toxicity, environmental occurrence, and physicochemical properties affecting chemical 

transport in water. 

9.7.1 Summary of Findings

A major finding of this chapter was that chronic oral RfVs and OSFs were not available for the 

majority of chemicals that the EPA has identified as being associated with hydraulic fracturing 

activity, indicating that the majority of these chemicals have not undergone significant toxicological 

evaluation. Similarly, there have been several recent peer-reviewed studies that have attempted to 

gather toxicological information for subsets of chemicals that are used in hydraulic fracturing fluids, 

and they have found that many of these chemicals do not have toxicity values available (Elliott et al., 

2016; Wattenberg et al., 2015; Stringfellow et al., 2014; Colborn et al., 2011). Taken together, this 

suggests a potentially significant knowledge gap exists with respect to the scientific community’s 

understanding of the potential human health impacts of these chemicals. With the limited 

availability of toxicity values, risk assessment is difficult, and potential impacts on drinking water 

resources may not be assessed adequately. This lack of toxicity values is not unique to the hydraulic 

fracturing industry; in fact, it has been estimated that there are tens of thousands of chemicals in 

commercial use that have not undergone significant toxicological evaluation (Judson et al., 2009). 

There are a variety of chemicals associated with hydraulic fracturing known to be hazardous to 

human health. Chronic oral RfVs or OSFs from the sources considered by the EPA in this assessment 

were available for 98 (9%) of the 1,084 chemicals used in hydraulic fracturing fluids, and 120

(20%) of the 599 chemicals detected in hydraulic fracturing produced water. Potential hazards 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-80 

associated with chronic oral exposure to these chemicals include carcinogenesis, immune system 

effects, changes in body weight, changes in blood chemistry, cardiotoxicity, neurotoxicity, liver and 

kidney toxicity, and reproductive and developmental toxicity. Methane is not considered to be toxic 

when ingested, but may accumulate to explosive levels or act as an asphyxiant. DBPs formed during 

wastewater treatment can contribute to an increased risk of cancer, anemia, liver and kidney 

effects, and central nervous system effects, with brominated forms of DBPs considered to be more 

cytotoxic, genotoxic, and carcinogenic than chlorinated species. 

To assess the toxicity of chemicals that lack chronic oral RfVs and OSF, risk assessors will need to 

turn towards alternative data sources. This chapter explored two alternative data sources that may 

provide useful information. QSAR-based toxicity estimates—specifically, rat chronic oral LOAEL 

estimates generated using TOPKAT—were available for many of the chemicals that lacked chronic 

oral RfVs and OSFs from the sources considered in this assessment, and may be used to rank 

chemicals based on toxicity when other data are not available. Additionally, many of these 

chemicals have information available on the EPA’s ACToR database, which is an online data 

warehouse designed to consolidate large and disparate amounts of chemical data. The information 

available in the ACToR data warehouse ranges from the selected RfVs and OSFs discussed in this 

assessment, which have undergone extensive peer review, to toxicological data that have 

undergone little-to-no peer review.

When considering the potential impact of chemicals on drinking water resources and human health, 

it is important to consider exposure as well as toxicological properties. As discussed in previous 

chapters of this report and highlighted in this chapter, events such as spills, leaks from storage pits, 

and discharge of inadequately treated wastewater have led to the entry of hydraulic fracturingrelated chemicals into drinking water resources. In some instances, chemical concentrations in 

surface water or groundwater were in exceedance of MCLs, indicating their presence at levels that 

could impact human health. While these studies demonstrate the potential entry of these chemicals 

into drinking water resources, there is a lack of systematic studies examining actual human 

exposures to these chemicals in drinking water as a result of hydraulic fracturing activity. 

In the absence of exposure assessment data, the MCDA framework presented in this chapter 

provides a preliminary analysis of the relative hazard potential of these chemicals. In this context, 

occurrence and physicochemical property data were used as metrics to estimate the likelihood that 

a chemical could reach and impact drinking water, and toxicity data was used as a metric for the 

potential severity of an impact. This analysis highlighted several chemicals that may be more likely 

than others to reach drinking water and create a toxicological hazard. Of the chemicals used in 

hydraulic fracturing fluids that were considered in this analysis, chemicals such as propargyl 

alcohol stood out as having high potential toxicity, high frequency of use, and physicochemical

properties that are conducive to transport in water. Of the chemicals in produced water, chemicals 

such as benzene, pyridine, 2-methylnaphthalene, and naphthalene stood out as having high 

potential toxicity, high concentrations in produced water, and physicochemical properties that are 

conducive to transport in water. 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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9.7.2 Factors Affecting the Frequency or Severity of Impacts

There are multiple pieces of information that could be taken into account when evaluating the 

frequency and severity of impacts that these chemicals may have on drinking water resources. This 

includes knowledge of the chemicals used at a given site, the toxicological and physicochemical 

properties of these chemicals, the amount of fluid being used and recovered, the likelihood of 

mechanical integrity failures, the likelihood of spills and other unintentional releases, and the 

efficiency of chemical removal during wastewater treatment. The MCDA presented in this chapter 

incorporated parameters that may impact the likelihood of chemical exposure, including frequency 

of use, measured concentration, and transport in water, and was used to stratify and rank chemicals 

based on relative hazard potential. However, it should be considered only as a preliminary analysis, 

and should not be used in place of local data on the concentrations and volumes of chemicals in 

areas of hydraulic fracturing activity. 

Analysis of the chemicals used in hydraulic fracturing fluids indicated that the majority of chemicals 

on the EPA’s list are used in <1% of wells nationally (Figure 9-4). Therefore, potential exposure to 

the majority of these chemicals is more likely to be a local issue, rather than a national one. Given 

that the analysis of the EPA FracFocus 1.0 project database presented in this chapter was based on 

35,957 disclosures, a chemical used in <1% of wells nationally could still be used in several 

hundred wells. Chemicals used infrequently on a national basis could still be used more frequently 

within certain areas or counties, increasing the potential for local exposure to that chemical. 

As an example of how an infrequently used chemical could have local impacts, consider (E)-

crotonaldehyde, which had one of the lowest chronic oral RfVs among the chemicals considered in 

the noncancer MCDA for hydraulic fracturing chemicals, and was reported in approximately 0.06% 

of disclosures in the EPA FracFocus 1.0 project database. If the EPA FracFocus 1.0 project database 

is a representative sample of all of the wells across the country, then the likelihood of (E)-

crotonaldehyde contamination on a national scale is limited. However, this in no way diminishes 

the likelihood or potential severity of (E)-crotonaldehyde contamination at sites where this 

chemical is used. 

This is in contrast with frequently used chemicals such as methanol. Methanol was reported in 73% 

of wells in the EPA FracFocus 1.0 project database, and was the most frequently used chemical 

considered in the noncancer MCDA for chemicals used in hydraulic fracturing fluids. Methanol is 

soluble and relatively mobile in water, but has a higher chronic oral RfV compared other chemicals 

considered in this analysis. Therefore, methanol may be expected to have a higher exposure 

potential on a national basis compared to other chemicals, with a moderate hazard potential due to 

its relatively high RfV.

Even if no chemicals were added to hydraulic fracturing fluids, there is still a potential for impacts 

from constituents naturally present in the subsurface which could be brought to the surface in

produced water. As described in Section 9.5, many of the naturally occurring chemicals in produced 

water—e.g., organic chemicals (e.g., BTEX and related hydrocarbons), metals, anions, and 

TENORM—are hazardous to human health and have been reported in drinking water resources as a 

result of hydraulic fracturing activity, sometimes at concentrations exceeding MCLs. The 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

9-82 

constituents of produced water that contribute to the formation of DBPs, specifically bromide, 

chloride, iodine, and ammonium, are naturally occurring and are characteristic of wastewater from 

hydraulically fractured wells.

Overall, contamination of drinking water resources depends on site-, chemical-, and fluid-specific 

factors (Goldstein et al., 2014), and the exact mixture and concentrations of chemicals at a site will 

depend upon the geology and the chemicals used in the oil and gas extraction processes. Therefore, 

potential hazard and risk considerations are best made on a site-specific, well-specific basis.

9.7.3 Uncertainties

There are notable uncertainties in the chemical and toxicological data limiting a comprehensive 

assessment of the potential health impacts of hydraulic fracturing on drinking water resources. 

For human health risk assessment, a significant data gap is the lack of chronic oral RfVs and OSFs 

from sources meeting the EPA’s criteria for inclusion in this report. For instance, of the 34 

chemicals (excluding water, quartz, and sodium chloride) that were reported in ≥10% of 

disclosures in the EPA FracFocus 1.0 project database, 9 chemicals have chronic oral RfVs available, 

and none have OSFs (Table 9-2). Without reliable and peer reviewed toxicity values, comprehensive 

hazard evaluation and hazard identification of chemicals is difficult, and the ability to consider the 

potential cumulative effects of exposure to chemical mixtures in hydraulic fracturing fluid or 

produced water may be limited. Although there are other potential sources of toxicity information 

for many of these chemicals, some of it may be limited or of lesser quality. Consequently, potential 

impacts on drinking water resources and human health may not be assessed adequately. 

An equally significant data gap is the lack of exposure assessment data for drinking water resources 

in areas of hydraulic fracturing activity. As discussed in Text Box 9-1, data on exposure potential is 

a critical component of the risk assessment process, and is necessary for risk characterization. In 

the absence of exposure assessment information, the MCDA framework presented in this chapter 

may be useful for exploring the potential hazards of hydraulic fracturing-related chemicals, but 

should be considered as a preliminary analysis only. The MCDA presented in this chapter 

considered only a small subset of chemicals that had data available, was limited in scope, and may 

not be representative of the chemicals that are present at a specific field site. It should be 

emphasized that this MCDA framework represents just one method that can be used to integrate 

chemical data for hazard evaluation, and is readily adaptable to include different variables, different 

weights for the variables, and site-specific considerations. 

There is also uncertainty surrounding the EPA’s list of chemicals associated with hydraulic 

fracturing activity. As discussed in Section 5.4 and Section 9.3.1, there is incomplete information 

available on chemicals used in hydraulic fracturing fluids due to industry use of CBI as well as 

incomplete reporting of chemical use. For instance, the EPA’s analysis of the FracFocus 1.0 project 

database found that approximately 11% of ingredients were reported as CBI, and that more than 

70% of FracFocus 1.0 disclosures contained at least one CBI ingredient. There may also be regional 

limitations in the disclosures submitted to FracFocus 1.0, as 78% of chemical disclosures in came 

from five states, and 47% were from Texas (U.S. EPA, 2015a). Despite these limitations, FracFocus 
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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remains the most complete source for tracking hydraulic fracturing chemical usage in the United 

States, and therefore was the best available source for the hazard evaluation in this chapter. 

Although the sources used to compile the chemical list represented the best available data at the 

time of this study, it is possible that some of these chemicals are no longer used at all, and many of

these chemicals may only be used infrequently. Therefore, it may be possible that significantly 

fewer than 1,084 chemicals are currently used in abundance. As practices evolve, it is likely that 

chemicals are used or will be used that are not included on this chemical list. Having a better 

understanding of the chemicals and formulations, including those that are CBI, along with their 

frequency of use and volumes, would greatly benefit risk assessment and risk management 

decisions.

Additionally, the list of produced water chemicals identified in this chapter is almost certainly 

incomplete. As discussed in Chapter 7, chemicals and their metabolites may go undetected because 

they were not included in the analytical methodology, or because an analytical methodology was 

not available. Chemical analysis of produced water can also be challenging because high levels of 

dissolved solids in produced water and wastewater can interfere with chemical detection. As a 

result, there are likely chemicals of concern in produced water that have not been detected or 

reported, and are not included on the chemical list presented in this report.

9.7.4 Conclusions

The EPA identified 1,606 chemicals associated with the hydraulic fracturing water cycle, including 

1,084 chemicals used in hydraulic fracturing fluids, and 599 chemicals detected in produced water. 

Toxicity-based chronic oral RfVs and/or OSFs from sources meeting selection criteria were not 

available for the majority (89%) of the chemicals on this total list. Thirty-seven percent of 

chemicals on the EPA’s list that are used in hydraulic fracturing fluids lack data on their frequency 

of use. Current understanding of the chemical composition of produced water is constrained by 

analytical chemistry limitations and by the likelihood that chemical composition will vary between 

wells. A limited number of studies have detected these chemicals in surface water, groundwater, or 

well water near areas of hydraulic fracturing activity, suggesting the potential for human exposure; 

however, actual human exposures to these chemicals in drinking water resources has not been well 

characterized. Given the large number of chemicals used or detected in various stages of the 

hydraulic fracturing water cycle, as well as the large number of hydraulically fractured wells 

nationwide, this missing chemical information represents a significant data gap. 

While it remains challenging to fully understand the toxicity and potential public health impacts of 

these chemicals for drinking water resources, the toxicological data, occurrence data, and 

physicochemical data compiled in this report provide a resource for assessing the potential hazards 

of chemicals in the hydraulic fracturing water cycle. The MCDA framework presented here 

illustrates one method for integrating these data for a preliminary hazard evaluation, which may be 

useful when exposure assessment data are not available. While the analysis in this chapter is 

constrained to the assessment of chemicals on a national scale, this approach is readily adaptable 

for use on a regional or site-specific basis. 
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This collection of data provides a tool to inform decisions about protection of drinking water 

resources. Stakeholders may use these results to prioritize chemicals for hazard assessment or for 

determining future research priorities. Industry may use this information to prioritize chemicals for 

replacement with less toxic, persistent, and mobile alternatives. 

9.8 Annex

9.8.1 Calculation of Physicochemical Property Scores (MCDA Hazard Evaluation)

Section 9.6.3 describes how Physicochemical Properties Scores for the noncancer and cancer 

MCDAs were calculated based on three subcriteria which affect the likelihood that a chemical will 

be transported in water: mobility, volatility, and persistence. Calculation of these subcriteria scores 

was performed as described by Yost et al. (In Press), as follows:

9.8.1.1 Mobility Score

Chemical mobility in water was assessed based upon three physicochemical properties that 

describe chemical solvency in water: the octanol-water partition coefficient (KOW), the soil 

adsorption coefficient (KOC), and aqueous solubility. KOW describes the partitioning of a chemical 

between water and a carbon-based media (octanol), while KOC described the partitioning of a 

chemical between water and organic carbon in soil. KOW and KOC are generally represented on a 

logarithmic scale. Aqueous solubility is the maximum amount of a chemical that will dissolve in 

water in the presence of pure chemical. Chemicals with low KOW, low KOC, or high aqueous solubility 

are more likely to solubilize and move with water, and therefore were ranked as having greater 

potential to affect drinking water resources. 

For input into the MCDA, we used experimentally measured values (provided in EPI Suite) 

whenever available. Otherwise, we used the following estimated values from EPI Suite: log KOW

estimated using the KOWWINTM model, log KOC estimated using the KOCWINTM Sabljic molecular 

connectivity method, and aqueous solubility estimated using the WSKOWWINTM model. Using the 

thresholds designated in Table 9-11, each of these properties was assigned a score of 1-4. The 

highest of these three scores (KOW, KOC, or solubility) was designated as the Mobility Score for each 

chemical.

9.8.1.2 Volatility Score

Chemical volatility was assessed based on the Henry’s law constant, which is the ratio of the 

concentration of a chemical in air to the concentration of that chemical in water. Chemicals with 

low Henry’s law constants are less likely to leave water via volatilization, and were therefore 

ranked as having greater potential to affect drinking water resources. 

For input into the MCDA, we used experimentally measured values (provided in EPI Suite) 

whenever available. Otherwise, we used Henry’s Law constants that were estimated using the EPI 

Suite HENRYWINTM model, which generates values using two different methods (group contribution 

and bond contribution); the lower of these two estimated values was used as input into the MCDA. 
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Using the thresholds designated in Table 9-11, the Henry’s law constant for each chemical was 

assigned a score of 1-4. This value was designated as the Volatility Score for each chemical.

9.8.1.3 Persistence Score

Chemical persistence was assessed based on estimated half-life in water, which describes how long 

a chemical will persist in water before it is transformed or degraded. Chemicals with longer halflives are more persistent, and were therefore ranked as having greater potential to impact drinking 

water resources. 

EPI Suite estimates biodegradation time using the BIOWINTM 3 model, which provides an indication 

of a chemical’s environmental biodegradation rate in relative terms (e.g., hours, days, weeks, etc.), 

assuming aerobic conditions. These BIOWIN3 estimates are converted to numerical half-life values 

for use in EPI Suite’s Level III Fugacity model. For input into the MCDA, we used the same estimated 

half-life in water that is used in the Level III Fugacity model. Using the thresholds designated in 

Table 9-11, the half-life in water of each chemical was assigned a score of 1-4. This value was 

designated as the Persistence Score for each chemical.

9.8.1.4 Total Physicochemical Properties Score

For each chemical, the Mobility Score, Volatility Score, and Persistence Score (each on a scale of 1 to 

4) were summed to calculate a total Physicochemical Properties Score. Higher Physicochemical

Properties Scores indicate chemicals that are more likely to be transported in water, with a

maximum possible score of 12.

9.8.2 Example of MCDA Score Calculation

The methods used for MCDA score calculation are described in Section 9.6.3. For an example of how 

the MCDA scores were calculated, consider benzene, which was included in both the noncancer

MCDA (national analysis) and cancer MCDA for chemicals used in hydraulic fracturing fluids. This 

demonstrates how MCDA scores were calculated for benzene for these two different analyses. 

9.8.2.1 Score Calculation for Benzene in Noncancer MCDA for Hydraulic Fracturing Fluids

• Toxicity Score (Noncancer): Benzene has a chronic oral RfV of 0.004 mg/kg-day (source:

IRIS). Across the 42 chemicals that were considered in the noncancer MCDA (national

analysis), chronic oral RfVs ranged from 0.001 mg/kg-day [(E)-crotonaldehyde] to 20

mg/kg-day (1,2-propylene glycol). The chronic oral RfV of benzene falls in the lowest

(most toxic) quartile of these chemicals, and therefore benzene was assigned a Toxicity

Score of 4. When the results were standardized to the highest Toxicity Score (4) and

lowest Toxicity Score (1) within the set of chemicals, benzene was calculated to have a

final Toxicity Score of 1, as follows:

1 = (4 – 1) / (4 – 1)

• Occurrence Score: Benzene was used in 0.006% of wells nationally. For the 42 chemicals

considered in the national noncancer MCDA, frequency of use ranged from 73%
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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(methanol) to 0.003% (furfural) of wells nationally. Benzene falls in the lowest quartile 

with regards to frequency of use, and therefore benzene was assigned an Occurrence Score 

of 1. When the results were standardized to the highest Occurrence Score (4) and lowest 

Occurrence Score (1) within the set of chemicals, benzene was calculated to have a final 

Occurrence Score of 0, as follows: 

0 = (1 – 1) / (4 – 1)

• Physiochemical Properties Score: Benzene received a Mobility Score of 4 (log KOW =

2.13; log KOC = 1.75; solubility = 2000 mg/l), a Volatility Score of 2 (Henry’s law constant =

0.00555), and a Persistence Score of 2 (half-life in water = 37.5 days). This sums to a Total

Physicochemical Properties Score of 8. Within the 42 chemicals considered in the national

noncancer MCDA, several chemicals received Total Physicochemical Properties Scores of

9, which was the highest observed score. Cumene received a Total Physicochemical

Properties Scores of 6, which was the lowest score. When the results were standardized to

the highest (9) and lowest (6) of these scores, benzene was calculated to have a final Total

Physicochemical Properties Scores of 0.67, as follows:

0.67 = (8 – 6) / (9 – 6)

• Total Hazard Potential Score (Noncancer MCDA): For benzene, the Toxicity Score (1),

Occurrence Score (0), and Physicochemical Properties Score (0.67) were summed to

calculate a Total Hazard Potential Score of 1.67. The relative contribution of the three

criteria scores to this total score is depicted as a graphic in Figure 9-8.

9.8.2.2 Score Calculation for Benzene in Cancer MCDA for Hydraulic Fracturing Fluids

• Toxicity Score (Cancer): Benzene has an OSF of 0.055 per mg/kg-day (source: IRIS).

Within the entire set of 10 chemicals that was considered in the cancer MCDA, OSFs

ranged from 3 (quinoline) to 0.002 (dichloromethane) per mg/kg-day. The OSF of benzene

falls in the second quartile of these scores, and therefore was assigned a Toxicity Score of

2. When the results were standardized to the highest Toxicity Score (4) and lowest

Toxicity Score (1) within the set of chemicals, benzene was calculated to have a final

Toxicity Score of 0.33, as follows:

0.33 = (2 – 1) / (4 – 1)

• Occurrence Score: As described in the noncancer MCDA above, benzene was used in

0.006% of wells nationally. This was the lowest frequency of use among the 10 chemicals

that were considered in the cancer MCDA, with benzyl chloride (used in 6% of wells)

having the highest. Benzene therefore falls in the lowest quartile with regards to

frequency of use, and was assigned an Occurrence Score of 1. When the results were

standardized to the highest Occurrence Score (4) and lowest Occurrence Score (1) within

the set of chemicals, benzene was calculated to have a final Occurrence Score of 0, as

follows:
Chapter 9 – Identification and Hazard Evaluation of Chemicals across the Hydraulic Fracturing Water Cycle 

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0 = (1 – 1) / (4 – 1)

• Physiochemical Properties Score: As described in the noncancer MCDA above, benzene

received a Total Physicochemical Properties Score of 8. Within the 10 chemicals that were

considered in the cancer MCDA, all chemicals either received a Total Physicochemical

Properties Score of 8 or 9. When the results were standardized to these high and low

scores, benzene was calculated to have a final Total Physicochemical Properties Scores of

0 as follows:

0 = (8 – 8) / (9 – 8)

• Total Hazard Potential Score (Cancer MCDA): The Toxicity Score (0.33), Occurrence

Score (0), and Physicochemical Properties Score (0) were summed to calculate a Total

Hazard Potential Score of 0.33. The relative contribution of the three criteria scores to this

total score is depicted as a graphic in Figure 9-12.
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10. Synthesis

Introduction 

The goals of this report were to assess the potential for activities in the hydraulic fracturing water 

cycle to impact the quality or quantity of drinking water resources, and to identify factors affecting 

the frequency or severity of those impacts. Overall, we conclude activities in the hydraulic 

fracturing water cycle can impact drinking water resources under some circumstances. Impacts can 

range in frequency and severity, depending on the combination of hydraulic fracturing water cycle 

activities and local- or regional-scale factors. The following combinations of activities and factors 

are more likely than others to result in more frequent or more severe impacts:

• Water withdrawals for hydraulic fracturing in times or areas of low water availability, 

particularly in areas with limited or declining groundwater resources; 

• Spills during the management of hydraulic fracturing fluids and chemicals or produced 

water that result in large volumes or high concentrations of chemicals reaching 

groundwater resources; 

• Injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, 

allowing gases or liquids to move to groundwater resources;

• Injection of hydraulic fracturing fluids directly into groundwater resources; 

• Discharge of inadequately treated hydraulic fracturing wastewater to surface water 

resources; and

• Disposal or storage of hydraulic fracturing wastewater in unlined pits, resulting in 

contamination of groundwater resources.

These conclusions are based on cases of identified impacts and other data, information, and 

analyses presented in this report. Cases of impacts were identified for all stages of the hydraulic 

fracturing water cycle. Identified impacts generally occurred near hydraulically fractured oil and 

gas production wells and ranged in severity, from temporary changes in water quality to 

contamination making private drinking water wells unusable. The inherent characteristics of 

groundwater resources make them more vulnerable to impacts from activities in the hydraulic 

fracturing water cycle compared to surface water. 

We see the identification of factors affecting the frequency or severity of impacts, and uncertainties

and data gaps in this report as particularly useful for decision makers. Factors often can be 

managed, changed, or used to identify areas for specific monitoring or modification of practices.

Thus, in the short-term, information on factors can help decision makers reduce current 

vulnerabilities of drinking water resources to activities in the hydraulic fracturing water cycle. In 

the longer term, reducing the uncertainties and filling the data gaps could enhance science-based 

decisions to protect drinking water resources in the future. 

The purpose of this chapter is to synthesize for decision makers the information on factors, 

uncertainties, and data gaps presented in this assessment. In Section 10.2, we focus on factors 
Chapter 10 – Synthesis

10-4 

increasing or decreasing the frequency or severity of impacts at each stage of the hydraulic 

fracturing water cycle. In Section 10. 3, we discuss major uncertainties and data gaps identified in 

this assessment. Finally, in Section 10.4, we discuss potential uses for this assessment. 

10.1 Factors Affecting the Frequency or Severity of Impacts

10.1.1 Water Acquisition 

Groundwater and surface water resources serve as both sources of water for hydraulic fracturing 

and public and private drinking water supplies. Thus, water withdrawals for hydraulic fracturing 

can impact the quantity or quality of drinking water resources under certain circumstances. Since, 

by definition, every water withdrawal affects water quantity, we focused in this assessment not on 

all water withdrawals per se, but rather on those with the potential to limit the availability of 

drinking water or alter its quality. Whether a withdrawal has this potential depends upon a 

combination of factors at the local scale. Factors can either increase or decrease the frequency or 

severity of impacts. In this section on water acquisition, we combine our discussion of frequency 

and severity because all of the factors we discuss in this section affect both frequency and severity 

in a similar fashion (i.e., either increase both frequency and severity, or decrease both frequency 

and severity). 

10.1.1.1 Frequency and Severity 

The local balance between water withdrawals and water availability is the most important factor 

determining whether water acquisition impacts are likely to occur or be severe. Impacts are more 

likely to be frequent or severe where or when hydraulic fracturing water withdrawals are relatively 

high and water availability is low. In contrast, the same amount of water withdrawn can have a 

negligible effect if withdrawn in an area of—or at a time of—higher water availability. For this 

reason, it is important not to focus solely on the amount withdrawn, but the balance between water 

withdrawals and availability in place and time. 

For this assessment, we developed county-level estimates of water use (i.e., water withdrawals) for 

hydraulic fracturing, which were then compared to an index of readily available fresh water. This 

readily available fresh water index included unappropriated surface water and groundwater, and 

appropriated water potentially available for purchase (Tidwell et al., 2013) (Text Box 4-2).1 In the 

majority of counties where hydraulic fracturing takes place, hydraulic fracturing water use was less 

than 1% of this index of readily available fresh water. We did find, however, a small number of 

counties with higher percentages. There were 45 counties out of the almost 400 surveyed where 

hydraulic fracturing water use was above 10% of the index. Of these counties, 35 exceeded 30%, 

and 17 of these counties had hydraulic fracturing water use exceeding the index. All of the counties 

in this latter category are located in Texas. 

 

1 In the western United States, water is generally allocated by the principle of prior appropriation—that is, first in time of 

use is first in right. New development must use unappropriated water or purchase appropriated water from vested users. 

In the index of readily available fresh water, it was assumed 5% of appropriated irrigated water could be purchased. See 

Text Box 4-2 for more details about this analysis. 
Chapter 10 – Synthesis

10-5 

This does not mean impacts to drinking water quantities occurred or will occur in these counties, 

nor does it mean that impacts did not or will not occur in counties with relatively low percentages. 

To truly determine whether impacts occurred, water withdrawals and availability need to be 

compared at the scale of the drinking water resource. For instance, groundwater withdrawals for 

hydraulic fracturing could affect water levels in nearby private water wells. As a national 

assessment, we could not often examine impacts at this local scale, although we did cite studies of 

local impacts where available. Nevertheless, our county level assessment does point to places

where the potential for impacts is higher. This information may be useful to focus efforts on 

reducing the fresh water demand of hydraulic fracturing. 

Beyond our county level assessment, we conclude that declining groundwater resources are 

particularly vulnerable to water quantity and quality impacts from withdrawals. Groundwater 

recharge rates can be low, and groundwater withdrawals are exceeding recharge in areas of the 

country (Konikow, 2013). When withdrawals exceed recharge, the result is declining water levels. 

For this reason, water levels in some aquifers in the United States have declined substantially over 

the last century (Konikow, 2013). Although irrigated agriculture is often the dominant user of 

groundwater, hydraulic fracturing withdrawals now also contribute to declining groundwater 

levels in some areas (e.g., southern Texas; Steadman et al., 2015; Scanlon et al., 2014b) Cumulative 

groundwater withdrawals can also impact water quality by mobilizing chemicals, such as uranium,

from naturally occurring sources in the surrounding rock into the groundwater (DeSimone et al., 

2014). 

In certain instances, state and local governments have encouraged or mandated the use of surface 

water in place of groundwater, as evidenced in both Louisiana and North Dakota. In 2008, the state 

of Louisiana asked oil and gas companies to switch from groundwater to surface water to mitigate 

stress on the Carrizo-Wilcox aquifer, a critical source of drinking water in the region. Likewise, the 

state of North Dakota requested the oil industry obtain water from the Missouri river system, and 

not from stressed groundwater sources. By contrast, surface water availability is limited in other 

regions and cannot provide an alternative source of water (e.g., western Texas). 

Among surface water sources, small streams are particularly vulnerable to impacts. This is the case 

across the country, even in the eastern United States where surface water is generally more 

plentiful. An EPA study of the Susquehanna River Basin in northeastern Pennsylvania found that the 

smallest streams (with less than 10 mi2 of contributing area–i.e., the watershed area drained by the 

stream) would be the most likely to be impacted from water withdrawals in the absence of 

protective passby flows; see discussion below and U.S. EPA (2015e).1 While the amount of 

contributing area varies by geographic location due to differences in runoff, the finding that the 

smallest streams are the most vulnerable to withdrawals holds across all landscapes. 

Not only does water availability vary from one location to another, but it can also vary temporally at 

a given location, often due to variations in precipitation. Because of this dynamic, long-term or 

seasonal drought can increase the frequency or severity of impacts from withdrawals by decreasing 

water availability. The EPA study of the Susquehanna River Basin found even larger streams (up to 

 

1 Passby flows are low stream flow thresholds below which withdrawals are not allowed.
Chapter 10 – Synthesis

10-6 

600 mi2 of contributing area) would be vulnerable to impacts at times of drought, again absent 

passby flows (U.S. EPA, 2015e). Dry conditions can also stress groundwater supplies by 

simultaneously increasing water demand (e.g., irrigation water demand increases in dry 

conditions) while also decreasing groundwater recharge. Much of the western United States has 

experienced extended periods of drought over the last decade. Climate change is likely to 

exacerbate these conditions in certain locations (Meixner et al., 2016). 

Conversely, there are factors that can reduce the frequency or severity of impacts. Reuse of 

hydraulic fracturing wastewater (i.e., produced water managed for reuse, treatment and discharge, 

or disposal), for example, can reduce demands on fresh water resources.1 Reuse does not appear to 

be driven by water scarcity, but rather by the cost of disposal. Operators are likely to dispose of 

wastewater when it is less expensive than reuse. For instance, greater reuse of wastewater occurs 

in the Marcellus Shale in Pennsylvania than in the Barnett Shale in Texas, even though water 

availability is generally higher in the Marcellus region (Figure 10-1). The general lack of disposal 

wells in Pennsylvania means disposing of wastewater requires trucking to Ohio or other locations 

with disposal wells. Because of this expense, operators reuse substantial proportions of their 

wastewater, in contrast to the Barnett Shale where disposal wells are readily available. 

The reuse of wastewater to offset fresh water use in hydraulic fracturing is often limited by the 

amount of wastewater available. The volume of produced water from a single well can be relatively 

small compared to the volume needed to fracture a well (Figure 10-1a). This means produced water 

would need to be aggregated from multiple wells to equal the volume needed to hydraulically

fracture an additional well. For instance, it would take 10 wells to make enough water to fracture 

an 11th well if, as has been shown in the Marcellus Shale in Pennsylvania, produced water volumes 

are 10% of injected volumes (Figure 10-1a). Thus, reuse is a factor that can reduce fresh water 

demand, but not eliminate it in most cases. Nevertheless, even a marginal decline in fresh water 

demand can make a difference in the frequency or severity of impacts. 

The use of brackish groundwater is also a factor reducing fresh water demand, in some cases to a 

much greater degree than reuse. In the Permian Basin in western Texas, for instance, brackish 

water makes up 30 to 80% of water used for hydraulic fracturing, and 20% in the Eagle Ford Shale 

in southern Texas (Nicot et al., 2012). Our county level estimates suggest brackish water availability 

could entirely meet current hydraulic fracturing water demand in Texas and many other locations.2

In 35 counties nationally, hydraulic fracturing water use equaled or exceeded 30% of an index of 

fresh water availability; when brackish water and wastewater were considered in addition to fresh 

water availability, only two counties equaled or exceeded 30% (Text Box 4-2).

 

1 Hydraulic fracturing wastewater is 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. The term 

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 (see Chapter 8 and Appendix J, the Glossary, for more detail). 

2 Brackish water for the purposes of this analysis ranged from 3,000 to 10,000 ppm of total dissolved solids (TDS), and 

from 50 to 2,500 ft (15-760 m) below the surface (Tidwell et al., 2013). (See Text Box 4-2 for more details.)
Chapter 10 – Synthesis

10-7 

Figure 10-1. Water budgets representative of practices in (top) the Marcellus Shale in the 

Susquehanna River Basin in Pennsylvania and (bottom) the Barnett Shale in Texas.

Pie size and arrow thickness represent the relative volume of water as it flows through the hydraulic fracturing 

water cycle. Water budgets illustrative of typical water management practices in the Marcellus Shale in the 

Susquehanna River Basin between approximately 2008 and 2013 and the Barnett Shale in Texas between 

approximately 2011 and 2013. They do not represent any specific well. Sources for the top figure (a) Tables 4-1 and 

4-2 (SRBC, 2016)—note, surface water, groundwater, and reuse values of 92%, 8%, and 16% in table normalized to 

79%, 7%, 14%, respectively, for this chart (this was done to represent reuse on the same chart as surface water 

and groundwater—in the original tabular values, reuse is expressed as a percentage of total water used, and 

surface water and groundwater are expressed in percentages relative to each other); (b) Appendix Table B-5 (U.S. 

EPA, 2015a); (c) Table 7-2 (Ziemkiewicz et al., 2014)—note: produced water volumes estimated from percentages 

applied to volumes injected, and value from the West Virginia portion of the Marcellus Shale used in this chart 

since it was the longest term measurement of produced water volumes; (d) Figure 8-4 (PA DEP, 2015a) and Table 

8-6 (Ma et al., 2014; Shaffer et al., 2013). Sources for the bottom figure: (e) Tables 4-1 and 4-2 (Nicot et al., 2014; 

Nicot et al., 2012)—note, surface water, groundwater, and reuse values of 50%, 50%, and 5% in the tables 

normalized to 48%, 48%, and 4%, respectively, for this chart (see reason for this above); (f) Appendix Table B-5 

(U.S. EPA, 2015a; Nicot et al., 2012; Nicot et al., 2011)—note: see median value for Fort Worth Basin; (g) Table 7-2 

(Nicot et al., 2014); (h) Table 8-6 (Nicot et al., 2012)—note, percentage going to disposal wells estimated by 

subtracting reuse values from 100%. 
Chapter 10 – Synthesis

10-8 

Finally, passby flows can be a factor reducing the frequency or severity of surface water impacts. 

Passby flows are low stream flow thresholds below which withdrawals are not allowed. This

management practice has been shown to be protective of streams from over-withdrawals in the 

Susquehanna River Basin in northern Pennsylvania (U.S. EPA, 2015e). This is likely most important 

for protecting aquatic life in smaller streams, but may also aid in protecting drinking water 

supplies. 

10.1.2 Chemical Mixing and Produced Water Handling 

Like water acquisition, activities in the chemical mixing and produced water handling stages of the 

hydraulic fracturing water cycle can impact drinking water in some instances. We combine our 

discussion of the two stages here because activities in these stages both affect drinking water 

resources primarily through spills. The chemical mixing stage encompasses management of fluids 

on the well pad to create hydraulic fracturing fluid. Chemicals are mixed with a base fluid, typically 

water, and then injected into the production well. After the pressure is released post-fracturing, 

produced water flows from the well and needs to be collected and managed in the produced water 

handling stage.

Chemical mixing and produced water handling activities can impact drinking water resources 

through spills of chemicals used to make hydraulic fracturing fluid, hydraulic fracturing fluid itself, 

or produced water reaching surface water or groundwater.1 There is some information on spill 

frequencies—although limited—and spill severities are most often uncharacterized. Nevertheless, 

we could identify factors affecting the frequency or severity of impacts from chemical mixing or 

produced water spills. In the section below, we discuss these factors, with those affecting frequency 

first, followed by those affecting severity. We discuss each of the factors individually, but spill 

events in reality exhibit combinations of these factors. These factors can interact to increase or 

decrease the frequency or severity of a spill beyond the effect of an individual factor. 

10.1.2.1 Frequency

An impact on the quality of a drinking water resource from a spill first depends on a spill occurring. 

Most spill frequency estimates are of spills in total, and not the subset reaching drinking water 

resources. Spill estimates from three states (Colorado, North Dakota, and Pennsylvania) ranged 

from 0.4 to 12.2 reported spills per 100 hydraulically fractured wells (Appendix C.4).2 The 

estimates from Pennsylvania and Colorado included hydraulic fracturing chemicals, fluids, and 

produced water; while the North Dakota estimate was based on spills of hydraulic fracturing 

chemicals and fluids only.3 Spill rates can also be expressed on a per-active-well basis. This may be 

 

1 In Chapter 5 and elsewhere in this assessment, the chemicals added to the base fluid (most often water) and proppant 

(most often sand) are referred to as “additives” since this is the term used in FracFocus. Here, this chapter simply refers to 

them as “chemicals.” It does this to discuss chemicals in a unified manner in this combined section on chemical mixing and 

produced water. 

2 Since most wells are not reported hydraulically fractured in databases, these estimates used spudded, completed, or 

installed wells as proxies for hydraulically fractured wells. (See Appendix Section C.4 for more detail.)

3 These estimates from Pennsylvania and Colorado also included spills of diesel fuel and drilling muds, which could not be 

separated out from the total frequency estimate even though they were generally out-of-scope of this assessment (diesel 

fuel was in scope if used in hydraulic fracturing fluid). 
Chapter 10 – Synthesis

10-9 

more appropriate for produced water spills since they can occur years or even decades after 

hydraulic fracturing. An analysis of North Dakota produced water spills found there were 

approximately 5 to 7 spills of produced water per 100 active wells between 2010 and 2015 

(Appendix E.5). We conclude from these data that spills do occur in both the chemical mixing and 

produced water stages of the hydraulic fracturing water cycle, generally in the range of 1 to 10% of 

hydraulically fractured or active wells.

Not all spills, however, reach and therefore impact a drinking water resource. In U.S. EPA (2015m), 

32 of the 457 (7%) spills characterized were reported to have reached surface water or 

groundwater. The California Office of Emergency Services estimated 18% of produced water spills 

reached waterways between January 2009 and December 2014 (CCST, 2015b). It is unclear if this 

estimate included groundwater, or was limited to surface water. If, however, roughly 5 to 20% of 

spills reach surface water or groundwater (encompassing the U.S. EPA and California estimates 

above), we would expect a spill to occur and reach a drinking water resource at approximately 0.05

to 2% of active or hydraulically fractured wells.1 This estimate of spills reaching drinking water 

resources would be broadly consistent with estimates from the limited number of published studies 

addressing this topic (e.g., Brantley et al., 2014; Gross et al., 2013).2 If a 0.05 to 2% frequency rate is

applied to the estimates of approximately 275,000 to 370,000 new wells hydraulically fractured 

nationally between 2000 and part of 2013 and 2000 and part of 2014, respectively (Chapter 3), we 

would expect roughly 140 to 7,400 spills to reach a drinking water resource during this almost 14-

to-15 year time-period. This would be approximately 10 to 500 spills per year reaching a drinking 

water resource, dividing by the respective time periods. This large range reflects the high 

uncertainty of these estimates and the lack of data on this topic. 

Despite the data limitations and uncertainties surrounding estimates of spills, we can with more 

certainty identify factors likely affecting the frequency of spills reaching drinking water resources. 

These factors include spill characteristics, encompassing the volume of the chemical spilled; factors 

related to the environmental fate and transport of the spill, such as properties of the chemical 

spilled and characteristics of the site where the spill occurred; and finally, factors related to spill 

prevention and response.

Everything else being equal, a larger volume spill will be more likely to reach a drinking water 

resource than a smaller spill (U.S. EPA, 2015m). On-site spills in the chemical mixing and produced 

water handling stages are typically in the hundreds of gallons (U.S. EPA, 2015m). Larger spills, 

though less common, do occur. Well blowouts, pipeline leaks, and impoundment failures are 

sources of some of the largest individual spill volumes. Well blowouts were responsible for the 

 

1 Estimated by multiplying the 1 to 10% spill rate for active or hydraulically fractured wells by 5% to 20% for spills 

reaching drinking water, and then reconverting to a percentage by multiplying by 100. 

2 Brantley et al. (2014) estimated approximately 0.4 to 0.8 spills per 100 hydraulically fractured wells reached surface 

water in Pennsylvania between 2008 to September 2013. These were spills of 400 gal (1,514 L) or more, containing 

hydraulic fracturing chemicals, fluids, or produced water. This might be an underestimate of spills reaching surface water 

since spill volumes were limited to only 400 gal (1,514 L) or more. In estimate of the frequency of spills reaching 

groundwater, Gross et al. (2013) examined oil and produced water spills between July 2010 and July 2011 in Weld 

County, Colorado. They counted 77 such spills reaching groundwater, approximately 0.4% of the nearly 18,000 active 

wells in the county.
Chapter 10 – Synthesis

10-10 

highest volume spills on average in 2015 in North Dakota. In Bradford County, Pennsylvania, a well 

blowout resulted in a spill of approximately 10,000 gal (38,000 L) of produced water into a 

tributary of Towanda Creek, a state designated trout fishery. The largest volume spill identified in 

this assessment occurred in North Dakota, where approximately 2.9 million gal (11 million L) of 

produced water spilled from a broken pipeline and impacted surface water and groundwater. 

Though relatively rare compared to smaller volume spills, these types of spills are more likely to 

reach—and therefore impact—a drinking water resource because they are of larger volumes. 

By this same principle, produced water spills are more likely to impact drinking water resources 

than chemical mixing spills. In an analysis of on-site spills, the median volume of produced water 

spills was approximately twice as large as that in the chemical mixing stage (990 versus 420 gal, or 

3,750 versus 1,590 L; U.S. EPA (2015m)). Additionally, offsite, large pipeline spills of produced 

water can occur. It is possible that spills of produced water are larger, in part, because they are less 

likely to be stopped as quickly as spills in the chemical mixing stage. Spills in the chemical mixing 

stage are likely to occur when people are on-site, and so the spills can be quickly addressed. In 

contrast, spills of produced water may occur when no one is on-site or, in the case of pipelines, near 

the off-site location of the spill. This may delay a response, allowing larger volumes to spill, 

increasing the likelihood of the spill reaching a drinking water resource. 

Properties of the chemicals spilled also affect the frequency of impacts. We identified or estimated 

chemical and physical properties for almost half of the chemicals used in hydraulic fracturing fluids 

between 2006 and 2013 (455 of the 1,084 chemicals). These were individual organic chemicals, not 

inorganic chemicals, polymers, or mixtures. Volatility, solubility, and hydrophobicity/hydrophilicity 

are three properties, among others, affecting whether a spill reaches a drinking water resource

(hydrophobic chemicals tend to repel or fail to mix with water, while hydrophilic chemicals tend to 

mix with water). The vast majority of organic chemicals in hydraulic fracturing fluid do not readily 

volatilize or evaporate, meaning these chemicals tend to remain in water if spilled. These chemicals 

also vary widely in their solubility and hydrophobicity/hydrophilicity, defying a general 

characterization. Nevertheless, of the 20 chemicals most frequently used according to our analysis 

of FracFocus, most are highly soluble and hydrophilic, meaning they will be mobile if spilled

(Chapter 5). For example, methanol, isopropanol, and ethylene glycol are all likely to travel quickly 

through the environment. Thus, these chemicals may more frequently reach drinking water 

because of two unrelated, yet compounding factors: relatively high frequency of use in hydraulic 

fracturing operations and relatively high mobility in the environment. 

Site characteristics are also an important factor determining whether a spill reaches a drinking 

water resource (Figure 10-2). Site characteristics facilitating infiltration to groundwater are of 

particular concern, since spills into groundwater are more likely to have severe impacts than those 

into surface water (discussed in the severity section below). More permeable, sandier soils allow 

greater infiltration of spilled fluids, whereas less permeable soils with more clay content can greatly 

slow infiltration. More permeable rock also facilitates infiltration and movement of spills through 

preferential flow paths—for example, in fractured or karst bedrock. Thus, sandier soils and more 

permeable rock can increase the potential for spills to reach groundwater. 
Chapter 10 – Synthesis

10-11 

Figure 10-2. Fate and transport schematic for a spill of chemicals, hydraulic fracturing fluid, or 

produced water. 

Schematic shows the potential paths, transport processes, and factors governing potential impacts of spills to 

drinking water resources. 

There are spill prevention and response factors that reduce the frequency of impacts to drinking 

water resources from spills. Spill containment systems include primary, secondary, and emergency 

containment systems. Primary containment systems are the storage units, such as tanks or totes. 

Secondary containment systems, such as liners and berms installed during site set-up, are intended 

to contain spilled fluids until they can be cleaned up. Emergency containment systems, such as 

berms, dikes, and booms, can be implemented temporarily in response to a spill. Remediation is the 

action taken to clean up a spill and its affected environmental media. One of the most commonly 

reported remediation activities is the removal of spilled fluid and/or affected media, typically soil 

(U.S. EPA, 2015m). Other remediation methods include the use of absorbent material, vacuum 

trucks, flushing the affected area with water, and neutralizing the spilled material (U.S. EPA, 

2015m). It was beyond the scope of this assessment to evaluate the implementation and efficacy of 

spill prevention practices and spill response activities.

10.1.2.2 Severity

In addition to frequency, there are also factors affecting the severity of an impact on a drinking 

water resource from a spill. For a given concentration, a larger volume spill will be more severe 

than a smaller spill (see frequency section above for discussion of spill volumes). In addition to 
Chapter 10 – Synthesis

10-12 

volume, the concentration and toxicity of the chemicals reaching a drinking water resource affect 

severity, as well as site characteristics. 

A spill with higher chemical concentrations will be more severe than a more dilute spill of equal 

volume. In the chemical mixing stage, chemicals are stored in concentrated form on-site, prior to 

diluting with a base fluid. Approximately 3,000 to 30,000 gal (11,000 to 114,000 L) of chemicals are 

used per well on average, with up to twice that amount stored on site. If multiple wells are 

fractured per site, tens to hundreds of thousands of gallons of chemicals are likely stored in 

containers at a single site during the hydraulic fracturing of these wells. These storage containers 

are a relatively frequent source of spills during the chemical mixing stage. Spills from these storage 

containers, even if low in volume, may be severe if they reach a drinking water resource because 

they often contain concentrated chemicals. 

In the produced water handling stage, the severity of impacts from a spill also increases with higher

concentrations, especially if the spill reaches groundwater (see site characteristics below). 

Produced water can vary substantially in chemical concentrations, including total dissolved solids 

(TDS), metals, radioactive isotopes, and organic chemicals. Within the Marcellus Shale, for example, 

produced water can range in TDS from less than 1,500 mg/L to over 300,000 mg/L (Rowan et al., 

2011). By comparison, the average salinity concentration for seawater is 35,000 mg/L. The more 

concentrated the produced water, the more likely impacts will be severe if a spill reaches a drinking 

water resource. When a spilled fluid has greater concentrations of TDS than groundwater, the 

higher-density fluid can move downward through the groundwater resource. Depending on the 

flow rate and other properties of the groundwater, impacts from produced water spills can last for 

years.

In addition to concentration, the toxicity of chemicals affects the severity of the impact if they enter 

a drinking water resource. There were 37 chemicals listed in 10% or more of all FracFocus

disclosures between January 1, 2011 and February 28, 2013. Of these 37 chemicals, nine had 

chronic oral reference values meeting the criteria used in this assessment. 1 These nine chemicals 

are associated with health effects including liver toxicity, kidney toxicity, developmental toxicity, 

reproductive toxicity, and/or carcinogenesis. Chemicals used in hydraulic fracturing fluids and 

detected in produced water will vary from site to site, so human health hazards are best evaluated 

on a site-specific basis. Nevertheless, the multi-criteria decision analysis (MCDA) presented in 

Chapter 9 highlighted certain chemicals that may have greater hazard potential. Propargyl alcohol, 

2-butoxyethanol, and N,N-dimethylformamide are three such chemicals having relatively greater 

hazard potential in the MCDA based on toxicity, frequency of use in hydraulic fracturing fluids, and 

mobility in water.

Many of the chemicals in produced water are also known or suspected to cause cancer and/or noncancer health effects in humans. Associated health effects include liver toxicity, kidney toxicity, 

neurotoxicity, reproductive and developmental toxicity, and carcinogenesis, based on the produced 

 

1 The analysis of toxicity presented in Chapter 9 included chemicals regardless of accompanying concentration data in 

FracFocus, and therefore listed 37 chemicals that were reported in 10% or more disclosures. Comparatively, Chapter 5 

listed 35 chemicals that had valid concentration data from FracFocus and were reported in 10% of more disclosures.
Chapter 10 – Synthesis

10-13 

water chemicals having chronic oral reference values meeting the criteria used in this assessment. 

Benzene, pyridine, and naphthalene are three of the chemicals highlighted in the MCDA as having 

relatively greater hazard potential based on toxicity, measured concentrations in produced water, 

and mobility in water. 

We did not evaluate trends in chemical use by toxicity (e.g., the trends in the use of less toxic 

chemicals). However, a more recent study of FracFocus data evaluated disclosures dating from 

March 9, 2011, to April 13, 2015 (Dayalu and Konschnik, 2016; Konschnik and Dayalu, 2016). When 

compared to the list of 1,084 chemicals used in hydraulic fracturing operations between 2005 and 

2013 compiled for this assessment (Appendix H), an additional 263 chemicals were identified 

(Chapter 5). Only one of these 263 chemicals was reported in more than 1% of disclosures. This 

comparison of chemical lists does not address potential shifts in volumes of chemicals used, but it 

does suggest that a shift to new types of chemicals–less toxic or otherwise–did not occur between 

2013 and early 2015. 

Finally, site characteristics also affect the severity of the impact. Spills into groundwater are likely 

to be more severe than spills into surface water, everything else being equal. This is not to say that

spills into surface water cannot be severe, especially in the immediate vicinity of the spill. For

instance, a tank overflowed on a well site in Kentucky spilling fluid into a nearby stream at

concentrations sufficient to kill fish in the area (Papoulias and Velasco, 2013). Chemicals can also

associate with stream sediments, forming a source of long-term contamination (e.g., radium). In 

general, however, surface water dilutes a spilled chemical much more rapidly than groundwater. 

Groundwater often moves slowly between areas of recharge and discharge. Groundwater 

movement can be as slow as one foot per year or even one foot per decade (Alley et al., 1999). 

Because of this dynamic, chemicals from multiple spills can accumulate over time in groundwater. 

Multiple chemical mixing and produced water spills, even if individually small, may impact a 

groundwater resource in aggregate. Additionally, groundwater contamination may not be as readily 

apparent as that in surface water because of the need to install monitoring wells to detect 

contamination in groundwater. Lastly, groundwater can be difficult and expensive to remediate,

adding to the severity of impacts if spills reach groundwater (Alley et al., 1999). 

10.1.3 Well Injection

Like the water acquisition, chemical mixing, and produced water handling stages, activities in the 

well injection stage of the hydraulic fracturing water cycle can affect drinking water resources in 

some instances. The well injection stage involves the injection of hydraulic fracturing fluids through 

the production well and into the targeted rock formation at sufficient pressure to fracture the rock. 

There are two fundamental pathways outlined in this assessment by which activities in the well 

injection stage have the potential to affect drinking water resource quality. They are: (1) fluid 

(meaning, liquid or gas) movement into a drinking water resource through defects or deficiencies 

in the production well casing and/or cement; and (2) fluid movement into a drinking water 

resource through the fracture network. The fluids potentially affecting drinking water resources 

include hydraulic fracturing fluids, hydrocarbons (including methane gas), and naturally occurring 

brines. The drinking water resources impacted directly in this stage are almost always groundwater 

resources, rather than surface water.
Chapter 10 – Synthesis

10-14 

Though we could not in this assessment quantify an overall frequency of groundwater quality 

impacts from the well injection stage, we can describe factors which make impacts more or less 

frequent or more or less severe, as we did for other stages. We describe these factors below, first 

with frequency and then severity. Within the frequency discussion, we address factors by each 

pathway type. 

10.1.3.1 Frequency

Pathway #1: Fluid movement into a drinking water resource through defects or deficiencies in the 

production well casing and/or cement. 

To reach and then fracture the production zone, an oil or gas well must first be drilled and 

constructed down through the subsurface rock formations, often containing an overlying drinking 

water resource. Since the well passes through the drinking water resource, this means defects or 

deficiencies in the production well can lead to unintended movement of fluid into the drinking 

water resource. This can occur regardless of the vertical separation between the drinking water 

and the production zone. 

The relatively brief hydraulic fracturing phase will likely impose the highest stresses to which the 

well will be exposed during its entire life. If the well cannot withstand the stresses experienced 

during hydraulic fracturing, the casing or cement can fail, resulting in the loss of mechanical 

integrity and the unintended movement of fluids into the surrounding environment. 

A few studies have estimated rates of mechanical integrity failure of production wells resulting in 

the loss of all barriers protecting the groundwater or in contamination of groundwater in areas 

with hydraulic fracturing activity (Table 10-1). The estimates are all approximately equal to or less 

than 1% of wells drilled or hydraulically fractured over varying time frames. For most of these 

estimates, it is not possible to tell whether failures occurred during hydraulic fracturing or at some 

other point in the well’s life, with the exception of the EPA’s Well File Review (U.S. EPA, 2015n). If 

the failure rate from the Well File Review (0.5%) is applied to the estimates of 275,000 to 370,000 

new wells hydraulically fractured nationally between 2000 and part of 2013 and 2000 and part of 

2014, respectively (Chapter 3), we would expect roughly 1,370 to 1,850 mechanical integrity 

failures during this time-period (almost 14 to 15 years). Dividing by each time period yields 

approximately 100 to 125 mechanical integrity failures per year on average, resulting in the loss of 

all barriers protecting the groundwater during hydraulic fracturing. These estimates also have a 

high degree of uncertainty like the spills estimates. This not only stems from the lack of certainty 

about failure rates, but also uncertainties surrounding the estimates of the number of wells 

hydraulically fractured (Chapter 3). These are likely low estimates because they do not include 

mechanical integrity failures occurring outside of the hydraulic fracturing process (e.g., during the 

production phase), nor do they consider failures in re-fractured wells. 
Chapter 10 – Synthesis

10-15 

Table 10-1. Literature estimates of mechanical integrity failure rates resulting in 

contamination of groundwater or failure of all well barriers, potentially exposing the 

groundwater.

Citation Mechanical Integrity 

Failure Rate (%)

Geographic 

Scope

Key Findings & Description of Mechanical 

Integrity Failurea,b

Fleckenstein et 

al. (2015)

0.06 ColoradoWattenberg 

Field

An overall catastrophic failure rate of 0.06% was found 

for 16,828 wells studied (out of 17,948 total wells) 

drilled in the Wattenberg Field between 1970 and 2013. 

The timing of the failures was unknown, but most of the 

failures occurred in the older wells. The Wattenberg 

Formation is 4,400 ft (1,300m) below surface and 

typically is hydraulically fractured. A catastrophic failure 

was considered to have occurred when there was 

contamination of drinking water aquifers (i.e., the 

presence of thermogenic gas in a drinking water well) 

and evidence of a well defect such as exposed 

intermediate gas formations or casing leaks.

Considine et al. 

(2012)

0.06 Pennsylvania Two wells were cited between 2008 and 2011 by PA 

DEP for causing methane migration into an aquifer. In 

this same time period, 3,533 wells were drilled. 

Brantley et al. 

(2014)

0.12–1.1 Pennsylvania Based on positive determination letters (PDLs) for 

violations that occurred between 2008 and 2012, 

Brantley et al. estimated between 7 and 64 problematic 

unconventional wells contaminated 85 properties.

Since PDLs are tied to drinking water wells and not gas 

wells, Brantley et al. made assumptions about how 

many unconventional gas wells were represented by 

each PDL. This equates to problematic unconventional 

gas wells compromising approximately 0.1 to 1% of the 

6,061 wells spudded between 2008 and 2012.c Not all of 

these PDLs may be due to mechanical integrity failures–

they could also be due to other causes, such as spills, or 

methane migration from natural or other 

anthropogenic sources.

Vidic et al. 

(2013)

0.25 Pennsylvania Of the 6,466 wells studied, 16 received notices 

regarding contamination of groundwater with gas or 

other fluids from the PA DEP associated with incidents 

that occurred between 2008 and 2013.
Chapter 10 – Synthesis

10-16 

Citation Mechanical Integrity 

Failure Rate (%)

Geographic 

Scope

Key Findings & Description of Mechanical 

Integrity Failurea,b

U.S. EPA (2016c) 0.5 National In an estimated 0.5% of the approximately 28,500 

hydraulic fracturing jobs surveyed, a failure occurred 

during hydraulic fracturing, such that there was no 

additional barrier between the annular space with fluid 

and the protected drinking water resource. While it 

could not definitively be determined whether fluid 

movement into the protected drinking water resource 

occurred, in these cases, all of the protective barriers 

intended to prevent such fluid migration had failed, 

leaving the groundwater source vulnerable to 

contamination.

a Note: While some information is available on the age of the wells studied, it is unclear whether the failure occurred during the 

hydraulic fracturing event, with the exception of the U.S. EPA (2016c) study. In that study, the failures occurred during hydraulic 

fracturing.

b While the Pennsylvania studies did not specifically identify whether the wells were involved in hydraulic fracturing operations, 

a significant portion of Pennsylvania’s recent oil and gas activity is in the Marcellus Shale; therefore, many of the wells in these 

studies were most likely used for hydraulic fracturing. 

c Spudding refers to starting the well drilling process by removing rock, dirt, and other sedimentary material with the drill bit

(U.S. EPA, 2013f). 

Not all wells are equally likely to lose mechanical integrity; instead, there are factors that make 

some wells more likely to experience a mechanical integrity failure than others. Well design and 

construction are two such factors. First, a primary element of well design is the placement of at 

least one additional layer of casing (besides the production casing) from the surface through the 

lowest depth of the drinking water resource. This additional casing provides redundancy if the 

production casing fails. In a study of 731 saltwater injection wells in the Williston Basin in North 

Dakota, Michie and Koch (1991) found the risk of aquifer contamination from leaks into the 

drinking water resource was 7 in 1,000,000 injection wells if a surface casing, in addition to the 

production casing, was set deep enough to cover the drinking water resource. The risk increased to 

6,000 per 1,000,000 wells (or 6 in 1,000) if this additional casing was not set deeper than the 

bottom of the drinking water resource.

Second, fully cementing casing(s) through the entire drinking water resource affects the frequency 

of impacts. Uncemented sections of surface casing increase the frequency of fluid leaks from the 

well that can reach groundwater (Fleckenstein et al., 2015; Watson and Bachu, 2009). The EPA’s 

Well File Review estimated that a portion of the protected groundwater resource identified by well 

operators was uncemented in 3% of the wells surveyed (U.S. EPA, 2015n). With approximately 

25,000 to 30,000 new wells hydraulically fractured a year (Chapter 3), this percentage means 750 

to 900 of the wells used in hydraulic fracturing operations annually might lack this protection. 

Adding re-fractured wells would increase the estimate of wells lacking this protection. Knowing the 

depth of the groundwater resource at the point of drilling and then setting and cementing casings 

below the lowest part of the drinking water resource can reduce the frequency or likelihood of an 

impact. 
Chapter 10 – Synthesis

10-17 

Third, the well’s casing, cement, and components need to be designed and constructed to withstand 

the stresses applied to the well during hydraulic fracturing. In an example of inadequate well 

construction, hydraulic fracturing of a gas well with insufficient and improperly placed cement in 

Bainbridge Township, Ohio led to gas contamination of 26 domestic water supply wells and an 

explosion in the basement of one of the nearby homes. This was due in part to a failure to cement 

through the over-pressured gas formations and proceeding with the fracturing operation without 

adequate cement (ODNR, 2008). In another case, casings at an oil well near Killdeer, North Dakota,

ruptured in 2010 following a pressure spike during hydraulic fracturing, allowing fluids to escape 

to the surface. Brine and tert-butyl alcohol were detected in two nearby water wells. Following an 

analysis of potential sources, the only potential source consistent with the conditions observed in 

the two impacted water wells was the ruptured well (U.S. EPA, 2015i). 

In addition to well design and construction, the degradation or corrosion of well components can 

also increase the frequency of impacts to drinking water quality. Older wells exhibit more integrity 

problems as cement and casings age. The EPA’s Well File Review estimated at least 10% of the wells 

represented in the national survey were greater than five years old at the time of hydraulic 

fracturing. Hydraulic fracturing or re-fracturing older wells has the potential to increase the 

frequency of casing or cement failures allowing unintended fluid migration into drinking water 

resources. 

Confirming well mechanical integrity can reduce the frequency of water quality impacts. Pressure 

testing the casing used for hydraulic fracturing prior to the job can help detect problematic 

casing—and provide an opportunity to make needed repairs if necessary. Monitoring the annular 

space behind the casing used for hydraulic fracturing during the hydraulic fracturing job can detect 

well component failure in real time and signal for an immediate shut down. Based on the EPA’s Well 

File Review study, casing pressure testing occurred at slightly less than 60% of the approximately 

28,500 hydraulic fracturing jobs represented in that time frame (primarily 2009-2010) and annulus 

monitoring took place during slightly more than 50% of these same jobs, implying these activities 

did not always occur (U.S. EPA, 2016c). It is unclear whether the frequency of these practices have

changed since this time period. 

Pathway #2: Fluid movement into a drinking water resource through the fracture network. 

The other potential pathway for fluid movement into a drinking water resource is through the 

fracture network. This could occur indirectly if the fracture network extends to a nearby well or its 

fracture network, or to another permeable subsurface feature, such as natural fractures or faults, 

which then allow the fluid to reach an underground drinking water resource. It could also occur

directly by the fracture network extending out of the production zone into a drinking water 

resource, or hydraulic fracturing into a drinking water resource itself.1 Key factors affecting the 

frequency of this pathway are the presence, distance, and condition of nearby wells; and the vertical 

 

1 Hereafter, fractures extending out of the production zone are referred to as “out-of-zone” fractures, consistent with 

Chapter 6.
Chapter 10 – Synthesis

10-18 

separation distance and the characteristics of the intervening rock between the production zone 

and the drinking water resource. 

Nearby wells (often called offset wells) can be a pathway for fluid movement, with hydraulic 

fracturing fluid from one production well moving through the subsurface and entering another

nearby oil or gas well or its fracture network. These events are commonly referred to as “well

communication events” or “frac hits.” The communication event might simply be registered as an

increase in pressure in the nearby well; yet there is also the possibility of damage to the nearby well

or its components, causing a surface spill or a subsurface release of fluids. The EPA’s Well File

Review found 1% of the wells represented in the study experienced a frac hit, and the EPA spills 

report identified 10 spills attributed to well communication events (U.S. EPA, 2015m, n). It is 

unknown whether any fluid reached a drinking water resource from these spills. Where active 

nearby wells exist, operators of those wells can shut them in temporarily during the nearby 

hydraulic fracturing to reduce the possibility of spills or damage to their wells, and therefore, the 

potential for drinking water resource contamination. 

The distance to the nearby well can affect the frequency of these communication events. In one 

study, the likelihood of a frac hit was less than 10% in hydraulically fractured wells more than 

4,000 ft (1,219 m) apart, while nearly 50% in wells less than 1,000 ft (300 m) apart (Ajani and 

Kelkar, 2012). Distance was measured from the mid-point of each horizontal lateral. Thus, the 

closer the nearby wells, the more likely a communication event. 

If nearby wells are in good condition and can withstand an increase in pressure, then an impact is 

unlikely to occur. However, if the nearby well is not able to withstand the pressure of the fluid, well 

components may fail and allow fluid to move into a drinking water resource. Because of this, nearby 

older or abandoned wells are of particular concern. In older wells near a hydraulic fracturing 

operation, plugs and cement may have degraded over time; in some cases, abandoned wells may 

never have been plugged properly. This can be a significant issue in areas with legacy (i.e., historic) 

oil and gas exploration. A Pennsylvania Department of Environmental Protection (PA DEP) report 

cited three cases where migration of natural gas had been caused by well communication events via

old, abandoned wells (PA DEP, 2009c). In Tioga County, Pennsylvania, following hydraulic 

fracturing of a shale gas well, an abandoned well nearby produced a 30 ft (9 m) geyser of brine and 

gas for more than a week (Dilmore et al., 2015). Various studies estimate the number of abandoned 

wells in the United States to be significant. For example, the Interstate Oil and Gas Compact 

Commission (IOGCC, 2008) estimates that approximately 1 million wells were drilled in the United 

States prior to a formal regulatory system, and the status and location of many of these wells are 

unknown. Hydraulic fracturing operators can reduce the possibility of impacts by identifying 

nearby wells, and if necessary, plugging or otherwise addressing deficiencies in these wells. 

If nearby wells serve as a pathway, fluid movement can bypass layers of intervening rock. In the 

absence of this pathway, however, vertical distance and the intervening rock between the 

production zone and the drinking water resource are factors affecting the possible movement of 

fluid into a drinking water resource. The extension of fractures out of the oil and/or gas production 

zone can—and does—occur. Examples have been reported in Greene County, Pennsylvania 

(Hammack et al., 2014); at the Killdeer site in Dunn County, North Dakota (U.S. EPA, 2015i); and in 
Chapter 10 – Synthesis

10-19 

other wells within the Bakken Shale (Arkadakskiy and Rostron, 2013; Arkadakskiy and Rostron,

2012; Peterman et al., 2012). In a study across several major shale formations, Davies et al. (2012)

found upward vertical fracture growth was often on the order of tens-to-hundreds of feet. One

percent of the fractures had a fracture height greater than 1,148 ft (350 m), and the maximum

fracture height among all of the data reported was 1,929 ft (588 m). This would suggest that

substantial vertical separation could preclude out-of-zone-fractures from directly reaching the

drinking water resource, although these measurements were only conducted in shale formations

and the extension of fractures is not the only way the drinking water resource could be

contaminated from out-of-zone fractures (see below). A modeling study also suggests fractures are

unlikely to extend from the production zone directly to a shallow drinking water resource in a deep

Marcellus-like environment (Kim and Moridis, 2015). 

Not all fracturing occurs, however, with substantial vertical separation between the production 

zone and the drinking water resource (Figure 10-3). The EPA’s Well File Review found that 20% of

wells used for hydraulic fracturing had less than 2,000 ft (600 m) between the shallowest point of

fracturing and the base of the protected groundwater resource (U.S. EPA, 2015n). In coalbed

methane (CBM) plays, typically shallower than shale gas plays, these separation distances can be

smaller. For example, in the Raton Basin of southern Colorado and northern New Mexico,

approximately 10% of CBM wells have less than 675 ft (206 m) of separation between the

production zone and the depth of local water wells. In certain areas of the basin, this distance is less

than 100 ft (31 m) (Watts, 2006). Many of these areas are shallower in depth, and fracture growth

has been shown to be primarily horizontal, rather than vertical, at less than 2,000 ft (600 m) from

the surface (Fisher and Warpinski, 2012). Nevertheless, the possibility of an out-of-zone fracture

reaching a drinking water resource is more likely in a setting with less vertical separation than with

more.

Even if an out-of-zone fracture does not extend into a drinking water resource, it could connect to 

other permeable subsurface features, such as natural fractures or faults, which could then connect

to a drinking water resource. Thus, properties of the intervening rock can also make this pathway 

more or less frequent or likely. For instance, in the Pavillion gas field in Wyoming, there are no

laterally-continuous confining layers to prevent upward movement of fluids into the groundwater

(Digiulio and Jackson, 2016). While flow of subsurface fluids generally tends to be downward, local 

areas of upward flow have been observed (Digiulio and Jackson, 2016).

There are cases of hydraulic fracturing without vertical separation between the drinking water

resource and the production zone (Figure 10-3). The co-location of the oil or gas formation with the 

drinking water resource is the factor affecting the frequency of an impact in these cases. Directly

fracturing into a drinking water resource causes an impact because it changes the quality of the

resource by introducing hydraulic fracturing fluids. The EPA’s Well File Review found an estimated

0.4% of the wells represented in the study had perforations used for hydraulic fracturing shallower

than the base of the protected groundwater resource, as reported by well operators (U.S. EPA, 

2015n). The EPA’s Well File Review did not examine these instances by formation type. This

practice may be concentrated in locations in western states, especially in CBM plays. Examples

include the Raton Basin in Colorado (U.S. EPA, 2015k), the San Juan Basin of Colorado and New
Chapter 10 – Synthesis

10-20 

Mexico (U.S. EPA, 2004a), and the Powder River Basin of Montana and Wyoming (Dahm et al., 2011; 

ALL Consulting, 2004; U.S. EPA, 2004a). This is a concern in the short term (should there be people 

using these drinking water resources currently) and the long term (if drought or other conditions 

necessitate the future use of these drinking water resources). For the most part in this chapter, we 

focused on factors which can be managed, changed, or used to identify areas to target monitoring 

efforts. In this situation, hydraulic fracturing directly into a drinking water resource would need to 

cease if it was decided the resulting impacts to drinking water resource quality were unacceptable.

Figure 10-3. Separation in measured depth between drinking water resources and 

hydraulically fractured intervals in wells.

In panel (a), the oil- and gas-bearing formation (dark gray) being hydraulically fractured is much deeper than the 

depth where drinking water resources (light blue) exist, and hence a comparatively large separation distance 

exists. In panel (b), there are two oil- and gas-bearing formations (dark gray and grayish blue) being hydraulically 

fractured. The shallower formation has no separation distance, because the water also contained in this formation

is a drinking water resource. Panel (b) also shows another subsurface drinking water zone at a shallower depth

(light blue). Multiple groundwater zones of varying qualities can exist between the production zone and the 

surface. These two panels depict end-member cases of separation distance: from large separation distances to no 

separation distance. The graph in panel (c) illustrates the distribution of separation distances among the 

approximately 23,000 oil and gas production wells hydraulically fractured by nine service companies between 2009 

and 2010 (U.S. EPA, 2015n). Error bars in the panel (c) display 95% confidence intervals.
Chapter 10 – Synthesis

10-21 

Lastly, the presence of gas, as opposed to liquids, in the subsurface may be a factor affecting the 

frequency of impacts from fluid movement via defects or deficiencies in the well (pathway #1), or 

through the fracture network (pathway #2). The low density of gas compared to liquids makes it 

buoyant, which creates an upward drive toward the surface. Thus, gas found in the subsurface, such 

as methane, can exploit pathways in a well (such as along a well lacking mechanical integrity), or in 

the surrounding rock (such as induced or naturally occurring fractures). If a pathway exists and gas 

is present, it can reach groundwater used for drinking. Consequently, gases could be more likely to 

contaminate drinking water resources than liquids (Li et al., 2016a). 

10.1.3.2 Severity 

The well injection chapter (Chapter 6) focused primarily on the potential for impacts to occur and 

factors affecting frequency. By contrast, we have little-to-no information on factors affecting the 

severity of impacts for this stage of the hydraulic fracturing water cycle. Severity would likely be 

affected by the chemical composition of the fluid entering the drinking water resource; the volume 

of the fluid; the duration in which that volume is delivered; and the concentration of the fluid and 

its specific components, among other factors. Logically, the relatively simple pathway of a 

mechanical integrity failure might result in the highest fluid volume delivered to a drinking water 

resource over a short period of time—e.g., contamination of water wells in Bainbridge Township, 

Ohio. By contrast, fluid movement through a fracture network, then through the intervening rock, 

and finally into a drinking water resource may take a longer time and deliver a comparatively lower 

volume. Even in this case, however, the impacts could still be severe if the fluid movement was to go 

undetected and unaddressed. 

10.1.4 Wastewater Disposal and Reuse 

The last stage of the hydraulic fracturing water cycle is wastewater disposal and reuse. Produced 

water from hydraulically fractured oil or gas production wells is managed predominantly through 

disposal in underground Class II wells. Secondarily, it is disposed of via other practices, such as 

discharge to surface waters or disposal in pits or evaporation ponds, or reused in other hydraulic 

fracturing operations. Activities in the wastewater disposal and reuse stage of the hydraulic 

fracturing water cycle can impact drinking water resources in some instances. Two such activities 

are: the discharge of inadequately treated wastewater to surface water, and the storage or disposal 

of wastewater in unlined pits or impoundments leading to contamination of surface water or 

groundwater. In this section, we address factors increasing or decreasing the frequency or severity 

of impacts from these activities. As in the water acquisition section, we combine our discussion of 

frequency and severity here. 

10.1.4.1 Frequency and Severity

Discharge of inadequately treated wastewater has impacted surface water. The quality of the 

wastewater discharged is a factor affecting the frequency and severity of impacts. This factor is a 

function of the chemical characteristics of the wastewater prior to treatment (i.e., the composition 

and concentration of chemicals in the wastewater) and the efficacy of the treatment process. The 

pre-2011 treatment of Marcellus wastewater in Pennsylvania illustrates this combination. In 
Chapter 10 – Synthesis

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Pennsylvania before 2011, wastewater from shale gas operations was treated at centralized waste 

treatment facilities (CWTs) and publicly owned treatment works (POTWs). The POTWs and some 

CWTs at the time were not equipped to adequately treat high TDS wastewater. This resulted in 

wastewater discharges containing elevated levels of TDS, including bromide and iodide, to surface 

waters. 

The elevated levels of TDS raised concerns about the formation of disinfection byproducts (DBPs) 

after treatment at downstream drinking water facilities. Disinfection byproducts are formed when 

organic material comes in contact with disinfectants (e.g., chlorine, chloramine, chlorine dioxide or 

ozone). Many DBPs have long-term health effects including an increased risk of cancer, anemia, 

liver and kidney effects, and central nervous system effects. Of particular concern are DBPs formed 

in the presence of bromide or iodide, which are considered particularly toxic. Management of DBPs 

places a burden on downstream drinking water utilities. Concerns regarding elevated TDS (in 

particular high bromide) and the potential for formation of DBPs led the PA DEP to take steps in 

2010 and 2011 to route Marcellus Shale wastewater away from POTWs and CWTs (that could not 

treat for TDS) to alternate options such as disposal via injection wells, on-site reuse, or reuse after 

limited treatment at CWTs. By 2014, only a small percentage (approximately less than 1%) of 

Marcellus wastewater went to CWTs permitted to discharge to surface waters (Figure 10-1). 

Additionally, the new EPA pretreatment standards prohibit oil and gas operators from sending 

unconventional oil and gas wastewater directly to POTWs (U.S. EPA, 2016d). 

The combination of wastewater composition and inadequate treatment have also resulted in the 

discharge of other constituents such as barium, strontium, and radium into surface waters in 

Pennsylvania. Marcellus Shale wastewater contains radium, naturally occurring in the subsurface 

formation. Radium has been found in stream sediments at discharge points for POTWs and CWT 

facilities that have accepted Marcellus Shale wastewater. The ratio of radium isotopes (radium-228 

to radium-226) in these sediments is consistent with ratios in Marcellus Shale wastewater (Warner 

et al., 2013a). Radium-226, with a half-life of approximately 1,600 years, causes long-term 

contamination. The practice of management of wastewaters via POTWs and CWTs without TDS 

removal has declined, yet it remains uncertain whether the discharge of radionuclides to surface 

waters from the oil and gas industry in Pennsylvania has ceased entirely (PA DEP, 2015b). 

The storage or disposal of wastewater in pits or impoundments can also lead to contamination of 

surface water or groundwater resources. This can occur via surface spills or overflows. It can also 

occur via infiltration into the soil and percolation to groundwater through the pit itself. Whether 

the pit or impoundment is lined is an important factor affecting the frequency and severity of 

impacts on groundwater due to subsurface leaching. Historically, unlined pits have been used to 

dispose of wastewater via percolation (or evaporation). While this practice has been banned in 

most states, it is allowed in certain locations or instances (e.g., storage of wastewater, but not 

disposal) as of July 2016. Even where prohibited, unpermitted unlined disposal or storage pits exist.

For example, approximately 1,000 unlined storage or disposal pits of oil and gas wastewater are 

located in the Central Valley Region of California (California State Water Resources Control Board, 

2016; Esser et al., 2015). Of these, approximately 60% were still active as of July 2016, and roughly 

20% of those pits lacked permits (CA Water Board, 2016). 
Chapter 10 – Synthesis

10-23 

Unlined pits have been shown to cause contamination of drinking water resources. The presence of 

BTEX (benzene, toluene, ethylbenzene, and xylenes) and other organics in groundwater are linked 

to pits in California and New Mexico (California Regional Water Quality Control Board Central 

Valley Region, 2015; Sumi, 2004; Eiceman, 1986). Groundwater impacts downgradient of an 

unlined pit in Oklahoma included high salinity (3500-25,600 mg/L) and the presence of volatile 

organic compounds (Kharaka et al., 2002). Impacts can also occur in the case of disposal of 

relatively low TDS wastewater (Healy et al., 2011; Healy et al., 2008). For example, a CBM 

wastewater impoundment in the Powder River Basin of Wyoming resulted in high concentrations 

of TDS, chloride, nitrate, and selenium in the groundwater (Healy et al., 2011; Healy et al., 2008). 

Total dissolved solids exceeded 100,000 mg/L in one groundwater sample, despite the much lower 

concentrations (2,300 mg/L) in the wastewater being discharged (Healy et al., 2008). Most of the 

solutes found in the groundwater did not originate with the CBM wastewater, but rather resulted 

from dissolution of previously existing salts and minerals in the subsurface. Lining pits or using 

closed-loop systems (i.e., tanks) can decrease the frequency of such impacts. 

10.1.5 Summary 

In the above section, we synthesized the information in this assessment by discussing factors 

increasing or decreasing the frequency or severity of impacts from activities in the hydraulic 

fracturing water cycle. We focused particularly on factors that could be managed, changed, or used 

to identify locations for additional monitoring or alteration of practices. Based on the information 

reviewed, we conclude the following combinations of activities and factors are more likely than 

others to result in more frequent or more severe impacts:

• Water withdrawals for hydraulic fracturing in times or areas of low water availability, 

particularly in areas with limited or declining groundwater resources; 

• Spills during the management of hydraulic fracturing fluids and chemicals or produced 

water that result in large volumes or high concentrations of chemicals reaching 

groundwater resources; 

• Injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, 

allowing gases or liquids to move to groundwater resources;

• Injection of hydraulic fracturing fluids directly into groundwater resources; 

• Discharge of inadequately treated hydraulic fracturing wastewater to surface water 

resources; and

• Disposal or storage of hydraulic fracturing wastewater in unlined pits, resulting in 

contamination of groundwater resources.

Conversely, the scientific literature and data provide evidence that certain factors can reduce the 

frequency or severity of impacts. Based on the information reviewed in this assessment, we 

conclude the following factors are likely to reduce the frequency or severity of impacts:

• Passby flows, or low-flow criteria, for surface water withdrawals, and the use of brackish 

groundwater or reused wastewater as substitutes for fresh water withdrawals; 
Chapter 10 – Synthesis

10-24 

• Implementation of spill prevention and response measures;

• Design and placement of well casing and cement able to withstand the stresses imposed by 

hydraulic fracturing (including identifying the depth of the drinking water resource at the 

point of drilling, and setting and cementing casings through the entire drinking water 

resource); 

• Confirming mechanical integrity of oil and gas wells prior to, during, and after hydraulic 

fracturing, and correcting deficiencies if necessary;

• Identification of active or abandoned wells near hydraulic fracturing operations and, if 

necessary, adjustment of the operations to minimize well-to-well communication and/or 

plugging improperly abandoned wells;

• The use of treatment technologies to remove TDS, and other constituents, such as radium, 

when present prior to discharge; and

• Storage of wastewater in lined pits or the use of closed-loop systems instead of pits.

The above factors are not the only factors that can reduce the frequency or severity of impacts, yet 

are the ones most emphasized by the information reviewed for this assessment. It should be noted 

that the above factors reduce, but do not completely eliminate, the possibility of an impact 

occurring. In the case of hydraulic fracturing directly into a drinking water resource or disposal of 

wastewater via unlined pits, we did not identify factors which could reduce the frequency or 

severity of impacts, besides restricting the activity itself. 

10.2 Uncertainties and Data Gaps

In this assessment, we identified impacts on drinking water resources in all stages of the hydraulic 

fracturing water cycle and described the factors affecting the frequency or severity of impacts. The 

major conclusions presented above (in Section 10.2.5) are the strongest conclusions based on data 

and information synthesized for the assessment. 

There were also many areas within the assessment for which strong conclusions could not be 

reached. This was because of the lack of publicly available data and large uncertainties in available 

sources of information. Below, we provide perspective on what data gaps and uncertainties 

prevented us from drawing additional strong conclusions about the potential for impacts and/or 

the factors affecting the frequency or severity of impacts.

We encountered uncertainties associated with, and gaps in, aggregated, publicly accessible 

information about both activities in the hydraulic fracturing water cycle and groundwater data. In 

general, comprehensive information on the location of activities in the hydraulic fracturing water 

cycle is lacking, either because it is not collected, not publicly-available, or prohibitively difficult to 

aggregate. Thus, we lacked complete information on the geographic locations of well sites (both 

new and existing) where the chemical mixing, well injection, and produced water handling stages 

take place; the depth(s) of zones that have been hydraulically fractured in these wells; where water 

is being acquired (i.e., the source water) for hydraulic fracturing; and where hydraulic fracturing 

wastewater is treated and/or disposed. FracFocus provided data on well locations, and water and 
Chapter 10 – Synthesis

10-25 

other chemicals used at those locations. However, reporting to FracFocus at the time period studied 

was not always required, making it difficult to determine the completeness or representativeness of 

the information. 

In addition, there are uncertainties about where groundwater resources are located. This includes 

the thickness of the resource, from its top to its lowest depth, and its relation to the shallowest 

depth where hydraulic fracturing occurred. If comprehensive data about the locations of both 

drinking water resources and activities in the hydraulic fracturing water cycle were available, it 

would have been possible to more completely identify areas in the United States where hydraulic 

fracturing-related activities and drinking water resources overlap. 

There are also uncertainties and data gaps related to chemicals used in hydraulic fracturing fluid 

and those detected in produced water. Some chemicals and chemical mixtures remain undisclosed 

because of confidential business information (CBI) claims. Well operators claimed at least one 

chemical as CBI at more than 70% of disclosures reported to FracFocus between 2011 and early 

2013. Data suggests this practice is increasing. Konschnik and Dayalu (2016) reported that 92% of 

FracFocus disclosures submitted between approximately March 2011 and April 2015 included at 

least one chemical claimed as confidential. When chemicals are claimed as CBI, there is no public 

means of accessing information on these chemicals. Furthermore, many of the chemicals and 

chemical mixtures disclosed, or those detected in produced water, lack information on properties 

affecting their movement, persistence, and toxicity in the environment should they be spilled. 

Better information on these chemicals would allow for a more robust evaluation of potential human 

health hazards posed, and thus a better understanding about the severity of impacts should the 

chemicals reach drinking water resources. 

In places where we know hydraulic fracturing water cycle activities have occurred, data to assess 

impacts are often either not collected or are not publicly available in accessible forms. Specifically, 

local water quality monitoring and well mechanical integrity integrity data are not consistently 

collected or readily available. In particular, sufficient baseline data on local water quality are 

needed to quantify any changes post-hydraulic fracturing. There are exceptions to this, for example, 

the state of California recently implemented a plan to make water quality monitoring information 

public (Text Box 10-1). In general, however, the limited amount of data collected before, during, 

and after hydraulic fracturing activities and made public, reduces the ability to determine whether 

hydraulic fracturing affected drinking water resources. 

Text Box 10-1. Hydraulic Fracturing and Groundwater Quality Monitoring in California.

In July 2015, the California Water Resources Control Board adopted Senate Bill 4 (SB4), Model Criteria for 

Groundwater Monitoring in Areas of Oil and Gas Well Stimulation. This resolution directed the establishment of 

a “comprehensive regulatory groundwater monitoring and oversight program...in order to assess the 

potential effects of well stimulation treatment activities on the state’s groundwater resources” (California 

State Water Resources Control Board, 2015). The adoption of SB4 concluded a multi-year process, which 

incorporated stakeholder engagement, review by the public, and consultation with an expert scientific panel.

(Text Box 10-1 is continued on the following page.)
Chapter 10 – Synthesis

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Text Box 10-1 (continued). Hydraulic Fracturing and Groundwater Quality Monitoring in 

California.

The recommendations of the expert panel informed the creation and implementation of SB4 with respect to 

criteria “to be used for assessment, sampling, analytical testing, and reporting of water quality associated 

with oil and gas well stimulation activities” (Esser et al., 2015). 

The resolution requires two different scales of groundwater monitoring for different purposes. First, it 

requires well-by-well (also called “area-specific”) groundwater monitoring by well operators. This includes 

groundwater monitoring conducted for all hydraulic fracturing projects initiated after July 2015. Each oil or 

gas production well operator must submit a design and timeline for monitoring groundwater resources in 

proximity to its proposed well. The State Water Resources Control Board approves the monitoring plan

before hydraulic fracturing can proceed. The groundwater monitoring plan must include:

• The installation of monitoring wells within 0.5 miles of the wellhead. At least one monitoring well must 

be upgradient of the production well and two monitoring wells must be downgradient. Should the 

production well penetrate more than one protected groundwater resource (as defined by the resolution), 

monitoring wells must facilitate sampling of at least one that is shallow and one that is deep.

• A monitoring timeline that includes sampling prior to production well construction and hydraulic 

fracturing, as well as semi-annual sampling after completion.

• A list of water quality parameters and constituents to be monitored, including TDS, specific metals, and 

specific organic compounds. 

The area-specific monitoring requirements also include submission of information by well operators about 

geologic and human-made features in the subsurface that could serve as pathways for impacts to 

groundwater, aspects of production well construction, and hydraulic fracturing fluid composition. 

Second, a regional groundwater monitoring program will document trends in baseline water quality and 

locate protected groundwater state-wide. In addition to monitoring for trends in groundwater quality related 

to activities at well sites, it will also be designed to detect trends related to impacts from wastewater disposal 

practices.

All data from the monitoring programs will be publicly accessible in a state-maintained database. The 

database is intended to support public health, scientific, and academic needs, as well as future “investigation, 

assessment, and research relevant to oil and gas development impacts on groundwater quality” (Esser et al., 

2015). 

Together, the data and information collected and made publicly available as part of the area-specific and 

regional groundwater monitoring in California will help fill data gaps identified in this section of the 

assessment by locating groundwater resources, monitoring drinking water resources at spatial and temporal 

scales relevant for detecting impacts from activities in the hydraulic fracturing water cycle, and distinguishing 

impacts from hydraulic fracturing activities from the impacts of other potential sources.

In the cases where effects are suspected, it is often difficult to separate the potential effects of 

hydraulic fracturing activities from effects of broader oil and gas industry activities and other 

industries or causes. The use of long-lasting, mobile tracer chemicals added to hydraulic fracturing 

fluids to monitor for impacts has been proposed (Kurose, 2014), but has received relatively little 

attention in the scientific literature as of mid-2016. Instead, measured changes in water quality 

parameters can be associated with, but not necessarily diagnostic of, impacts from hydraulic 

fracturing activities. For instance, measurable changes in methane levels, TDS, ratios of geochemical 
Chapter 10 – Synthesis

10-27 

constituents, and isotopic ratios might suggest impacts from hydraulic fracturing but could also be 

from other sources, either natural or anthropogenic. To try to assign a cause, these measurements 

often have to be followed with further collection of evidence supporting or refuting hydraulic 

fracturing activities as the cause of the changes. (See Text Box 10-2 for discussion of causal 

assessments.) 

Text Box 10-2. Causal Assessment and Hydraulic Fracturing Water Cycle Activities.

A number of recent studies have conducted regional-scale assessments of trends in water quality in areas 

with hydraulic fracturing activity, showing either no trend or trends linked temporally or spatially with 

hydraulic fracturing (Burton et al., 2016; Hildenbrand et al., 2016; Hildenbrand et al., 2015; Siegel et al., 2015; 

Darrah et al., 2014; Fontenot et al., 2013; Warner et al., 2013b) Regional assessments can be important for 

integrating information over broader scales, and for posing hypotheses about how hydraulic fracturing water 

cycle activities may impact drinking water resources. Oftentimes, however, activities in the hydraulic 

fracturing water cycle are merely one of several possible causes of an observed change in water quality or 

quantity at a specific site. In this case, more thorough, site-specific investigations are often necessary. Causal 

assessment (also called causal analysis) involves collecting multiple kinds of evidence to determine which of 

several possible causes of contamination is most likely. 

Causal assessment requires several steps. First, the spatial and temporal scope of the issue is defined, 

including a description of all the possible causes of an observed impact, in this case the change in quality or 

quantity of a drinking water resource. Once this is done, evidence is collected and assembled to support or 

refute the potential causes. Evidence indicating how a potential cause and an observed effect are related in

time can help support or refute potential causes. Other kinds of evidence can also be useful in identifying a 

cause, including: determining whether the composition and volume of a leaked, spilled, or treated and 

discharged fluid are capable of causing observed impacts on water quality; and determining whether a 

physical pathway between a well or well site exists by measuring the mechanical integrity of hydraulically 

fractured wells and/or establishing the presence/absence of a contaminant plume. 

Ideally, the evidence helps exclude possible causes of the reported contamination, narrowing down the list of 

potential causes to a single cause. Causal assessments can take a long time to complete and can require a lot 

of resources and expertise. In some situations, available data and resources are simply not sufficient to 

definitively identify the cause. Nevertheless, causal assessments conducted in a consistent and transparent 

way can help enable the identification of the likely cause(s) of contamination of drinking water resources. 

The retrospective case studies conducted by the EPA under the Study Plan are examples of scientific 

investigations using a multiple lines of evidence approach consistent with the principles of causal assessment 

(U.S. EPA, 2015i, j, l, 2014f, g). These case studies were cited throughout this report. For instance, as noted 

previously, the Killdeer, North Dakota case study found that an inner string of casing burst during hydraulic 

fracturing of an oil well, resulting in a release of hydraulic fracturing fluids and formation fluids that impacted 

a groundwater resource (U.S. EPA, 2015i). Following an analysis of potential sources, the only potential 

source consistent with the conditions observed was the ruptured well (U.S. EPA, 2015i). 

Regardless of whether a single cause can be determined, actions can still be taken to mitigate one or more 

potential causes of contamination. Information gained once the suspected activity has been halted or at least 

reduced could elucidate whether hydraulic fracturing operations are more or less likely to have been the 

source of the contamination.

Many members of the public are interested in understanding the national frequency of impacts to 

drinking water resources from activities across the entire hydraulic fracturing water cycle. Because 
Chapter 10 – Synthesis

10-28 

of the significant data gaps and uncertainties in the available data, it was not possible to estimate 

the national frequency of impacts to drinking water resources from activities in the hydraulic 

fracturing water cycle collectively. We were, however, able to estimate impact frequencies in some, 

limited cases within the larger hydraulic fracturing water cycle (i.e., spills of hydraulic fracturing 

fluids or produced water, and mechanical integrity failures). These more specific estimates had a 

high degree of uncertainty, but were the best estimates that could be provided with the data and 

literature currently available. 

Finally, it should be recognized that this assessment is a snapshot in time. Our understanding of the 

factors affecting the frequency or severity of impacts may change in the future as industry practices 

evolve and new information becomes available.

10.3 Use of this Assessment

This assessment contributes to the understanding of the potential impacts to drinking water 

resources by activities in the hydraulic fracturing water cycle and the factors influencing those 

impacts. The scientific information presented can be used by federal, tribal, state, and local officials; 

industry; and the public to better understand and address vulnerabilities of drinking water 

resources to activities in the hydraulic fracturing water cycle. 

The uncertainties and data gaps identified throughout this assessment could be used to identify 

future data collection efforts. Data collection efforts could include, for example, surface water and 

groundwater monitoring programs in areas with hydraulically fractured oil and gas production 

wells; collection and the public dissemination of data on the condition of hydraulically fractured 

wells; or targeted research programs to better characterize the environmental fate and transport 

and human health hazards associated with chemicals in the hydraulic fracturing water cycle. Data 

collected and analyzed through new data collection efforts may identify new factors increasing or 

decreasing the frequency or severity of impacts. 

In the near term, decision-makers could focus their attention on the combinations of activities and 

factors that we conclude are more likely than others to result in more frequent or more severe 

impacts (Section 10.2.5). By focusing attention on the above combinations, impacts to drinking 

water resources from activities in the hydraulic fracturing water cycle can be prevented or reduced. 

Overall, the practice of hydraulic fracturing is expanding and continues to change. Oil and gas 

production associated with hydraulic fracturing was insignificant in 2000, but by 2015 it accounted 

for an estimated 51% of U.S. oil production and 67% of U.S. gas production (EIA, 2016c, d). The 

number of wells drilled and hydraulically fractured is likely to continue to increase in the coming 

decades (EIA, 2014a). The work of evaluating potential impacts from combinations of activities and 

factors in the hydraulic fracturing water cycle will need to keep pace with this industry and as new 

scientific studies are produced. This assessment provides a foundation for those efforts, while 

offering information to support the reduction of current vulnerabilities of drinking water resources. 
Chapter 11 – References

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Chapter 11 – References

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Front cover (top): Illustrations of activities in the hydraulic fracturing water cycle. 

From left to right: Water Acquisition, Chemical Mixing, Well Injection, Produced Water Handling, 

and Wastewater Disposal and Reuse.

Front cover (bottom): Aerial photographs of hydraulic fracturing activities. 

Left: Near Williston, North Dakota. Image ©J Henry Fair / Flights provided by LightHawk. 

Right: Springville Township, Pennsylvania. Image ©J Henry Fair / Flights provided by LightHawk.

Back cover: Top left: DOE/NETL. All other images courtesy of the U.S. EPA.

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