EPA-600-R-16-236Fb 

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

Appendices

Office of Research and Development

Washington, DC

EPA-600-R-16-236Fb 

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 

Appendices 

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: U.S. EPA (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 - Appendices. Office of Research and Development, Washington, DC. 

EPA/600/R-16/236Fb. 
ii

Contents 

List of Tables ........................................................................................................................................................... v

List of Figures .........................................................................................................................................................ix

List of Text Boxes ................................................................................................................................................. xi

Appendix A. The EPA's Study of the Potential Impacts of Hydraulic Fracturing for Oil and 

Gas on Drinking Water Resources ...............................................................................................................A-1

A.1. The EPA’s Hydraulic Fracturing Study Publications Cited in This Assessment.........................A-5

A.2. Answers to the Secondary Research Questions ......................................................................................A-7

A.2.1. Water Acquisition ....................................................................................................................................A-9

A.2.2. Chemical Mixing .................................................................................................................................... A-11

A.2.3. Well Injection .......................................................................................................................................... A-14

A.2.4. Produced Water Handling ................................................................................................................. A-15

A.2.5. Wastewater Disposal and Reuse .................................................................................................... A-18

Appendix B. Water Acquisition Supplemental Information ..............................................................B-1

B.1. Supplemental Tables .......................................................................................................................................... B-3

B.2. Supplemental Discussion: Potential for Water Acquisition Impacts by Location .................. B-53

B.2.1. Oklahoma and Kansas ......................................................................................................................... B-53

B.2.2. Utah, New Mexico, and California .................................................................................................. B-55

Appendix C. Chemical Mixing Supplemental Information .................................................................. C-1

C.1. Most Frequently Reported Chemicals in Gas- and Oil-Producing Wells ....................................... C-3

C.2. Most Frequently Reported Chemicals for Each State ........................................................................... C-7

C.3. Estimating Volume and Mass for 74 Chemicals Reported in Disclosures in the EPA 

FracFocus 1.0 Project Database ..............................................................................................................................C-22

C.4. Estimating Spill Rates Based on State Spill Report Data ...................................................................C-36

C.5. Selected Physicochemical Properties of Organic Chemicals Used in Hydraulic 

Fracturing Fluids ...........................................................................................................................................................C-38

C.6. Details on the EPI (Estimation Programs Interface) SuiteTM............................................................C-66

C.7. Top 20 lists for most mobile and least mobile chemicals .................................................................C-67

Appendix D. Well Injection Supplemental Information ......................................................................D-1

D.1. Design Goals for Well Construction .............................................................................................................D-3

D.2. Well Components .................................................................................................................................................D-3

D.2.1. Casing ............................................................................................................................................................D-4

D.2.2. Cement ..........................................................................................................................................................D-6

D.3. Well Completions ..............................................................................................................................................D-12

D.4. Mechanical Integrity Testing .......................................................................................................................D-13

D.4.1. Internal Mechanical Integrity ..........................................................................................................D-14

D.4.2. External Mechanical Integrity .........................................................................................................D-15
iii

Appendix E. Produced Water Handling Supplemental Information ............................................... E-1

E.1. Specific Definitions of the Terms “Produced Water” and “Flowback”........................................... E-3

E.1.1. Produced Water ........................................................................................................................................ E-3

E.1.2. Flowback ..................................................................................................................................................... E-3

E.2. Produced Water Volumes ................................................................................................................................. E-3

E.2.1. Summary of Results from Produced Water Studies ................................................................E-13

E.3. Chemical Content of Produced Water .......................................................................................................E-17

E.3.1. General Water Quality Parameters .................................................................................................E-17

E.3.2. Salinity and Inorganics ........................................................................................................................E-22

E.3.3. Metals and Metalloids ..........................................................................................................................E-25

E.3.4. Naturally Occurring Radioactive Material (NORM) and Technically Enhanced 

Naturally Occurring Radioactive Material (TENORM) .............................................................................E-31

E.3.5. Organics .....................................................................................................................................................E-34

E.3.6. Chemical Reactions ...............................................................................................................................E-57

E.3.7. Microbial Community Processes and Content ...........................................................................E-58

E.4. Produced Water Content Spatial Trends .................................................................................................E-60

E.4.1. Variability between Plays of the Same Rock Type ...................................................................E-60

E.4.2. Local Variability ......................................................................................................................................E-62

E.5. North Dakota Spill Analysis ...........................................................................................................................E-62

E.5.1. Materials and Methods ........................................................................................................................E-62

E.5.2. Results ........................................................................................................................................................E-64

E.5.3. Summary of Additional Studies on Spills .....................................................................................E-72

E.6. Evaluation of Impacts ......................................................................................................................................E-73

E.7. Transport Properties........................................................................................................................................E-78

E.8. Example Calculation for Roadway Transport ........................................................................................E-79

E.8.1. Estimation of Transport Distance ...................................................................................................E-79

E.8.2. Estimation of Wastewater Volumes ...............................................................................................E-80

E.8.3. Estimation of Roadway Accidents ...................................................................................................E-80

E.8.4. Estimation of Material Release Rates in Crashes ......................................................................E-81

E.8.5. Estimation of Volume Released in Accidents .............................................................................E-81

Appendix F. Wastewater Disposal and Reuse Supplemental Information ................................... F-1

F.1. Estimates of Wastewater Production in Regions where Hydraulic Fracturing is 

Occurring ............................................................................................................................................................................ F-3

F.2. Overview of Treatment Processes for Treating Hydraulic Fracturing Wastewater ................ F-9

F.2.1. Basic Treatment........................................................................................................................................ F-9

F.2.2. Advanced Treatment ............................................................................................................................F-11

F.3. Treatment Technology Removal Capabilities ........................................................................................F-16

F.4. Treatment for Constituents of Concern ....................................................................................................F-23

F.5. Centralized Waste Treatment Facilities and Waste Management Options ...............................F-33

F.5.1. Design of Treatment Trains for CWTs ...........................................................................................F-33
iv

F.5.2. Discharge Options for CWTs ............................................................................................................. F-41

F.6. Water Reuse ........................................................................................................................................................ F-41

F.6.1. Factors in Considering Reuse ...........................................................................................................F-42

F.6.2. Water Quality for Reuse ......................................................................................................................F-43

F.7. Hydraulic Fracturing Wastewater Impacts on POTWs ......................................................................F-45

F.8. Hydraulic Fracturing Wastewater and Disinfection Byproducts ...................................................F-46

F.8.1. Disinfection Byproducts ......................................................................................................................F-46

F.8.2. Studies Modeling Bromide in Receiving Waters from CWT Effluents .............................F-47

Appendix G. Identification and Hazard Evaluation of Chemicals across the Hydraulic 

Fracturing Water Cycle Supplemental Information ..............................................................................G-1

G.1. Introduction ...........................................................................................................................................................G-3

G.2. Criteria for Selection and Inclusion of Reference Value (RfV), Oral Slope Factor (OSF), 

and Qualitative Cancer Classification Data Sources .........................................................................................G-3

G.2.1. Included Sources ......................................................................................................................................G-5

G.2.2. Excluded Sources .....................................................................................................................................G-5

G.3. Glossary of Toxicity Value Terminology ....................................................................................................G-6

G.4. Additional Tools for Hazard Evaluation .................................................................................................. G-10

G.4.1. Threshold of Toxicological Concern (TTC) ................................................................................ G-10

G.4.2. Organisation for Economic Co-operation and Development (OECD) Quantitative 

Structure-Activity Relationship (QSAR) Toolbox ...................................................................................... G-11

G.4.3. Application of Data from High Throughput Screening Assays ........................................... G-11

Appendix H. Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced 

Water .....................................................................................................................................................................H-1

H.1. Supplemental Tables and Information .......................................................................................................H-3

Appendix I. Unit Conversions .........................................................................................................................I-1

Appendix J. Glossary ..........................................................................................................................................J-1

J.1. Introduction ............................................................................................................................................................ J-3

J.2. Glossary Terms and Definitions.......................................................................................................................J-3

Appendix K. Appendix References ..............................................................................................................K-1
v 

List of Tables 

Table A-1. Titles, descriptions, and citations for the EPA’s hydraulic fracturing study 

publications cited in this assessment. .........................................................................................................................A-5

Table B-1. Average annual hydraulic fracturing water use and consumption in 2011 and 

2012 compared to total annual water use and consumption in 2010 by state. ........................................B-3

Table B-2. Average annual hydraulic fracturing water use and consumption in 2011 and 

2012 compared to total annual water use and consumption in 2010 by county. ....................................B-5

Table B-3. Comparison of water use per well estimates from the EPA FracFocus 1.0 project 

database (U.S. EPA, 2015c) and literature sources. ........................................................................................... B-21

Table B-4. Comparison of well counts from the EPA FracFocus 1.0 project database (U.S. 

EPA, 2015c) and state databases for North Dakota, Pennsylvania, and West Virginia. ...................... B-22

Table B-5. Water use per hydraulically fractured well as reported in the EPA FracFocus 1.0 

project database (U.S. EPA, 2015c) by state and basin, covering the time period of January 

2011 through February 2013. ..................................................................................................................................... B-23

Table B-6. Estimated percent domestic use water from groundwater and self-supplied by 

county in 2010. .................................................................................................................................................................. B-27

Table B-7. Projected hydraulic fracturing water use by Texas counties between 2015 and 

2060, expressed as a percentage of 2010 total county water use................................................................ B-41

Table C-1. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0 

project database for gas-producing wells, with the number of disclosures (for reported 

chemicals), percentage of disclosures, and the median maximum concentration (% by mass) 

of that chemical in hydraulic fracturing fluid. .........................................................................................................C-3

Table C-2. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0 

project database for oil-producing wells, with the number of disclosures (for reported 

chemicals), percentage of disclosures, and the median maximum concentration (% by mass) 

of that chemical in hydraulic fracturing fluid. .........................................................................................................C-5

Table C-3. (a) Chemicals most frequently reported in disclosures in the EPA FracFocus 1.0 

project database for each state and number (and percentage) of disclosures where a 

chemical is reported for that state, Alabama to Montana; (b) Chemicals most frequently 

reported in disclosures in the EPA FracFocus 1.0 project database for each state and 

number (and percentage) of disclosures where a chemical is reported for that state, New 

Mexico to Wyoming ............................................................................................................................................................ C-7

Table C-4. Estimated mean, median, 5th percentile, and 95th percentile volumes in gallons for 

chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, 

where density information was available. ............................................................................................................. C-24

Table C-5. Estimated mean, median, 5th percentile, and 95th percentile volumes in liters for 

chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, 

where density information was available. ............................................................................................................. C-27

Table C-6. Calculated mean, median, 5th percentile, and 95th percentile chemical masses 

reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, where 

density information was available. ........................................................................................................................... C-30
vi

Table C-7. Associated chemical densities and references used to calculate chemical mass 

and estimate chemical volume. ................................................................................................................................... C-33

Table C-8. Estimations of spill rates.......................................................................................................................... C-37

Table C-9. Selected physicochemical properties of organic chemicals reported as used in 

hydraulic fracturing fluids. ........................................................................................................................................... C-38

Table C-10. Ranking of the 20 most mobile organic chemicals, as determined by the largest 

log Kow, with CASRN, percent of wells where the chemical is reported from January 1, 2011 

to February 28, 2013 (U.S. EPA, 2015c), and physicochemical properties (log Kow, solubility, 

and Henry’s law constant) as estimated by EPI SuiteTM. ................................................................................... C-68

Table C-11. Ranking of the 20 least mobile organic chemicals, as determined by the largest 

log Kow, with CASRN, percent of wells where the chemical is reported from January 1, 2011 

to February 28, 2013 (U.S. EPA, 2015c), and physicochemical properties (log Kow, 

solubility, and Henry’s law constant) as estimated by EPI SuiteTM............................................................... C-70

Table E-1. Produced water characteristics for wells by basin, formation, and resource type. ........... E-4

Table E-2. Reported concentrations of general water quality parameters in produced water 

for unconventional shale and tight formations, presented as: average (minimum-maximum) 

or median (minimum-maximum). ............................................................................................................................. E-18

Table E-3. Reported concentrations of general water quality parameters in produced water 

for coalbed basins, presented as: average (minimum-maximum). .............................................................. E-21

Table E-4. Reported concentrations (mg/L) of inorganic constituents contributing to salinity 

in produced water from unconventional reservoirs (including shale and tight formations), 

presented as: average (minimum-maximum) or median (minimum-maximum). ................................ E-23

Table E-5. Reported concentrations (mg/L) of inorganic constituents contributing to salinity 

in produced water for coalbed methane basins, presented as: average (minimummaximum) ........................................................................................................................................................................... E-25

Table E-6. Reported concentrations (mg/L) of metals and metalloids from produced water 

from unconventional reservoirs (including shale and tight formations), presented as: 

average (minimum-maximum) or median (minimum-maximum). ............................................................. E-27

Table E-7. Reported concentrations (mg/L) of metals and metalloids from produced water 

from coalbed methane, presented as: average (minimum-maximum). ..................................................... E-30

Table E-8. Reported concentrations (in pCi/L) of radioactive constituents in produced water 

in unconventional reservoirs (including shale and tight sandstones), presented as: average 

(minimum-maximum) or median (minimum-maximum). .............................................................................. E-32

Table E-9. Concentrations of select organic parameters in produced water from 

unconventional reservoirs (including shale, a tight formation, and coalbed methane), 

presented as: average (minimum-maximum) or median (minimum-maximum). ................................ E-36

Table E-10. Classes of organic compounds and representative example compounds found in 

coal bed methane and gas shale formations (Orem et al., 2014). ................................................................. E-38

Table E-11. Reported concentrations (μg/L) of organic constituents in produced water for 

two shale formations, presented as: average (minimum-maximum) or median (minimummaximum). .......................................................................................................................................................................... E-42
vii

Table E-12. Reported concentrations of organic constituents in 65 samples of produced 

water from the Black Warrior CBM Basin (Alabama and Mississippi), presented as: average 

(minimum-maximum). ................................................................................................................................................... E-44

Table E-13. Organic chemical concentrations reported from three specific studies of 

produced water (Khan et al., 2016; Lester et al., 2015; Orem et al., 2007). ............................................. E-45

Table E-14. Volume distribution in gallons (minimum, 25th percentile, median, 75th

percentile and maximum) for each type of spill in North Dakota for 2015. ............................................ E-70

Table E-15. Numbers of 2015 North Dakota spills in ranges defined by the spill volume 

statistics (Table E-13) for each type. ........................................................................................................................ E-70

Table E-16. Number of 2015 North Dakota spills which exceed thresholds (20,000 gal, 

40,000 gal, and 400,000 gal) for each type of spill. ............................................................................................ E-71

Table E-17. Outline of Northeastern Pennsylvania Retrospective Case Study QAPP. ......................... E-74

Table E-18. Source delineation analysis table from the EPA retrospective case study in Wise 

County, Texas. .................................................................................................................................................................... E-76

Table E-19. Combination truck crashes in 2012 for the 2,469,094 registered combination 

trucks, which traveled 163,358 million miles. ..................................................................................................... E-80

Table E-20. Large truck crashes in 2012. ............................................................................................................... E-80

Table E-21. Chances of a crash releasing produced water based on the total produced water 

volume per well, transport distances, crash rates, and material release rates. ..................................... E-82

Table F-1. Estimated volumes (millions of gallons) of wastewater based on state data for 

selected years and numbers of wells producing fluid. The wastewater is likely associated 

with an unknown combination of wells not hydraulically fractured and some hydraulically 

fractured. ................................................................................................................................................................................. F-4

Table F-2. Removal efficiency of different hydraulic fracturing wastewater constituents 

using various wastewater treatment technologies.a...........................................................................................F-16

Table F-3. Estimated effluent concentrations for example constituents based on treatment 

process removal efficiencies. ........................................................................................................................................F-20

Table F-4. Studies of removal efficiencies and influent/effluent data for various processes 

and facilities. ........................................................................................................................................................................F-24

Table F-5. Treatment processes for hydraulic fracturing wastewater organic constituents. ...........F-32

Table F-6. Examples of centralized waste treatment facilities. ......................................................................F-35

Table F-7. Water quality requirements for reuse. ...............................................................................................F-43

Table G-1. (a) Chemicals reported to be used in hydraulic fracturing fluids, with available 

chronic oral RfVs, OSFs, and qualitative cancer classifications from United States federal 

sources; (b) Chemicals reported to be used in hydraulic fracturing fluids, with available 

chronic oral RfVs and OSFs from state sources; (c) Chemicals reported to be used in 

hydraulic fracturing fluids, with available chronic oral RfVs and OSFs from international 

sources; (d) Chemicals reported to be used in hydraulic fracturing fluids, with available lessthan-chronic oral RfVs and OSFs; (e) Available qualitative cancer classifications for 

chemicals reported to be used in hydraulic fracturing fluids ........................................................................ G-12
viii

Table G-2. (a) Chemicals reported to be detected in produced water, with available chronic 

oral RfVs, OSFs, and qualitative cancer classifications from United States federal sources; (b) 

Chemicals reported to be detected in produced water, with available chronic oral RfVs and 

OSFs from state sources; (c) Chemicals reported to be detected in produced water, with 

available chronic oral RfVs and OSFs from international sources; (d) Chemicals reported to 

be detected in produced water, with available less-than-chronic oral RfVs and OSFs; (e) 

Available qualitative cancer classifications for chemicals reported to be detected in 

produced water ................................................................................................................................................................. G-41

Table H-1. Sources used to create lists of chemicals used in fracturing fluids or detected in 

produced water. ...................................................................................................................................................................H-3

Table H-2. Chemicals reported to be used in hydraulic fracturing fluids. ...................................................H-8

Table H-3. List of generic names of chemicals reportedly used in hydraulic fracturing fluids. .......H-62

Table H-4. Chemicals detected in produced water. ............................................................................................H-75

Table H-5. Chemicals detected in produced water for which a specific, valid CASRN could 

not be identified. ............................................................................................................................................................H-105
ix

List of Figures 

Figure A-1. Timeline of activities in the EPA’s hydraulic fracturing study.................................................. A-4

Figure A-2. Structure of the EPA’s hydraulic fracturing study. ........................................................................ A-8

Figure B-1. Major U.S. EIA shale plays and basins for Oklahoma and Kansas. ........................................ B-53

Figure B-2. Major U.S. EIA shale plays and basins for Utah, New Mexico, and California. ................. B-56

Figure C-1. Histograms of physicochemical properties organic chemicals claimed as 

confidential by industry that were used in the hydraulic fracturing process. ........................................ C-72

Figure D-1. A typical staged cementing process. ................................................................................................. D-11

Figure D-2. Examples of well completion types. .................................................................................................. D-12

Figure E-1. Fraction of injected hydraulic fracturing fluid recovered from six vertical (top) 

and eight horizontal (bottom) wells completed in the Marcellus Shale. ................................................... E-13

Figure E-2. Example of flowback and produced water from the Marcellus Shale, illustrating 

rapid decline in water production and cumulative return of approximately 30% of the 

volume of hydraulic fracturing fluid. ........................................................................................................................ E-14

Figure E-3. Percent of hydraulic fracturing fluid recovered for Marcellus Shale wells in West 

Virginia (2010 − 2012)................................................................................................................................................... E-15

Figure E-4. Barnett Shale monthly water-production percentiles (5th, 30th, 50th, 70th, and 

90th) and number of wells with data (dashed line). ........................................................................................... E-16

Figure E-5. Barnett Shale production data for approximately 72 months. .............................................. E-16

Figure E-6. Illustration of a "box" or "box and whisker" plot. ........................................................................ E-63

Figure E-7. Median, mean, and maximum volume of oil spills in North Dakota for 2001 to 

2015. ...................................................................................................................................................................................... E-64

Figure E-8. Median, mean, and maximum volume of “other” spills in North Dakota for 2002 

to 2015. ................................................................................................................................................................................. E-65

Figure E-9. Count of spills and active wells in North Dakota for the years 2001 to 2015. ................. E-66

Figure E-10. Number of spills in North Dakota from 2001 to 2015 separated by type and by 

“contained” versus “not contained.”......................................................................................................................... E-67

Figure E-11. Median volume (gal) of spills in North Dakota from 2001 to 2015 separated by 

type and by “contained” versus “not contained.”................................................................................................ E-68

Figure E-12. Yearly sum of spill volume (gal) of spills in North Dakota from 2001 to 2015 

separated by type and by “contained” versus “not contained.”.................................................................... E-69

Figure E-13. Numbers of contained spills in North Dakota by cause for 2014 and 2015. ................. E-71

Figure E-14. Numbers of not contained spills in North Dakota by cause for 2014 and 2015. ......... E-72

Figure E-15. Quality assurance blanks illustrating giving their purpose, brief procedure, and 

the span of their scope (modified from US EPA Region 3 Quality Control Tools: Blanks, April 

27, 2009). ............................................................................................................................................................................. E-75

Figure F-1. Electrocoagulation unit. .......................................................................................................................... F-10

Figure F-2. Photograph of reverse osmosis system. ........................................................................................... F-12
x 

Figure F-3. Picture of mobile electrodialysis units in Wyoming. ................................................................... F-13

Figure F-4. Picture of a mechanical vapor recompression unit near Decatur, Texas. ........................... F-14

Figure F-5. Mechanical vapor recompression process design – Maggie Spain Facility. ....................... F-14

Figure F-6. Picture of a compressed bed ion exchange unit. ........................................................................... F-15

Figure F-7. Full discharge water process used in the Pinedale Anticline field. ....................................... F-34

Figure F-8. Diagram of treatment for reuse of flowback and produced water. ....................................... F-45
xi

List of Text Boxes 

Text Box D-1. Selected Industry-Developed Specifications and Recommended Practices for 

Well Construction in North America. .......................................................................................................................... D-4
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Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources 

A-1 

Appendix A. The EPA's Study of the Potential 

Impacts of Hydraulic Fracturing for Oil and 

Gas on Drinking Water Resources 
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources

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Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources 

A-3 

Appendix A. The EPA’s Study of Hydraulic Fracturing for 

Oil and Gas and Its Potential Impact on Drinking Water 

Resources 

In 2009, at the urging of the U.S. Congress, the EPA initiated a study of hydraulic fracturing for oil 

and gas and its relationship to drinking water resources (hereafter the EPA’s hydraulic fracturing 

study). The national study culminates with this report, the Hydraulic Fracturing for Oil and Gas: 

Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United

States. 

The EPA’s hydraulic fracturing study consisted of many elements. It included independent 

research projects conducted by EPA scientists and contractors, and involved the analysis of 

existing data, scenario and modeling evaluations, laboratory studies, toxicological assessments, 

and case studies. A list of the ensuing EPA publications is presented in Table A-1. The EPA’s 

hydraulic fracturing study also included the development of this report, which is a state-of-thescience synthesis of available data and information, as well as the EPA’s own research.

Throughout, the EPA consulted with the Agency’s independent Science Advisory Board (SAB) on 

the scope of its hydraulic fracturing study and the progress made on each of the research projects. 

The timeline of this work is presented in Figure A-1. The SAB also conducted a peer review of both 

the EPA’s Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources

(U.S. EPA, 2011a, hereafter Study Plan) and the Hydraulic Fracturing for Oil and Gas: Impacts from

the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States, as described 

in Chapter 1. 

Stakeholder engagement also played an important role in the development and implementation of 

the EPA’s hydraulic fracturing study. The EPA held public meetings across the United States to 

hear feedback from stakeholders on the proposed study design and scope. In addition, while 

conducting the hydraulic fracturing study, the EPA engaged with technical, subject-matter experts 

on relevant topics in a series of technical workshops and roundtables (Figure A-1). 
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources

A-4 

Figure A-1. Timeline of activities in the EPA’s hydraulic fracturing study. 

On the left are activities related to the development of products from the EPA’s hydraulic fracturing study, in the 

center are interactions between the EPA and the SAB, and on the right are stakeholder engagement activities.
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources 

A-5 

A.1. The EPA’s Hydraulic Fracturing Study Publications Cited in This 

Assessment 

In this section, we provide a table of publications that were completed as part of the EPA’s 

hydraulic fracturing study and cited in this assessment. We also indicate projects that were 

originally part of the Study Plan but that did not result in a publication. The full list of publications 

under the EPA’s hydraulic fracturing study is updated and available at 

https://www.epa.gov/hfstudy. 

Table A-1. Titles, descriptions, and citations for the EPA’s hydraulic fracturing study 

publications cited in this assessment. 

Research project Description Citations/Notes

Analysis of existing data 

Literature Review Review and assessment of existing papers and 

reports, focusing on peer-reviewed literature 

Literature review is incorporated into 

this assessment.

Spills Database Analysis Characterization of hydraulic fracturingrelated spills using information obtained from 

selected state and industry data sources 

U.S. EPA (2015j)

Service Company 

Analysis 

Analysis of information provided by nine 

hydraulic fracturing service companies in 

response to a September 2010 information 

request on hydraulic fracturing operations 

Analysis of data received is 

incorporated into this assessment.a

Well File Review Analysis of information provided by nine oil 

and gas operators in response to an August 

2011 information request for 350 well files 

U.S. EPA (2015k)

U.S. EPA (2016a)

Analysis of data received is also 

incorporated into this assessment.b

FracFocus Analysis Analysis of water and chemical use data for 

hydraulic fracturing wells compiled from 

FracFocus 1.0, the national hydraulic 

fracturing chemical registry operated by the 

Ground Water Protection Council and the 

Interstate Oil and Gas Compact Commission 

U.S. EPA (2015a)

U.S. EPA (2015b)

U.S. EPA (2015c)

Scenario evaluations 

Subsurface Migration 

Modeling 

Numerical modeling of subsurface fluid 

migration scenarios that explore the potential 

for fluids, including liquids and gases, to move 

from the fractured zone to drinking water 

aquifers 

Kim and Moridis (2013)

Kim et al. (2014)

Kim and Moridis (2015)

Kim et al. (2016)

Reagan et al. (2015)

Rutqvist et al. (2013)

Rutqvist et al. (2015)
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources

A-6 

Research project Description Citations/Notes

Surface Water Modeling Modeling of concentrations of selected 

chemicals at public water supplies 

downstream from wastewater treatment 

facilities that discharge treated hydraulic 

fracturing wastewater to surface waters 

Weaver et al. (2016)

Water Availability 

Modeling 

Assessment and modeling of current and 

future scenarios exploring the impact of 

water usage for hydraulic fracturing on 

drinking water availability in the Upper 

Colorado River Basin and the Susquehanna 

River Basin 

U.S. EPA (2015d)

Laboratory studies 

Source Apportionment 

Studies 

Identification and quantification of the 

source(s) of high bromide and chloride 

concentrations at public water supply intakes 

downstream from wastewater treatment 

plants discharging treated hydraulic fracturing 

wastewater to surface waters 

U.S. EPA (2015l)

Wastewater Treatability 

Studies

Assessment of the efficiency of common 

wastewater treatment processes on removing 

selected chemicals found in hydraulic 

fracturing wastewater

None 

Br-DBP Precursor 

Studies

Assessment of the ability of bromide and 

brominated compounds present in hydraulic 

fracturing wastewater to form brominated 

disinfection byproducts (Br-DBPs) during 

drinking water treatment processes

None

Analytical Method 

Development 

Development of analytical methods for 

selected chemicals found in hydraulic 

fracturing fluids or wastewater 

DeArmond and DiGoregorio (2013a)

DeArmond and DiGoregorio (2013b)

U.S. EPA (2014b)

U.S. EPA (2014f)

Toxicity assessment

Toxicity Assessment Toxicity assessment of chemicals reportedly 

used in hydraulic fracturing fluids or found in 

hydraulic fracturing wastewater

Yost et al. (2016a)

Yost et al. (2016b)

Yost et al. (In Press)

Case studies

Retrospective case studies: Investigations of whether reported drinking water impacts may be associated 

with or caused by hydraulic fracturing activities

Las Animas and 

Huerfano Counties, 

Colorado 

Investigation of potential drinking water 

impacts from coalbed methane extraction in 

the Raton Basin 

U.S. EPA (2015h)
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A-7 

Research project Description Citations/Notes

Dunn County, North 

Dakota 

Investigation of potential drinking water 

impacts from a well blowout during hydraulic 

fracturing for oil in the Bakken Shale 

U.S. EPA (2015f)

Bradford County, 

Pennsylvania 

Investigation of potential drinking water 

impacts from shale gas development in the 

Marcellus Shale 

U.S. EPA (2014d)

Washington County, 

Pennsylvania 

Investigation of potential drinking water 

impacts from shale gas development in the 

Marcellus Shale 

U.S. EPA (2015g)

Wise County, Texas Investigation of potential drinking water 

impacts from shale gas development in the 

Barnett Shale 

U.S. EPA (2015i)

Prospective case studies Investigation of potential impacts of hydraulic fracturing through collection of 

samples from a site before, during, and after well pad construction and hydraulic fracturing

The EPA was unable to find suitable locations that met both the scientific criteria of a rigorous prospective 

study and the business needs of potential partners.

a Data received and incorporated into this document is cited as: U.S. EPA (U.S. Environmental Protection Agency). (2013). Data 

received from oil and gas exploration and production companies, including hydraulic fracturing service companies 2011 to 

2013. Non-confidential business information source documents are located in Federal Docket ID: EPA-HQ-ORD2010-0674. 

Available at http://www.regulations.gov. 

b Data received and incorporated into this document is cited as: U.S. EPA (U.S. Environmental Protection Agency). (2011). 

Sampling data for flowback and produced water provided to EPA by nine oil and gas well operators (non-confidential business 

information). US Environmental Protection Agency. 

http://www.regulations.gov/#!docketDetail;rpp=100;so=DESC;sb=docId;po=0;D=EPA-HQ-ORD-2010-0674.

A.2. Answers to the Secondary Research Questions 

The EPA’s Study Plan (U.S. EPA, 2011a) was organized around the five stages of the hydraulic 

fracturing water cycle. Each stage of the hydraulic fracturing water cycle was associated with a 

primary research question (Figure A-2). Nested within each primary research question was a set of 

secondary research questions. The primary and secondary research questions provided a 

framework for exploring how hydraulic fracturing water cycle activities could potentially impact 

drinking water resources. Research projects, undertaken using different types of research 

approaches (i.e., analysis of existing data, scenario evaluations, laboratory studies, toxicity 

assessment, and case studies), were designed to provide information relevant to answering the 

secondary research questions. 
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Figure A-2. Structure of the EPA’s hydraulic fracturing study.

This diagram shows the generalized elements of the study and how they relate to one another. 

The primary research questions included: 











Water acquisition: What are the potential impacts of large volume water withdrawals from 

groundwater and surface water on drinking water resources? 

Chemical mixing: What are the possible impacts of hydraulic fracturing fluid surface spills 

on or near well pads on drinking water resources? 

Well injection: What are the possible impacts of the injection and fracturing process on 

drinking water resources? 

Produced water handling: What are the possible impacts of flowback and produced water 

(collectively referred to as “hydraulic fracturing wastewater”) surface spills on or near 

well pads on drinking water resources? 

Wastewater disposal and reuse: What are the possible impacts of inadequate treatment of 

hydraulic fracturing wastewater on drinking water resources? 

In this section we present answers to the secondary research questions posed in the Study Plan as a 

way of providing continuity between the Study Plan and this assessment. Answers were informed 

by the knowledge accumulated and synthesized from the EPA’s hydraulic fracturing study, 

including the scientific literature reviewed for this assessment.
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A.2.1. Water Acquisition 







What are the types of water used for hydraulic fracturing? 

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 through public water systems or other 

suppliers. Hydraulic fracturing operations in the eastern United States rely predominantly on 

surface water, whereas operations in more semi-arid to arid western states use either surface 

water or groundwater. In some areas of the country, operators rely entirely on groundwater 

supplies (e.g., western Texas). 

Fresh water (from both surface water and groundwater sources) currently supplies the vast 

majority of water used for hydraulic fracturing. However, the reuse of hydraulic fracturing 

wastewater for injection reduces the demand on fresh water sources. Nationally, the proportion of 

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). 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. Reuse as a percentage of water injected is typically lower 

in other areas, in part because of the availability of disposal wells (Chapter 8). 

How much water is used per well? 

The median amount of water used nationally per hydraulically fractured well was approximately 

1.5 million gal (5.7 million L) in 2011 and through early 2013 based on disclosures to FracFocus 

(U.S. EPA, 2015a, c). This increased to approximately 2.7 million gal (10.2 million L) in 2014, driven 

by a proportional increase in horizontal wells that, on average, use more water per well (estimated 

from data reported in Gallegos et al., 2015) (Figure 4-1). 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, 2015a). This variation results from several factors, including geology, well 

length, and fracturing fluid formulation. 

How might cumulative water withdrawals for hydraulic fracturing affect drinking 

water quantity? 

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, 
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however, hydraulic fracturing generally accounts for only a small percentage, usually less than 1%. 

These percentages are higher 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, 30% or more in 2.2% of counties, and 50% or more in 1.0% of counties (see 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 (see Table B-2). 

Thus, hydraulic fracturing represents a relatively large user and consumer of water in these 

counties. 

Whether water quantity impacts occur from water acquisition for hydraulic fracturing depends on 

the 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 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. Importantly, our results do not preclude the possibility of local water 

quantity impacts in areas with comparatively lower potential, nor do they necessarily mean 

impacts have occurred in the high potential areas. Our survey provides an indicator of areas with 

higher potential for impacts, and could be used to target resources for future studies. 

Local impacts to drinking water resources have occurred in areas with increased hydraulic 

fracturing activity. In a detailed case study, Scanlon et al. (2014) 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 

approximately 100 to 200 ft (30 to 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 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 use likely 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 current hydraulic fracturing water withdrawals (U.S. EPA, 

2015d) (Sections 4.5. and 4.5). These site-specific findings emphasize the need to focus on regional 

and local dynamics when considering the impacts from hydraulic fracturing water withdrawals. 

 What are the possible impacts of water withdrawals for hydraulic fracturing on water 

quality? 

Water withdrawals for hydraulic fracturing, similar to all water withdrawals, have the potential to 

alter the quality of drinking water resources. Groundwater withdrawals exceeding natural recharge 

rates decrease water storage in aquifers, potentially mobilizing contaminants or allowing the 

infiltration of lower-quality water from the land surface or adjacent formations. Pumping can also 

promote changes in reduction-oxidation (redox) conditions and mobilize chemicals from geologic 

sources (e.g., uranium). Withdrawals can also decrease groundwater discharge to streams, 

potentially affecting surface water quality. Areas with declining groundwater resources, 
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particularly in drought-prone regions, are most likely to experience water quality impacts from 

hydraulic fracturing water withdrawals. 

Surface water withdrawals also have the potential to affect water quality, particularly in smaller 

streams. Withdrawals may lower water levels and alter stream flow, decreasing a stream’s capacity 

to dilute contaminants. Studies by the EPA show that streams can be vulnerable to changes in water 

quality due to water withdrawals, most notably smaller streams or during periods of low flow (U.S. 

EPA, 2015d). Managing the rate and timing of surface water withdrawals (e.g., passby flows) can 

help mitigate potential impacts on water quality. 

A.2.2. Chemical Mixing 

 What is currently known about the frequency, severity, and causes of spills of

hydraulic fracturing fluids and additives?

There has not been much work on the frequency of spills of hydraulic fracturing fluids and 

additives. Using spills data from three states (Pennsylvania, Colorado, and North Dakota), there is 

an estimated median of 2.6 reported spills for every 100 wells, with a range of 0.4 to 12.2. These 

values are uncertain because these rates used different criteria for including a spill, what the 

denominator is for the well type (e.g., drilled or finished), and includes more than hydraulic 

fracturing fluids and additives. Using solely the North Dakota database, we estimate 2.6 reported 

spills of injected fluid or chemical per 100 wells fractured (Rahm et al., 2015; U.S. EPA, 2015j; 

Brantley et al., 2014; Gradient, 2013).1 Estimates of the frequency of on-site spills from hydraulic 

fracturing operations were unavailable for other areas. It is unknown whether these spill estimates 

are representative of national occurrences. 

The severity of a spill depends on several factors, including: spill amount (mass, volume, 

concentration), the fate and transport of the spill, if it reaches a water resource, the characteristics 

of the receiving water resource, and the hazard associated with the chemicals themselves. There is 

little known on the severity of hydraulic fracturing fluid and additive spills. The reported volume 

of chemicals or hydraulic fracturing fluid spilled range of 5 to 19,320 gal (19 to 73,130 L), with a 

median volume of 420 gal (1,600 L) per spill. Spill reports contain little information on chemicalspecific 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. 

Spill causes included equipment failure, human error, failure of container integrity, and other (e.g., 

weather and vandalism). The most common cause was equipment failure. Equipment failure 

included blowout preventer failure, corrosion, and failed valves. More than 30% of the chemical or 

hydraulic fracturing fluid spills characterized by the EPA came from fluid storage units (e.g., tanks, 

totes, and trailers) (U.S. EPA, 2015j). 

1 Spill frequency estimates are for a given number of wells over a given period of time. These are not annual estimates nor 

are they for over a lifetime of the wells. 
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 What are the identities and volumes of chemicals used in hydraulic fracturing fluids, 

and how might this composition vary at a given site and across the country? 

The EPA has identified 1,084 different chemicals used in chemical mixing. A recent study of 

FracFocus disclosure data reported an additional 263 new CASRNs, increasing the total number of 

chemicals identified as used by approximately 24% (Konschnik and Dayalu, 2016). Industry use of 

confidential business information (CBI) is one factor that likely limits the completeness of these 

chemical lists. The EPA’s analysis of disclosures to FracFocus 1.0 found that 11% of ingredients 

were reported to FracFocus as CBI (U.S. EPA, 2015a), and the more recent analysis by Konschnik 

and Dayalu (2016) indicated a 5.6% increase in the number of CBI ingredients. 

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. Thirty-two chemicals, excluding water, quartz, 

and sodium chloride, have been reported to be used at 10% or more sites. 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. 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 frac jobs, with methanol being used at 72% of all sites. 

Operators used a median of 14 unique chemicals per well according to the EPA’s analysis of 

disclosures to FracFocus 1.0 (U.S. EPA, 2015a). 

The composition of hydraulic fracturing fluids varies by state, by well, and within the same service 

company and geologic formation. This variability likely results from several factors, including the 

geology of the formation, production goals, the availability and cost of different chemicals, and 

operator preference (U.S. EPA, 2015a). 

The estimated median volumes of individual chemicals injected per well ranged from a few gallons 

to thousands of gallons, with a median of 650 gal (2,500 L) per chemical per well (U.S. EPA, 2015c). 

There is an estimated 9,100 gal (34,000 L) to 30,000 gal (114,000L) of chemicals used per well. 

 What are the chemical, physical, and toxicological properties of hydraulic fracturing 

chemical additives? 

The EPA identified 1,084 different chemicals reported to be used in hydraulic fracturing fluid from 

2005 to 2013. Of these, 455 (more than 40%) were individual organic chemicals with 

physicochemical properties that vary, from fully miscible to insoluble and from highly hydrophobic 

to highly hydrophilic. We were able to estimate the physicochemical properties of these 455 

chemicals using the EPA’s Estimation Program Interface (EPI) SuiteTM software. Of the 20 most 

frequently used chemicals, three have low mobility: (1) distillates, petroleum, hydrotreated light; 

(2) solvent naphtha, petroleum, heavy aromatic; and, (3) naphthalene. These chemicals have the 

potential to act as long term sources of contamination if spilled on-site. 

The chemicals with determinable physicochemical properties were not necessarily the chemicals 

most frequently reported as used in hydraulic fracturing fluids or activities. Of the 455 chemicals 
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for which physicochemical properties were available, 18 of the top 20 most mobile chemicals were 

included in 2% or less of disclosures (U.S. EPA, 2015c). However, two highly mobile chemicals, 

choline chloride and tetrakis (hydroxymethyl) phosphonium sulfate were reported in 14% and 

11% of disclosures, respectively. These two chemicals are relatively more common, and, if spilled, 

would move quickly through the environment with the flow of water. 

Of the 1,084 chemicals identified by the EPA as used in hydraulic fracturing fluids, chronic oral RfVs 

and/or OSFs from selected federal, state, and international sources were available for 98 (9%) of 

these chemicals. From the federal sources alone, chronic oral RfVs were available for 81 chemicals 

(7%), and OSFs were available for 15 chemicals (1%). Chronic oral RfVs and OSFs from these 

selected sources were not available for the majority of chemicals used in hydraulic fracturing fluid, 

representing a potential data gap with regard to hazard identification. Of the chemicals that have 

these selected toxicity values, health effects associated with chronic oral exposure include the 

potential for carcinogenesis, immune system effects, changes in body weight, changes in blood 

chemistry, cardiotoxicity, neurotoxicity, liver and kidney toxicity, and reproductive and 

developmental toxicity. 

When considering the hazard evaluation of these chemicals on a nationwide scale, chemicals such 

as propargyl alcohol stand out for their relatively low RfVs, high frequency of use, and expected 

transport and mobility in water. However, the EPA’s analysis of disclosures to FracFocus 1.0 

indicates that most chemicals are used infrequently on a nationwide scale. Potential exposures to 

the majority of these chemicals are likely to be a local issue, rather than a national one. Accordingly, 

potential hazard and risk considerations for hydraulic fracturing fluid additives are best made on a 

site-specific, well-specific basis.

 If spills occur, how might hydraulic fracturing chemical additives contaminate 

drinking water resources? 

The potential for spilled fluids to contaminate 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. Spill characteristics (e.g., the volume and chemical composition of the spilled 

fluid) describe the identity and volume of chemicals that enter the environment due to a spill. The 

environmental fate and transport of the spilled fluid describes how spilled chemicals move and 

transform in the environment. Spill response activities include actions designed to remove spilled 

fluids from the environment. Because all of these factors influence whether spilled fluids reach 

groundwater and surface water resources, they affect the frequency and severity of potential 

impacts to drinking water resources from spills during the chemical mixing stage of the hydraulic 

fracturing water cycle. 

The movement of spilled hydraulic fracturing fluids and additives through the environment is 

difficult to assess, because of the site-specific and chemical-specific nature of spills and because 

hydraulic fracturing-related spills typically involve complex mixtures of chemicals. In the absence 

of site-specific studies of actual spills, we relied on fundamental environmental fate and transport 

principles to describe how hydraulic fracturing fluids and chemicals used in hydraulic fracturing 

fluids can move through the environment to drinking water resources. 
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The environmental fate and transport of hydraulic fracturing fluids and chemicals depend on sitespecific environmental conditions and the physicochemical properties of the chemicals spilled. Sitespecific environmental characteristics can affect how spilled liquids move through soil into the 

subsurface or over the land surface. Generally, highly permeable soils or preferential flow paths 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. When spilled liquids move 

underground, the distance between the land surface and the groundwater resource can affect 

whether spilled liquids reach groundwater. Large spills volumes are more likely to be able to travel 

the distance between the land surface and the groundwater resource and impact the latter. In low 

permeability soils, spilled liquids are less able to move into the subsurface and are more likely to 

move over the land surface. When spilled liquids move over the land surface, the volume spilled and 

the distance between the source of the spill and nearby surface water resources can affect whether 

the spilled liquid reaches surface water. 

A.2.3. Well Injection

 How effective are current well construction practices at containing fluids—both 

liquids and gases—before, during, and after fracturing? 

A well will be exposed to the highest stress during the relatively brief phase of injection for 

hydraulic fracturing. If the well cannot withstand these stresses, the casing or cement can fail, 

resulting in the unintended movement of hydraulic fracturing fluids or naturally-occurring liquids 

or gases into the surrounding environment and, potentially, an impact on drinking water quality. 

These failures can be the result of inadequate design and/or construction, or degradation of the 

casing and/or cement that allows fluid to move laterally from inside the well to the formation or 

vertically along the wellbore from the production zone to shallower drinking water resources. 

The presence of multiple layers of casing strings can isolate and protect geologic zones containing 

drinking water. Most wells used in hydraulic fracturing operations are designed with one or more 

of these layers of casing. 

Cementing of the surface casing to below the lowest drinking water resource is a key protective 

measure to prevent hydraulic fracturing fluids, or other fluids, from reaching drinking water 

resources. Most states require this (GWPC, 2014); however, our data indicate adequate casing 

and/or cement are not present in all wells. For example, studies in Wyoming and Colorado have 

documented wells with partially uncemented surface casing (Fleckenstein et al., 2015; WYOGCC, 

2014). 

The presence of properly placed, adequate cement in those portions of the well that intersect 

porous or permeable water- and/or hydrocarbon-bearing zones can also prevent fluids from 

moving into drinking water resources. Wells with cement that does not resist formation or 

operational stresses have the potential to promote unintended subsurface fluid movement. In 

Bainbridge Township, Ohio, hydraulic fracturing was performed in a well with improperly 

emplaced and inadequate cement. This resulted in natural gas movement upward along the 
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A-15

wellbore, contamination of the drinking water aquifer, and the loss of 26 private drinking water 

wells (Bair et al., 2010). 

Even in optimally designed and constructed wells, metal casings and cement can degrade over 

time—either as a result of aging or stresses exerted over years of operations—and affect the 

integrity of the well. We have limited access to data and information regarding the degree to which 

the integrity of wells is verified before or after hydraulic fracturing operations. 

 Can subsurface migration of fluids—both liquids and gases—to drinking water 

resources occur, and what local geologic or artificial features might allow this? 

The presence of artificial penetrations, such as inadequately constructed or degraded offset wells or 

undetected abandoned wells near the well undergoing hydraulic fracturing, can provide pathways 

that allow fluid movement to drinking water resources. If the fractures created during hydraulic 

fracturing intersect a nearby, previously-fractured production well or its fracture network, 

hydraulic fracturing fluids or other fluids can move to that well in an event known as well 

communication or a “frac hit” (Jackson et al., 2013a). Instances of well communication have 

occurred in New Mexico (Vaidyanathan, 2014) and Texas (Craig et al., 2012). Additionally, 

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 the plugs 

and cement have degraded over time. This can be a significant issue in areas with legacy (i.e., 

historic) oil and gas exploration and when wells are re-entered and fractured (or re-fractured) to 

increase production in a reservoir. 

Some hydraulic fracturing operations involve the injection of fluids into formations with relatively 

limited vertical separation from drinking water resources. Where the separation between the 

production zone and drinking water resource is small, and where natural or induced fractures 

transecting the layers between these formations are present, there is an increased potential for 

impacts to drinking water quality. 

Hydraulic fracturing is also performed within formations that meet the salinity threshold used in 

some definitions of a drinking water resource, in addition to the broader definition of a drinking 

water resource developed for this assessment. By definition, these hydraulic fracturing operations 

affect the quality of the drinking water resources. 

A.2.4. Produced Water Handling 

 What is currently known about the frequency, severity, and causes of spills of flowback 

and produced water? 

Surface spills of produced water from unconventional oil and gas production have occurred across 

the country. Some produced water spills have affected drinking water resources, including private 

drinking water wells. Analysis of data from North Dakota suggests a produced water spill rate of 5 

to 7 spills per 100 active production wells. Of these, an estimated 84% are confined to the 

production or exploration facility and expected to have a lower potential to impact drinking water 

resources. Half of the spills are estimated to be less than 1,000 gal (3,800 L), but a small number of 
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large spills have occurred. For example, in North Dakota in 2015, there were 12 releases of 21,000 

gal (79,000 L) or more out of a total of 609 spills. The largest reported spill was 2.9 million gal (11.0 

million L). The causes identified for these spills are container and equipment failures, human error, 

well communication, blowouts, pipeline leaks, and dumping. Although specific impacts from a few 

spills have been documented, the severity of most spills is unknown. 

 What is the composition of hydraulic fracturing flowback and produced water, and 

what factors might influence this composition? 

The geochemical content of water flowing back initially reflects injected fluids. After initial 

flowback, returning fluid geochemistry shifts to reflect the geochemistry of formation waters and 

formation solids. According to the available literature and data, conventional and unconventional 

produced water content are often similar with respect to the occurrence and concentration of many 

constituents. Much produced water is generally characterized as saline (with the exception of most 

coalbed methane produced water) and enriched in major anions, cations, metals, naturally 

occurring radionuclides, and organics. The composition of produced water must be determined 

through sampling and analysis, both of which have limitations. Sampling limitations include 

equipment configurations that make it difficult to access representative fluids. Analytical 

limitations include identifying target analytes in advance, without sufficient knowledge of the 

composition of the fluid sampled, as well as the lack of appropriate analytical methods. 

Typically, unconventional produced water contains low levels of heavy metals. However, elevated 

strontium and barium levels are characteristic of Marcellus Shale produced water. Elevated levels 

of technologically enhanced naturally occurring radioactive materials (TENORM) have also been 

documented in the Marcellus Shale produced water. Other formations also contain TENORM, but 

fewer data are available. Composition data were limited, in general. Most of the available data on 

produced water content were for shale formations and CBM basins, while few data were available 

for sandstone formations. 

Recent published research has identified several hundred organic chemicals in produced water. 

Many of these are naturally-occurring constituents of petroleum, while fewer are known hydraulic 

fracturing chemicals. The identification of many organic chemicals in produced water depends on 

the availability of advanced laboratory analytical methods and equipment. Much less is known 

about subsurface transformation products and only a few have been identified. Recent research 

shows that subsurface transformation reactions may reduce concentrations of some hydraulic 

fracturing additives through oxidation (gelling agents and friction reducers), may create 

chlorinated and brominated organic compounds, and that surfactants (i.e., glycols) may be resistant 

to degradation and remain in produced water. 

Hydraulic fracturing flowback and produced water composition is influenced by the composition of 

injected hydraulic fracturing fluids, the targeted geological formation and associated hydrocarbon 

products, the stratigraphic environment, and subsurface processes and residence time. Spatial 

variability of produced water content occurs between plays of different rock type (e.g., coal vs. 

sandstone), between plays of the same rock type (e.g., Barnett Shale vs. Bakken Shale), and within 

formations of the same source rock (e.g., northeastern vs. southwestern Marcellus Shale). 
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 What are the chemical, physical, and toxicological properties of hydraulic fracturing 

flowback and produced water constituents? 

This assessment identified 599 chemicals that are reported to have been detected in hydraulic 

fracturing produced water. These include chemicals that are added to hydraulic fracturing fluids 

during the chemical mixing stage, as well as naturally occurring organic chemicals, metals, naturally 

occurring radioactive material, and other subterranean chemicals that may be mobilized by the 

hydraulic fracturing process. 

The identified constituents of produced water include inorganic chemicals (cations and anions in 

the form of metals, metalloids, non-metals, and radioactive materials), organic chemicals and 

compounds, and unidentified materials measured as TOC (total organic carbon) and DOC (dissolved 

organic carbon). Some constituents are readily transported with water (i.e., chloride and bromide), 

while others depend strongly on the geochemical conditions in the receiving water body (i.e., 

radium and barium), and assessment of their transport is based on site-specific factors. Using the 

EPA’s EPI Suite software, we were able to obtain actual or estimated physicochemical properties for 

521 (87%) individual organic chemicals of the 599 chemicals identified in produced water. The EPI 

SuiteTM results are constrained by their applicability to one temperature (25 °C), and salinity (low). 

Temperature changes impact Henry’s law constant, Kow, and solubility, and depend on the 

characteristics of the chemical and ions present. In some cases, the effect changes exponentially 

with salinity. Therefore, property values that depart from the EPI SuiteTM values are expected for 

the 599 chemicals identified in produced water at elevated temperature and salinity. Although little 

is known concerning attenuation of hydraulic fracturing fluid constituents, Kekacs et al. (2015)

report that salinity above 40,000 mg/L initially inhibited aerobic degradation of the organic 

constituents of a synthetic fracturing fluid (for 6.5 days), even though the bacterial communities 

were pre-acclimated to the salts. 

Of the 599 chemicals identified by the EPA as detected in produced water, chronic oral RfVs and/or 

OSFs from selected federal, state, and international sources were available for 120 (20%) of these 

chemicals. From the federal sources alone, chronic oral RfVs were available for 97 chemicals (16%), 

and OSFs were available for 30 chemicals (5%). Of the chemicals that have these selected toxicity 

values, health effects associated with chronic oral exposure include the potential for carcinogenesis, 

immune system effects, changes in body weight, changes in blood chemistry, pulmonary toxicity, 

neurotoxicity, liver and kidney toxicity, and reproductive and developmental toxicity. 

In a hazard evaluation of produced water data, chemicals such as benzene, pyridine, and 

naphthalene stood out for their relatively lower RfVs, high average concentrations, and expected 

transport and mobility in water. However, the chemicals present in produced water are likely to 

vary on a regional and well-specific basis as a result of geological differences, as well as differences 

between hydraulic fracturing fluid formulations. Therefore, potential hazard and risk 

considerations are best made on a site-specific basis. 
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources

A-18





If spills occur, how might hydraulic fracturing flowback and produced water 

contaminate drinking water resources? 

Both the scientific literature and published reports have shown that produced water spills have 

impacted drinking water resources. Spills of produced water may impact drinking water resources 

if the spill or release is of sufficient volume and duration to reach the resource at a sufficient 

concentration. During the first few months of production produced water is most likely to contain 

hydraulic fracturing additives and have low salinity. Later, the composition of shale-gas produced 

water will be dominated by high salinity. Spilled produced water can flow overland to reach surface 

water resources. Some of that water might infiltrate to impact soils and groundwater. Which path 

the spill takes depends on different conditions, such as the distance to a water receptor, spill 

volume, soil characteristics, and the physicochemical properties of the chemical. Of the produced 

water spills documents by the EPA, 17 (8%) reached surface water resources and 1 (0.4%) was 

documented to reach groundwater (U.S. EPA, 2015j), although groundwater impacts from 107 

additional spills were unknown. More spills (141 or 63%) impacted soil, and the impacts of 30 

spills were unknown. 

A.2.5. Wastewater Disposal and Reuse 

What are the common treatment and disposal methods for hydraulic fracturing 

wastewater, and where are these methods practiced?

The majority of hydraulic fracturing wastewater in the United States is disposed of via underground 

injection wells. As of 2014–2015, most states where hydraulic fracturing occurs have access to an 

adequate number of Class IID injection wells regulated under the Underground Injection Control 

(UIC) Program. The Marcellus Shale region, especially the northeastern region, is an exception. Due 

to the lack of available injection wells, wastewater reuse, with or without treatment beforehand (at 

centralized waste treatment facilities (CWTs) or mobile facilities), is currently the primary means 

of wastewater management and may continue to increase in western shale plays as the practice 

becomes encouraged and economically favorable. Other methods of management used to a lesser 

degree include evaporation and agricultural use (for low-total dissolved solids (TDS) wastewater), 

both of which occur in the western United States. 

 How effective are conventional POTWs and commercial treatment systems in 

removing organic and inorganic contaminants of concern in hydraulic fracturing 

wastewater? 

Publicly owned treatment works (POTWs) using basic treatment processes cannot effectively 

reduce TDS concentrations in highly saline hydraulic fracturing wastewater. CWTs that use 

advanced treatment processes such as mechanical vapor recompression, distillation, and reverse 

osmosis have been shown to remove TDS constituents with removal efficiencies ranging from 97% 

to over 99% (Table F-4). These advanced treatment processes can also remove other constituents 

found in hydraulic fracturing wastewater such as metals, cations, anions, and some organics. 
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources 

A-19

Indirect discharge, where wastewater is pretreated by a CWT and sent to a POTW, may be an 

effective option for hydraulic fracturing wastewater treatment (with restrictions on contaminant 

concentrations in the pretreated wastewater). This option would require careful planning to ensure 

that the pretreated wastewater blended with POTW influent is of appropriate quality to prevent 

deleterious effects on biological processes in the POTW or the pass-through of contaminants. 

Facilities that treat wastewater for reuse and employ only basic treatment are unable to remove all 

contaminants in hydraulic fracturing wastewater, especially if the CWTs do not include specific 

processes (e.g., distillation, advanced oxidation, adsorption) that target constituents of concern. 

Depending on the water quality requirements for a particular site, these lower quality treated 

waters may be of adequate quality for reuse in subsequent hydraulic fracturing operations (and will 

be less costly). 

 What are the potential impacts from surface water disposal of treated hydraulic 

fracturing wastewater on drinking water treatment facilities? 

Inadequate bromide and iodide removal from treated hydraulic fracturing wastewater has the 

potential to affect surface water quality and place a burden on downstream drinking water 

treatment facilities due to the formation of disinfection byproducts (DBPs). This occurs when 

bromide and iodide react with organic carbon and drinking water disinfectants. Although sampling 

data are limited both for treated wastewaters and receiving waters, bromide has reached drinking 

water resources via some discharges. One utility in Pennsylvania found that elevated bromide in 

their source water led to elevated disinfection byproducts in their treated drinking water. 

Ammonium in hydraulic fracturing wastewater could also impact downstream drinking water 

supplies by altering disinfection chemistry. Other constituents (e.g., including radionuclides, 

barium, and organic compounds) may impact drinking water resources if they are present in high 

concentrations in the wastewater and the applied wastewater treatment does not adequately 

remove them. Constituents such as radium, metals, and organics can also accumulate in sediments 

downstream of discharge points. 

As of 2014–2015, there is a lack of data on the concentrations of most hydraulic fracturing 

wastewater constituents in the water near drinking water intakes in regions with hydraulic 

fracturing activity. Therefore, it is not known whether or to what degree these contaminants have 

affected drinking water systems.
Appendix A – The EPA’s Study of Hydraulic Fracturing for Oil and Gas and Its Potential Impact on Drinking Water Resources

A-20

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Appendix B – Water Acquisition Supplemental Information

B-1 

Appendix B. Water Acquisition Supplemental 

Information 
Appendix B – Water Acquisition Supplemental Information 

B-2 

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Appendix B – Water Acquisition Supplemental Information

B-3 

Appendix B. Water Acquisition Supplemental 

Information 

B.1. Supplemental Tables

Table B-1. Average annual hydraulic fracturing water use and consumption in 2011 and 2012 

compared to total annual water use and consumption in 2010 by state.

Hydraulic fracturing water use data from the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). Annual total 

water use data from the U.S. Geological Survey (USGS) Water Census (Maupin et al., 2014). Estimates of 

consumption were derived from hydraulic fracturing water use and total water use data. States listed in 

descending order by the volume of hydraulic fracturing water use. 

State

Total annual water 

use in 2010 

(millions of gal)

a,b

Average annual

hydraulic 

fracturing water 

use in 2011 and 

2012 

(millions of gal)c

Hydraulic 

fracturing water 

use compared to

total water use 

(%)d

Hydraulic 

fracturing water 

consumption

compared to total 

water 

consumption (%)d,e

Texas 9,052,000 19,942 0.2 0.7

Pennsylvania 2,967,450 5,105 0.2 1.4

Arkansas 4,124,500 3,676 0.1 0.1

Colorado 4,015,000 3,277 0.1 0.1

Oklahoma 1,157,050 2,949 0.3 0.8

Louisiana 3,117,100 2,462 0.1 0.4

North Dakota 419,750 2,181 0.5 2.9

West Virginia 1,288,450 657 0.1 0.5

Wyoming 1,715,500 538 <0.1 <0.1

New Mexico 1,153,400 371 <0.1 <0.1

Ohio 3,445,600 273 <0.1 0.1

Utah 1,627,900 251 <0.1 <0.1

Montana 2,792,250 155 <0.1 <0.1

Kansas 1,460,000 66 <0.1 <0.1

California 13,870,000 44 <0.1 <0.1

Michigan 3,942,000 28 <0.1 <0.1

Mississippi 1,434,450 18 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information 

B-4 

State

Total annual water 

use in 2010 

(millions of gal)

a,b

Average annual

hydraulic 

fracturing water 

use in 2011 and 

2012 

(millions of gal)c

Hydraulic 

fracturing water 

use compared to

total water use 

(%)d

Hydraulic 

fracturing water 

consumption

compared to total 

water 

consumption (%)d,e

Alaskaf 397,850 7 <0.1 <0.1

Virginia 2,792,250 1 <0.1 <0.1

Alabama 3,635,400 1 <0.1 <0.1

Total for all 20 states 64,407,900 42,001 0.1 0.2

a Texas, Colorado, Pennsylvania, North Dakota, Oklahoma, and Utah all made some degree of reporting to the FracFocus

national registry mandatory rather than voluntary during this time period analyzed, January 1, 2011, to February 28, 2013.

Three other states started requiring disclosure to either FracFocus or the state (Louisiana, Montana, and Ohio), and five states 

required or began requiring disclosure to the state (Arkansas, Michigan, New Mexico, West Virginia, and Wyoming). Alabama, 

Alaska, California, Kansas, Mississippi, and Virginia did not have reporting requirements during the period of time studied (U.S. 

EPA, 2015a). 

b State-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on January 27, 2015. Total water 

withdrawals per day (located in downloaded Table 1) were multiplied by 365 days to estimate total water use for the year

(Maupin et al., 2014). 

c Average of water used for hydraulic fracturing in 2011 and 2012 based on the EPA FracFocus 1,0 project database (U.S. EPA, 

2015c). 

d Percentages were calculated by averaging annual water use for hydraulic fracturing in the EPA FracFocus 1.0 project database 

in 2011 and 2012 for a given state (U.S. EPA, 2015c), and then dividing by 2010 USGS total water use (Maupin et al., 2014) and 

multiplying by 100. Note that the annual hydraulic fracturing water use based on the EPA FracFocus 1.0 project database (the 

numerator) was not added to the 2010 total USGS water use value in the denominator, and the percentage is simply calculated 

as by dividing annual hydraulic fracturing use by 2010 total water use or consumption. This was done because of the difference 

in years between the two datasets, and because the USGS 2010 Census (Maupin et al., 2014) already included an estimate of 

hydraulic fracturing water use in its mining category. This approach is also consistent with that of other literature on this topic; 

see Nicot and Scanlon (2012). 

e Consumption values were calculated with use-specific consumption rates predominantly from the USGS, including 19.2% for 

public supply, 19.2% for domestic use, 60.7% for irrigation, 60.7% for livestock, 14.8% for industrial uses, 14.8% for mining

(Solley et al., 1998), and 2.7% for thermoelectric power (Diehl and Harris, 2014). We used a rate of 71.6% for aquaculture

(Verdegem and Bosma, 2009) (evaporation per kg fish + infiltration per kg)/(total water use per kg) *100. These rates were 

multiplied by each USGS water use value (Maupin et al., 2014) to yield a total water consumption estimate. To calculate a 

consumption amount for hydraulic fracturing, we used a consumption rate of 82.5%. This was calculated by taking the median 

value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this assessment and then subtracting 

from 100%. If a range of values was given, the midpoint was used. Note that this is likely a low estimate of consumption since 

much of this return water is not subsequently treated and reused, but rather disposed of in injection wells—see Chapter 8. 

f All reported hydraulic fracturing disclosures for Alaska passed state locational quality assurance methods, but not county 

methods (U.S. EPA, 2015c). Thus, only state-level cumulative values were reported here, and no county-level data are provided 

in subsequent tables.
Appendix B – Water Acquisition Supplemental Information

B-5 

Table B-2. Average annual hydraulic fracturing water use and consumption in 2011 and 2012 

compared to total annual water use and consumption in 2010 by county. 

The counties listed contained wells used for hydraulic fracturing based on the EPA FracFocus 1.0 project database 

(U.S. EPA, 2015c). Annual total water use data from the USGS Water Census (Maupin et al., 2014). Estimates of 

consumption derived from hydraulic fracturing water use and total water use data. 

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

Alabama Jefferson 29,685.5 0.6 <0.1 <0.1

Tuscaloosa 14,319.0 0.5 <0.1 <0.1

Arkansas Cleburne 9,471.8 740.9 7.8 32.9

Conway 10,643.4 798.1 7.5 21.2

Faulkner 3,204.7 284.0 8.9 13.7

Independence 57,195.5 80.3 0.1 0.3

Logan 1,525.7 2.4 0.2 0.3

Sebastian 1,365.1 0.6 <0.1 <0.1

Van Buren 1,587.8 899.6 56.7 168.8

White 32,131.0 869.8 2.7 4.7

California Yell 1,507.5 <0.1 <0.1 <0.1

Colusa 304,782.3 <0.1 <0.1 <0.1

Glenn 221,420.0 <0.1 <0.1 <0.1

Kern 788,359.9 41.7 <0.1 <0.1

Los Angeles 1,118,363.7 0.2 <0.1 <0.1

Sutter 263,511.8 0.2 <0.1 <0.1

Ventura 262,610.2 1.8 <0.1 <0.1

Colorado Adams 84,285.8 3.2 <0.1 <0.1

Arapahoe 68,255.0 4.0 <0.1 <0.1

Boulder 84,537.7 4.1 <0.1 <0.1

Broomfield 2,336.0 4.5 0.2 0.4

Delta 131,221.2 0.5 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information 

B-6 

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

Colorado, Dolores 2,040.4 0.1 <0.1 <0.1

cont. El Paso 42,380.2 <0.1 <0.1 <0.1

Elbert 5,040.7 <0.1 <0.1 <0.1

Fremont 53,366.7 0.6 <0.1 <0.1

Garfield 95,436.6 1,804.2 1.9 2.7

Jackson 126,968.9 1.0 <0.1 <0.1

La Plata 122,873.6 3.5 <0.1 <0.1

Larimer 150,690.3 5.4 <0.1 <0.1

Las Animas 26,911.5 7.9 <0.1 <0.1

Mesa 275,476.5 122.1 <0.1 0.1

Moffat 62,093.8 14.5 <0.1 <0.1

Morgan 67,901.0 3.9 <0.1 <0.1

Phillips 21,509.5 0.2 <0.1 <0.1

Rio Blanco 97,513.4 147.3 0.2 0.2

Routt 74,460.0 0.1 <0.1 <0.1

San Miguel 13,848.1 0.3 <0.1 <0.1

Weld 168,677.5 1,149.4 0.7 1.0

Yuma 80,595.7 0.4 <0.1 <0.1

Kansas Barber 2,164.5 9.9 0.5 0.7

Clark 1,898.0 0.8 <0.1 0.1

Comanche 3,011.3 25.6 0.9 1.2

Finney 102,685.5 2.4 <0.1 <0.1

Grant 47,128.8 0.2 <0.1 <0.1

Gray 69,379.2 3.3 <0.1 <0.1

Harper 1,357.8 17.3 1.3 2.0

Haskell 72,496.3 0.1 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information

B-7 

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

Kansas, cont. Hodgeman 8,460.7 2.7 <0.1 <0.1

Kearny 64,134.2 <0.1 <0.1 <0.1

Lane 5,628.3 0.8 <0.1 <0.1

Meade 55,958.2 <0.1 <0.1 <0.1

Morton 17,403.2 <0.1 <0.1 <0.1

Ness 1,478.3 1.6 0.1 0.2

Seward 57,443.7 <0.1 <0.1 <0.1

Sheridan 26,393.2 0.7 <0.1 <0.1

Stanton 41,420.2 <0.1 <0.1 <0.1

Stevens 72,124.0 0.1 <0.1 <0.1

Sumner 3,442.0 0.2 <0.1 <0.1

Louisiana Allen 8,942.5 0.1 <0.1 <0.1

Beauregard 10,161.6 2.3 <0.1 0.1

Bienville 4,810.7 108.9 2.3 10.0

Bossier 5,599.1 110.1 2.0 4.9

Caddo 53,644.1 153.6 0.3 1.7

Calcasieu 81,621.3 0.1 <0.1 <0.1

Caldwell 1,398.0 <0.1 <0.1 <0.1

Claiborne 952.7 3.8 0.4 1.1

DeSoto 13,373.6 1,085.9 8.1 47.4

East Feliciana 1,350.5 3.7 0.3 0.7

Jackson 1,456.4 <0.1 <0.1 <0.1

Lincoln 3,000.3 3.3 0.1 0.3

Natchitoches 12,530.5 12.7 0.1 0.2

Rapides 199,976.2 1.7 <0.1 <0.1

Red River 1,606.0 569.6 35.5 83.2
Appendix B – Water Acquisition Supplemental Information 

B-8 

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

Louisiana, cont. Sabine 1,522.1 395.2 26.0 76.6

Tangipahoa 7,329.2 1.9 <0.1 0.1

Union 1,481.9 4.9 0.3 1.0

Webster 2,664.5 1.2 <0.1 0.1

West Feliciana 15,191.3 2.3 <0.1 0.1

Winn 846.8 1.1 0.1 0.4

Michigan Cheboygan 2,777.7 <0.1 <0.1 <0.1

Gladwin 850.5 1.1 0.1 0.4

Kalkaska 1,233.7 24.0 1.9 3.7

Missaukee 1,423.5 <0.1 <0.1 <0.1

Ogemaw 1,179.0 <0.1 <0.1 <0.1

Roscommon 1,000.1 2.4 0.2 0.9

Mississippi Amite 792.1 14.4 1.8 3.8

Wilkinson 1,270.2 3.2 0.3 0.4

Montana Daniels 1,408.9 0.6 <0.1 0.1

Garfield 1,631.6 0.5 <0.1 <0.1

Glacier 46,760.2 5.1 <0.1 <0.1

Musselshell 26,827.5 0.4 <0.1 <0.1

Richland 94,797.8 83.5 0.1 0.1

Roosevelt 31,539.7 52.1 0.2 0.2

Rosebud 71,412.3 3.5 <0.1 <0.1

Sheridan 7,354.8 9.7 0.1 0.2

New Mexico Chaves 88,078.2 2.8 <0.1 <0.1

Colfax 17,450.7 0.7 <0.1 <0.1

Eddy 70,612.9 225.6 0.3 0.5
Appendix B – Water Acquisition Supplemental Information

B-9 

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

New Mexico,

cont.

Harding 1,168.0 0.1 <0.1 <0.1

Lea 64,057.5 113.7 0.2 0.3

Rio Arriba 39,080.6 16.5 <0.1 0.1

Roosevelt 63,367.7 <0.1 <0.1 <0.1

San Juan 125,432.3 11.6 <0.1 <0.1

Sandoval 23,922.1 0.4 <0.1 <0.1

North Dakota Billings 762.9 44.4 5.8 16.2

Bottineau 1,164.4 0.1 <0.1 <0.1

Burke 394.2 63.6 16.1 40.8

Divide 806.7 102.2 12.7 18.6

Dunn 1,076.8 309.5 28.7 43.1

Golden Valley 208.1 4.6 2.2 3.8

Mckenzie 13,753.2 588.4 4.3 6.2

Mclean 7,873.1 12.2 0.2 0.4

Mountrail 1,248.3 449.4 36.0 98.3

Stark 1,168.0 48.0 4.1 8.5

Williams 7,705.2 558.5 7.2 11.3

Ohio Ashland 2,033.1 1.5 0.1 0.2

Belmont 65,528.5 1.9 <0.1 0.1

Carroll 1,127.9 152.7 13.5 37.3

Columbiana 3,763.2 30.7 0.8 2.2

Coshocton 53,775.5 5.4 <0.1 0.1

Guernsey 2,379.8 8.4 0.4 0.7

Harrison 481.8 16.5 3.4 7.3

Jefferson 632,917.3 26.2 <0.1 0.1
Appendix B – Water Acquisition Supplemental Information 

B-10

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

Ohio, cont. Knox 3,270.4 1.1 <0.1 0.1

Medina 3,540.5 1.3 <0.1 0.1

Muskingum 6,018.9 5.1 0.1 0.3

Noble 478.2 8.3 1.7 3.4

Portage 18,414.3 3.2 <0.1 0.1

Stark 16,479.8 2.4 <0.1 <0.1

Tuscarawas 14,165.7 6.7 <0.1 0.2

Wayne 6,051.7 1.7 <0.1 0.1

Oklahoma Alfalfa 2,996.7 182.7 6.1 12.0

Beaver 15,341.0 23.1 0.2 0.3

Beckham 4,099.0 108.0 2.6 4.7

Blaine 3,763.2 203.3 5.4 9.3

Bryan 5,062.6 10.3 0.2 0.4

Caddo 24,064.5 25.4 0.1 0.3

Canadian 5,584.5 441.9 7.9 15.6

Carter 159,906.5 161.9 0.1 0.5

Coal 1,193.6 85.9 7.2 21.5

Custer 3,281.4 19.0 0.6 1.2

Dewey 10,953.7 162.6 1.5 6.2

Ellis 8,486.3 184.3 2.2 3.2

Garvin 16,279.0 15.0 0.1 0.4

Grady 13,537.9 111.5 0.8 2.3

Grant 5,569.9 77.8 1.4 5.2

Harper 3,266.8 8.8 0.3 0.4

Hughes 3,394.5 30.5 0.9 2.2

Jefferson 4,496.8 <0.1 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information

B-11

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

Oklahoma, 

cont.

Johnston 1,671.7 32.9 2.0 4.7

Kay 16,957.9 17.3 0.1 0.4

Kingfisher 3,744.9 10.2 0.3 0.5

Kiowa 5,022.4 0.1 <0.1 <0.1

Latimer 1,062.2 0.6 0.1 0.1

Le Flore 8,635.9 0.3 <0.1 <0.1

Logan 4,077.1 4.2 0.1 0.3

Love 2,011.2 4.4 0.2 0.5

Major 6,321.8 1.2 <0.1 <0.1

Marshall 2,613.4 98.4 3.8 7.2

McClain 2,952.9 2.1 0.1 0.2

Noble 12,990.4 25.3 0.2 1.8

Oklahoma 47,836.9 1.2 <0.1 <0.1

Osage 6,971.5 3.8 0.1 0.2

Pawnee 4,839.9 15.7 0.3 1.4

Payne 4,332.6 9.9 0.2 0.6

Pittsburg 6,314.5 349.0 5.5 16.0

Roger Mills 2,847.0 235.5 8.3 12.6

Seminole 124,837.3 0.1 <0.1 <0.1

Stephens 49,990.4 27.7 0.1 0.3

Texas 110,208.1 0.1 <0.1 <0.1

Washita 3,310.6 102.1 3.1 5.4

Woods 4,139.1 155.1 3.7 10.9
Appendix B – Water Acquisition Supplemental Information 

B-12

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

Pennsylvania Allegheny 234,140.2 13.6 <0.1 <0.1

Armstrong 65,853.3 55.7 0.1 1.8

Beaver 157,793.2 30.5 <0.1 0.2

Blair 8,303.8 5.9 0.1 0.2

Bradford 4,354.5 1,059.4 24.3 78.2

Butler 5,730.5 121.8 2.1 6.0

Cameron 292.0 6.6 2.3 4.1

Centre 16,560.1 38.5 0.2 0.5

Clarion 1,843.3 8.1 0.4 1.4

Clearfield 111,051.3 111.5 0.1 2.3

Clinton 6,161.2 94.4 1.5 3.0

Columbia 3,810.6 5.6 0.1 0.4

Crawford 5,091.8 2.4 <0.1 0.1

Elk 7,876.7 37.5 0.5 1.9

Fayette 16,465.2 120.2 0.7 2.7

Forest 744.6 7.7 1.0 1.6

Greene 13,023.2 359.0 2.8 24.7

Huntingdon 5,121.0 2.7 0.1 0.2

Indiana 21,819.7 16.2 0.1 0.7

Jefferson 1,730.1 13.8 0.8 1.7

Lawrence 36,598.6 27.0 0.1 1.0

Lycoming 5,854.6 704.6 12.0 33.8

McKean 4,723.1 60.5 1.3 4.9

Potter 2,281.3 16.5 0.7 1.0

Somerset 10,833.2 5.8 0.1 0.2

Sullivan 222.7 66.5 29.9 79.8
Appendix B – Water Acquisition Supplemental Information

B-13

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

Pennsylvania, 

cont.

Susquehanna 1,617.0 751.3 46.5 123.4

Tioga 2,909.1 566.3 19.5 47.3

Venango 2,989.4 2.4 0.1 0.3

Warren 5,099.1 2.3 <0.1 0.2

Washington 130,535.0 433.7 0.3 4.6

Westmoreland 14,607.3 207.0 1.4 3.8

Wyoming 4,788.8 150.0 3.1 15.2

Texas Andrews 23,363.7 236.2 1.0 2.7

Angelina 5,540.7 0.8 <0.1 <0.1

Archer 2,536.8 0.1 <0.1 <0.1

Atascosa 15,038.0 327.3 2.2 4.0

Austin 2,555.0 2.1 0.1 0.1

Bee 3,087.9 20.0 0.6 1.1

Borden 2,427.3 8.0 0.3 1.0

Bosque 3,544.2 0.7 <0.1 <0.1

Brazos 24,790.8 7.7 <0.1 0.1

Brooks 1,204.5 1.5 0.1 0.3

Burleson 10,694.5 3.0 <0.1 <0.1

Cherokee 24,845.6 0.5 <0.1 <0.1

Clay 1,963.7 <0.1 <0.1 <0.1

Cochran 24,035.3 3.0 <0.1 <0.1

Coke 12,713.0 0.3 <0.1 <0.1

Colorado 52,465.1 0.1 <0.1 <0.1

Concho 2,832.4 <0.1 <0.1 <0.1

Cooke 4,533.3 454.3 10.0 29.9
Appendix B – Water Acquisition Supplemental Information 

B-14

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, cont. Cottle 733.7 0.3 <0.1 0.1

Crane 8,566.6 92.3 1.1 5.7

Crockett 4,281.5 279.0 6.5 29.5

Crosby 27,261.9 1.3 <0.1 <0.1

Culberson 14,311.7 37.7 0.3 0.4

Dallas 112,204.7 5.6 <0.1 <0.1

Dawson 28,842.3 17.5 0.1 0.1

DeWitt 2,394.4 546.6 22.8 48.6

Denton 60,684.9 455.0 0.7 2.3

Dimmit 4,073.4 1,794.2 44.0 81.3

Ector 21,958.4 226.5 1.0 4.6

Edwards 332.2 <0.1 <0.1 <0.1

Ellis 8,530.1 4.2 <0.1 0.1

Erath 5,876.5 0.8 <0.1 <0.1

Fayette 9,008.2 13.7 0.2 1.2

Fisher 2,854.3 1.8 0.1 0.1

Franklin 1,956.4 <0.1 <0.1 <0.1

Freestone 297,861.9 53.9 <0.1 0.5

Frio 20,589.7 127.5 0.6 0.9

Gaines 121,778.6 21.6 <0.1 <0.1

Garza 5,234.1 0.6 <0.1 <0.1

Glasscock 20,680.9 598.1 2.9 4.2

Goliad 142,963.2 <0.1 <0.1 <0.1

Gonzales 7,121.2 577.9 8.1 17.6

Grayson 8,143.2 9.3 0.1 0.3

Gregg 33,010.6 9.4 <0.1 0.2
Appendix B – Water Acquisition Supplemental Information

B-15

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, cont. Grimes 112,500.3 15.5 <0.1 0.3

Hansford 43,643.1 2.9 <0.1 <0.1

Hardeman 2,230.2 0.4 <0.1 <0.1

Hardin 2,376.2 0.1 <0.1 <0.1

Harrison 11,869.8 141.6 1.2 6.0

Hartley 113,555.2 1.9 <0.1 <0.1

Haskell 12,143.6 0.1 <0.1 <0.1

Hemphill 3,150.0 263.9 8.4 16.3

Hidalgo 171,630.3 8.0 <0.1 <0.1

Hockley 46,314.9 3.0 <0.1 <0.1

Hood 9,351.3 76.0 0.8 2.2

Houston 3,686.5 8.6 0.2 0.6

Howard 10,811.3 97.6 0.9 2.7

Hutchinson 34,437.8 0.3 <0.1 <0.1

Irion 1,335.9 411.4 30.8 74.5

Jack 2,241.1 14.0 0.6 2.2

Jefferson 88,585.5 <0.1 <0.1 <0.1

Jim Hogg 306.6 0.1 <0.1 0.1

Johnson 9,241.8 582.0 6.3 18.5

Jones 5,679.4 <0.1 <0.1 <0.1

Karnes 1,861.5 1,055.2 56.7 120.1

Kenedy 456.3 0.2 0.1 0.1

Kent 6,132.0 0.4 <0.1 <0.1

King 1,485.6 <0.1 <0.1 <0.1

Kleberg 1,171.7 3.4 0.3 0.5

Knox 9,800.3 <0.1 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information 

B-16

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, cont. La Salle 2,474.7 1,288.7 52.1 93.7

Lavaca 3,763.2 45.0 1.2 2.0

Lee 3,120.8 1.2 <0.1 0.1

Leon 2,171.8 56.2 2.6 6.6

Liberty 20,662.7 <0.1 <0.1 <0.1

Limestone 11,158.1 10.7 0.1 0.9

Lipscomb 11,015.7 89.0 0.8 1.1

Live Oak 1,916.3 294.0 15.3 40.1

Loving 781.1 138.4 17.7 94.1

Lynn 19,892.5 1.1 <0.1 <0.1

Madison 1,554.9 45.3 2.9 8.2

Marion 3,606.2 5.9 0.2 0.9

Martin 14,063.5 432.0 3.1 4.7

Maverick 20,498.4 52.4 0.3 0.4

McMullen 657.0 745.9 113.5 350.4

Medina 19,228.2 0.2 <0.1 <0.1

Menard 1,014.7 <0.1 <0.1 <0.1

Midland 12,891.8 307.4 2.4 3.7

Milam 16,665.9 4.9 <0.1 0.1

Mitchell 6,559.1 11.0 0.2 0.3

Montague 3,989.5 925.3 23.2 77.8

Montgomery 32,565.3 0.2 <0.1 <0.1

Moore 57,075.1 <0.1 <0.1 <0.1

Nacogdoches 5,891.1 271.7 4.6 12.5

Navarro 18,699.0 4.8 <0.1 0.1

Newton 2,263.0 0.2 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information

B-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

Texas, cont. Nolan 4,124.5 4.5 0.1 0.2

Nueces 85,767.7 1.0 <0.1 <0.1

Ochiltree 21,348.9 33.3 0.2 0.2

Oldham 2,124.3 1.3 0.1 0.1

Orange 150,128.2 0.3 <0.1 <0.1

Palo Pinto 18,403.3 9.6 0.1 0.3

Panola 6,365.6 346.5 5.4 20.7

Parker 8,241.7 261.7 3.2 9.8

Pecos 52,954.2 8.2 <0.1 <0.1

Polk 204,009.5 0.2 <0.1 <0.1

Potter 2,029.4 0.4 <0.1 <0.1

Reagan 9,333.1 410.5 4.4 7.8

Reeves 20,772.2 164.2 0.8 1.1

Roberts 7,690.6 38.2 0.5 1.2

Robertson 158,344.3 45.4 <0.1 0.2

Runnels 2,847.0 <0.1 <0.1 <0.1

Rusk 582,134.9 65.8 <0.1 0.3

Sabine 799.4 31.1 3.9 13.9

San Augustine 1,131.5 182.1 16.1 50.8

San Patricio 4,172.0 1.1 <0.1 <0.1

Schleicher 967.3 27.0 2.8 5.0

Scurry 14,187.6 1.1 <0.1 <0.1

Shelby 4,920.2 133.6 2.7 8.2

Sherman 78,073.5 <0.1 <0.1 <0.1

Smith 11,231.1 0.2 <0.1 <0.1

Somervell 746,005.3 4.8 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information 

B-18

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, cont. Starr 9,552.1 5.0 0.1 0.1

Stephens 13,446.6 2.6 <0.1 0.1

Sterling 719.1 36.6 5.1 11.9

Stonewall 923.5 0.9 0.1 0.3

Sutton 1,153.4 1.6 0.1 0.3

Tarrant 104,430.2 1,443.0 1.4 3.9

Terrell 543.9 0.1 <0.1 <0.1

Terry 48,362.5 7.5 <0.1 <0.1

Tyler 1,872.5 0.1 <0.1 <0.1

Upshur 8,610.4 0.2 <0.1 <0.1

Upton 7,975.3 462.6 5.8 14.2

Van Zandt 4,139.1 0.1 <0.1 <0.1

Walker 4,478.6 3.4 0.1 0.2

Waller 9,829.5 0.1 <0.1 <0.1

Ward 6,909.5 107.3 1.6 4.6

Washington 2,430.9 2.2 0.1 0.2

Webb 15,862.9 1,117.8 7.0 18.2

Wharton 81,606.7 <0.1 <0.1 <0.1

Wheeler 6,522.6 858.0 13.2 21.5

Wichita 25,936.9 0.1 <0.1 <0.1

Wilbarger 12,683.8 0.2 <0.1 <0.1

Willacy 15,209.6 0.1 <0.1 <0.1

Wilson 7,843.9 84.5 1.1 1.7

Winkler 5,274.3 7.7 0.1 0.5

Wise 24,966.0 529.7 2.1 8.9

Wood 19,334.1 0.2 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information

B-19

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, cont. Yoakum 77,325.3 7.5 <0.1 <0.1

Young 21,162.7 0.1 <0.1 <0.1

Zapata 2,697.4 1.1 <0.1 0.1

Zavala 14,410.2 130.0 0.9 1.3

Utah Carbon 15,067.2 7.3 <0.1 0.1

Duchesne 119,811.3 85.5 0.1 0.1

San Juan 10,632.5 0.3 <0.1 <0.1

Sevier 52,512.6 <0.1 <0.1 <0.1

Uintah 100,229.0 157.5 0.2 0.2

Virginia Buchanan 313.9 0.6 0.2 0.3

Dickenson 1,741.1 0.8 <0.1 0.2

Wise 1,927.2 0.1 <0.1 <0.1

West Virginia Barbour 773.8 19.9 2.6 6.9

Brooke 4,551.6 54.8 1.2 5.1

Doddridge 405.2 78.5 19.4 69.4

Hancock 28,718.2 1.2 <0.1 <0.1

Harrison 20,232.0 40.2 0.2 1.9

Lewis 901.6 2.4 0.3 0.8

Marion 5,982.4 70.1 1.2 4.9

Marshall 158,358.9 84.5 0.1 0.7

Monongalia 42,102.8 6.8 <0.1 0.1

Ohio 3,825.2 116.5 3.0 10.4

Pleasants 24,703.2 <0.1 <0.1 <0.1

Preston 2,890.8 8.4 0.3 1.4

Ritchie 587.7 2.8 0.5 1.7

Taylor 824.9 52.9 6.4 17.6

Tyler 4,934.8 2.1 <0.1 0.2

Upshur 1,814.1 34.9 1.9 6.8
Appendix B – Water Acquisition Supplemental Information 

B-20

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

West Virginia, 

cont.

Webster 1,292.1 2.3 0.2 0.3

Wetzel 1,467.3 78.2 5.3 11.9

Wyoming Big Horn 143,368.4 2.9 <0.1 <0.1

Campbell 44,318.3 11.7 <0.1 0.1

Carbon 137,130.5 4.5 <0.1 <0.1

Converse 56,972.9 106.8 0.2 0.3

Fremont 186,150.0 28.2 <0.1 <0.1

Goshen 144,248.0 5.8 <0.1 <0.1

Hot Springs 28,572.2 0.3 <0.1 <0.1

Johnson 43,205.1 <0.1 <0.1 <0.1

Laramie 86,297.0 18.3 <0.1 <0.1

Lincoln 74,562.2 0.8 <0.1 <0.1

Natrona 62,885.9 1.8 <0.1 <0.1

Niobrara 25,148.5 0.1 <0.1 <0.1

Park 111,317.7 0.9 <0.1 <0.1

Sublette 61,006.1 314.8 0.5 0.7

Sweetwater 61,699.6 39.4 0.1 0.1

Uinta 79,518.9 0.6 <0.1 <0.1

Washakie 60,400.2 1.1 <0.1 <0.1

a County-level data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on November 11, 2014. Total 

daily water withdrawals were multiplied by 365 days to estimate total water use for the year (Maupin et al., 2014). 

b Average of water used for hydraulic fracturing in 2011 and 2012, based on the EPA FracFocus 1.0 project database (U.S. EPA, 

2015c). 

c Percentages were calculated by averaging annual water use for hydraulic fracturing in the EPA FracFocus 1.0 project database 

in 2011 and 2012 for a given county (U.S. EPA, 2015c), and then dividing by 2010 USGS total water use for that county (Maupin 

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 a rate of 71.6% for aquaculture 

(Verdegem and Bosma, 2009) (evaporation per kg fish + infiltration per kg)/(total water use per kg)*100. These rates were 

multiplied by each USGS water use value (Maupin et al., 2014) to yield a total water consumption estimate. To calculate a 

consumption amount for hydraulic fracturing, we used a consumption rate of 82.5%. This was calculated by taking the median 

value for all reported produced water/injected water percentages in Tables 7-1 and 7-2 of this assessment and then subtracting 

from 100%. If a range of values was given, the midpoint was used. Note that this is likely a low estimate of consumption since 

much of this return water is not subsequently treated and reused, but rather disposed of in injection wells—see Chapter 8. 
Appendix B – Water Acquisition Supplemental Information

B-21

Table B-3. Comparison of water use per well estimates from the EPA FracFocus 1.0 project 

database (U.S. EPA, 2015c) and literature sources. 

State Basina

Water use per well 

(gal) - EPA FracFocus 

1.0 project database

estimateb

Water use per well (gal)

- Literature estimateb,c

EPA FracFocus 1.0

project database

estimate as a 

percentage of 

literature estimate 

(%)

Colorado Denver 403,686 2,900,000 14

North Dakota - 2,140,842 2,200,000 97

Oklahoma - 2,591,778 3,000,000 86

Pennsylvaniad- 4,301,701 4,450,000 97

Texas Fort Worth 3,881,220 4,500,000 86

Texas Salt 3,139,980 4,000,000 78

Texas Western Gulf 3,777,648 4,600,000 82

Averagee- - - 77

Mediane- - - 86

a In cases where a basin is not specified, estimates were for the entire state and not specific to a particular basin. Basin 

boundaries for the EPA FracFocus 1.0 project database estimates were determined from data from the U.S. EIA (U.S. EPA, 

2015b). 

b The type of literature estimate determined the specific comparison with the EPA FracFocus 1.0 project database. If averages 

were given in the literature (as for North Dakota and Pennsylvania), those values were compared with EPA FracFocus 1.0 

project database averages; where medians were given in the literature (as for Colorado, Oklahoma, and Texas), they were 

compared with EPA FracFocus 1.0 project database medians. 

c Literature estimates were from the following sources: Colorado (Goodwin et al., 2014), North Dakota (North Dakota State 

Water Commission, 2014), Pennsylvania (Mitchell et al., 2013), and Texas (Nicot and Scanlon, 2012)—see far right-column and 

footnotes in Table B-5 for details on literature estimates. Where the literature provided a range, the mid-point was used. Only 

literature estimates that were not directly derived from FracFocus were included. 

d The results from Mitchell et al. (2013) were used for Pennsylvania since they were derived from Pennsylvania Department of 

Environment Protection (PA DEP) records. Estimates from Hansen et al. (2013) were not included here because they were 

based on data from the FracFocus national registry. 

e Average and median percentage calculations were not weighted by the number of wells for a given estimate.
Appendix B – Water Acquisition Supplemental Information 

B-22

Table B-4. Comparison of well counts from the EPA FracFocus 1.0 project database (U.S. EPA, 2015c) and state databases for 

North Dakota, Pennsylvania, and West Virginia. 

EPA FracFocus 1.0 project database

well countsaState database well counts

EPA FracFocus 1.0 project database

counts as a percentage 

of state database counts

State 2011 2012 Total 2011 2012 Total 2011 2012 Total

North Dakotab 613 1,458 2,071 1,225 1,740 2,965 50% 84% 70%

Pennsylvaniac 1,137 1,257 2,394 1,963 1,347 3,310 58% 93% 72%

West Virginiad 93 176 269 214 251 465 43% 70% 58%

Average - - - - - - 50% 82% 67%

a EPA FracFocus 1.0 project database wells counts (U.S. EPA, 2015c). 

b For North Dakota state well counts, we used a North Dakota Department of Mineral Resources online database containing a list of horizontal wells completed in the Bakken 

Formation. Data for North Dakota were accessed on July 9, 2014 at https://www.dmr.nd.gov/oilgas/bakkenwells.asp. 

c For Pennsylvania state well counts, we used completed horizontal wells as a proxy for hydraulically fractured wells in the state. The Pennsylvania Department of Environmental 

Protection has online databases of permitted and spudded wells, which differentiate between conventional and unconventional wells and can generate summary statistics at 

both the county and state scale. The number of spudded wells (i.e., wells drilled) provided a better comparison with the number of hydraulically fractured wells in the EPA 

FracFocus 1.0 project database than that of permitted wells. The number of permitted wells was nearly double that of spudded in 2011 and 2012, indicating that almost half of 

the wells permitted were not drilled in that same year. Therefore, we used spudded wells here. Data for Pennsylvania were accessed on February 11, 2014 from 

http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx?/Oil_Gas/Spud_External_Data.

d For West Virginia state well counts, data on the number of hydraulically fractured wells per year were received from the West Virginia Department of Environmental Protection 

on February 25, 2014.
Appendix B – Water Acquisition Supplemental Information

B-23

Table B-5. Water use per hydraulically fractured well as reported in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c) by 

state and basin, covering the time period of January 2011 through February 2013. 

This table highlights 15 of the 20 states accounting for almost all disclosures reported in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). All EPA 

FracFocus 1.0 project database estimates were limited to disclosures with valid state, county, and volume information. Other literature estimates are also 

included where available. NA indicates other literature estimates were not available. 

State Basin/Totala

Number of 

disclosures

Mean 

(gal)

Median 

(gal)

10th 

percentile 

(gal)

90th

percentile 

(gal) Literature estimates

Arkansas Arkoma 1,423 5,190,254 5,259,965 3,234,963 7,121,249 NA

Total 1,423 5,190,254 5,259,965 3,234,963 7,121,249 NA

California San Joaquin 677 131,653 77,238 22,100 285,029 NA

Other 34 132,391 36,099 13,768 361,192 NA

Total 711 131,689 76,818 21,462 285,306 130,000 gal (average)b

Colorado Denver 3,166 753,887 403,686 143,715 2,588,946 2.9 million gal (median, Wattenberg 

field of Niobrara play)c

Uinta-Piceance 1,520 2,739,523 1,798,414 840,778 5,066,380 NA

Raton 146 108,003 95,974 24,917 211,526 NA

Other 66 605,740 183,408 34,412 601,816 NA

Total 4,898 1,348,842 463,462 147,353 3,092,024 NA

Kansas Total 121 1,135,973 1,453,788 10,836 2,227,926 NA

Louisiana TX-LA-MS Salt 939 5,289,100 5,116,650 2,851,654 7,984,838 NA

Other 27 896,899 232,464 87,003 3,562,400 NA

Total 966 5,166,337 5,077,863 1,812,099 7,945,630 NA

Montana Williston 187 1,640,085 1,552,596 375,864 3,037,398 NA

Other 20 945,541 1,017,701 157,639 1,575,197 NA

Total 207 1,572,979 1,455,757 367,326 2,997,552 NA
Appendix B – Water Acquisition Supplemental Information 

B-24

State Basin/Totala

Number of 

disclosures

Mean 

(gal)

Median 

(gal)

10th 

percentile 

(gal)

90th

percentile 

(gal) Literature estimates

New Mexico Permian 732 991,369 426,258 89,895 2,502,923 NA

San Juan 363 159,680 97,734 27,217 313,919 NA

Other 50 33,787 8,358 1,100 98,841 NA

Total 1,145 685,882 175,241 35,638 1,871,666 NA

North Dakota Williston 2,109 2,140,842 2,022,380 969,380 3,313,482 NA

Total 2,109 2,140,842 2,022,380 969,380 3,313,482 2.2 million gal (average)d

Ohio Appalachian 146 4,206,955 3,887,499 2,885,568 5,571,027 NA

Total 146 4,206,955 3,887,499 2,885,568 5,571,027 NA

Oklahoma Anadarko 935 3,742,703 3,259,774 1,211,700 6,972,652 Many formations reportede

Arkoma 158 6,323,750 6,655,929 172,375 9,589,554 Many formations reportede

Ardmore 98 6,637,332 8,021,559 81,894 8,835,842 Many formations reportede

Other 592 1,963,480 1,866,144 1,319,247 2,785,352 NA

Total 1,783 3,539,775 2,591,778 1,260,906 7,402,230 3 million gal (median)e

Pennsylvania Appalachian 2,445 4,301,701 4,184,936 2,313,649 6,615,981 4.1-4.6 million gal (average, Marcellus 

play, Susquehanna River Basin)f

Total 2,445 4,301,701 4,184,936 2,313,649 6,615,981 4.1-4.5g and 4.3-4.6h million gal 

(average)

Texas Permian 8,419 1,068,511 841,134 40,090 1,814,633 Many formations reportedi

Western Gulf 4,549 3,915,540 3,777,648 173,832 6,786,052 4.5−4.7 million gal (median, Eagle 

Ford play)i

Fort Worth 2,564 3,880,724 3,881,220 923,381 6,649,406 4.5 million gal (median, Barnett play)i

TX-LA-MS Salt 626 4,261,363 3,139,980 193,768 10,010,707 6−7.5 million gal (median, TexasHaynesville play) and 0.5-1 million gal

(median, Cotton Valley play)i
Appendix B – Water Acquisition Supplemental Information

B-25

State Basin/Totala

Number of 

disclosures

Mean 

(gal)

Median 

(gal)

10th 

percentile 

(gal)

90th

percentile 

(gal) Literature estimates

Texas, cont. Anadarko 604 4,128,702 3,341,310 492,421 8,292,996 Many formations reportedi

Other 120 1,601,897 184,239 21,470 5,678,588 NA

Total 16,882 2,494,452 1,420,613 58,709 6,115,195 Not reported by statei

Utah Uinta-Piceance 1,396 375,852 304,105 77,166 770,699 NA

Other 10 58,874 56,245 28,745 97,871 NA

Total 1,406 373,597 302,075 76,286 769,360 NA

West Virginia Appalachian 273 5,034,217 5,012,238 3,170,210 7,297,080 NA

Total 273 5,034,217 5,012,238 3,170,210 7,297,080 4.7-6 million gal (average)g

Wyoming Greater Green River 861 841,702 752,979 147,020 1,493,266 NA

Powder River 351 739,129 5,927 5,353 2,863,182 NA

Other 193 613,618 41,664 22,105 1,818,606 NA

Total 1,405 784,746 322,793 5,727 1,837,602 NA

a Basin boundaries for the EPA FracFocus 1.0 project database well locations were determined from data from the U.S. EIA (U.S. EPA, 2015b). 

b Literature estimates for California were from a California Council on Science and Technology report using data from FracFocus (CCST, 2014). 

c Literature estimates for the Denver Basin were from Goodwin et al. (2014). Goodwin et al. (2014) assessed 200 randomly sampled wells in the Wattenberg Field of the Denver 

Basin (Niobrara Play), using industry data for wells operated by Noble Energy, drilled between January 1, 2010, and July 1, 2013. Water consumption is reported rather than 

water use, but Goodwin et al. (2014) assume, based on Noble Energy practices, that water use and water consumption were identical because none of the flowback or produced 

water is reused for hydraulic fracturing. Goodwin et al. reported drilling water consumed, hydraulic fracturing water consumed, and total water consumed. We present hydraulic 

fracturing water consumption here (hydraulic fracturing water consumption was approximately 95% of the total). 

d Literature estimates for North Dakota were from an informational bulletin from the North Dakota State Water Commission (2014). No further information was available. 

e Murray (2013), who assessed water use for oil and gas operations from 2000−2010 for eight formations in Oklahoma using data from the Oklahoma Corporation Commission. It 

is not possible to extract an estimate corresponding to 2011–2012 from Murray without the raw data, because medians were presented for the 10-year period rather than 

separated by year. 

f The range of average annual water use per hydraulically fractured well in the Susquehanna River Basin for 2011 and 2012, calculated from SRBC (2016). 

g Hansen et al. (2013), using data from FracFocus via Skytruth for Pennsylvania as a whole, the range of annual averages is reported for 2011 and 2012. Similarly, for West 

Virginia, the range of annual averages is reported for 2011 and 2012 (partial year). 
Appendix B – Water Acquisition Supplemental Information 

B-26

h Mitchell et al. (2013), using data reported to the Pennsylvania Department of Environmental Protection. Mitchell et al. (2013) reported water use in the Ohio River Basin for 

2011 and 2012 (partial year) for horizontal and vertical wells. Here we report results for horizontal wells, which made up the majority of wells over the two-year period (i.e., 

93%, 1,191 horizontal wells versus 96 vertical wells). A range is reported as before because the average water use differed between the two years. 

i Literature estimates for Texas were from Nicot et al. (2012), using proprietary data from IHS. In most cases, Nicot et al. (2012) reported at the play scale or smaller, rather than 

the EIA basin scale used for the EPA FracFocus 1.0 project database. We reference 2011 and 2012 (partial year) for Nicot et al. (2012) where possible to overlap with the period 

of study for the EPA FracFocus 1.0 project database, though more years were available for most formations. A range is reported for some medians because median water use 

was different for the two years. There were five formations reported for the Permian Basin (Wolfberry, Wolfcamp, Canyon, Clearfork, and San Andres-Greyburg). The most 

active area in the Permian Basin in 2011−2012 was the Wolfberry, which reported a median of 1 to 1.1 million gal (3.8 to 4.2 million L) per well—these were mostly vertical wells. 

For the TX-LA-MS Salt Basin Nicot et al. (2012) reported two formations (TX-Haynesville and Cotton Valley), with similar levels of activity in 2011-2012. Wells in TX-Haynesville 

were predominantly horizontal, while those in Cotton Valley were predominantly vertical (though horizontal wells in Cotton Valley were also reported). There were three fields 

reported in the Anadarko Basin (Granite Wash, Cleveland, and Marmaton). The most active area in the Anadarko Basin in 2011-2012 was the Granite Wash, which reported a 

median of 3.3 to 5.2 million gal (12 to 20 million L) per well and where wells were mostly horizontal. 
Appendix B – Water Acquisition Supplemental Information

B-27

Table B-6. Estimated percent domestic use water from groundwater and self-supplied by 

county in 2010. 

Counties listed contained hydraulically fractured wells with valid state, county, and volume information (U.S. EPA, 

2015c). Data estimated from the USGS Water Census (Maupin et al., 2014). 

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Alabama Jefferson 11.9 0.8

Tuscaloosa 10.7 6.1

Arkansas Cleburne 0.0 0.0

Conway 8.6 8.6

Faulkner 48.0 3.5

Independence 20.5 9.4

Logan 0.0 0.0

Sebastian 0.0 0.0

Van Buren 6.4 6.4

White 0.4 0.0

Yell 1.8 1.8

California Colusa 97.9 10.3

Glenn 96.5 21.6

Kern 74.5 1.7

Los Angeles 45.0 4.2

Sutter 19.4 4.6

Ventura 30.9 3.9

Colorado Adams 18.1 2.8

Arapahoe 19.3 1.3

Boulder 1.7 1.5

Broomfield 0.0 0.0

Delta 59.6 28.4

Dolores 55.2 51.4

El Paso 19.6 5.1

Elbert 100.0 75.2

Fremont 15.6 15.6
Appendix B – Water Acquisition Supplemental Information 

B-28

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Colorado, cont. Garfield 36.7 28.5

Jackson 84.4 40.7

La Plata 24.4 11.3

Larimer 2.3 0.8

Las Animas 26.3 16.0

Mesa 7.3 6.2

Moffat 36.4 25.8

Morgan 57.9 4.9

Phillips 100.0 25.3

Rio Blanco 60.2 32.5

Routt 22.6 5.9

San Miguel 71.4 32.5

Weld 4.7 0.7

Yuma 100.0 38.1

Kansas Barber 100.0 19.0

Clark 100.0 24.2

Comanche 100.0 19.2

Finney 100.0 2.1

Grant 100.0 23.8

Gray 100.0 36.4

Harper 100.0 10.3

Haskell 100.0 35.2

Hodgeman 100.0 42.3

Kearny 100.0 14.6

Lane 100.0 24.1

Meade 100.0 25.4

Morton 100.0 21.7

Ness 100.0 24.2

Seward 100.0 15.7
Appendix B – Water Acquisition Supplemental Information

B-29

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Kansas, cont. Sheridan 100.0 44.9

Stanton 100.0 29.8

Stevens 100.0 25.9

Sumner 51.3 0.0

Louisiana Allen 100.0 7.5

Beauregard 100.0 20.6

Bienville 100.0 16.8

Bossier 29.4 14.6

Caddo 12.2 8.8

Calcasieu 98.3 12.7

Caldwell 100.0 6.5

Claiborne 100.0 10.4

DeSoto 55.8 21.8

East Feliciana 100.0 11.8

Jackson 100.0 13.8

Lincoln 100.0 4.2

Natchitoches 23.2 11.4

Rapides 100.0 3.3

Red River 83.2 27.6

Sabine 67.5 36.2

Tangipahoa 100.0 26.9

Union 100.0 11.2

Webster 100.0 11.3

West Feliciana 100.0 2.4

Winn 100.0 16.4

Michigan Cheboygan 100.0 76.4

Gladwin 100.0 84.5

Kalkaska 100.0 89.0

Missaukee 100.0 90.6
Appendix B – Water Acquisition Supplemental Information 

B-30

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Michigan, cont. Ogemaw 100.0 90.8

Roscommon 100.0 91.9

Mississippi Amite 100.0 26.0

Wilkinson 100.0 11.1

Montana Daniels 100.0 29.4

Garfield 100.0 70.0

Glacier 62.1 17.7

Musselshell 89.9 54.5

Richland 100.0 30.8

Roosevelt 84.2 20.9

Rosebud 51.3 10.3

Sheridan 100.0 31.0

New Mexico Chaves 100.0 11.8

Colfax 30.7 2.6

Eddy 100.0 2.2

Harding 100.0 25.0

Lea 100.0 17.4

Rio Arriba 84.0 42.3

Roosevelt 100.0 8.9

San Juan 14.6 12.9

Sandoval 98.9 23.2

North Dakota Billings NA 33.3

Bottineau 100.0 13.7

Burke 100.0 12.5

Divide 100.0 12.5

Dunn 100.0 21.4

Golden Valley 100.0 7.7

Mckenzie 75.8 15.7

Mclean 12.5 9.9
Appendix B – Water Acquisition Supplemental Information

B-31

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

North Dakota, cont. Mountrail 65.7 11.5

Stark NA 5.7

Williams 27.4 7.3

Ohio Ashland 98.8 57.4

Belmont 76.4 8.9

Carroll 96.4 76.4

Columbiana 63.2 43.2

Coshocton 99.3 34.9

Guernsey 37.6 9.5

Harrison 65.6 45.9

Jefferson 33.1 10.2

Knox 99.2 41.1

Medina 98.4 83.1

Muskingum 93.4 17.0

Noble 8.0 8.0

Portage 32.6 18.3

Stark 91.2 30.9

Tuscarawas 94.0 23.5

Wayne 99.1 49.0

Oklahoma Alfalfa 100.0 14.6

Beaver 100.0 47.9

Beckham 100.0 10.6

Blaine 100.0 8.8

Bryan 26.0 7.8

Caddo 45.4 35.1

Canadian 100.0 0.0

Carter 17.5 0.5

Coal 31.5 27.5

Custer 70.8 13.2
Appendix B – Water Acquisition Supplemental Information 

B-32

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Oklahoma, cont. Dewey 100.0 22.5

Ellis 100.0 31.4

Garvin 41.3 15.8

Grady 100.0 34.2

Grant 100.0 13.2

Harper 100.0 22.6

Hughes 23.6 6.7

Jefferson 13.5 1.8

Johnston 53.4 1.1

Kay 39.2 4.6

Kingfisher 100.0 28.3

Kiowa 10.3 0.0

Latimer 12.6 12.6

Le Flore 14.3 13.1

Logan 61.1 34.6

Love 100.0 3.8

Major 100.0 28.1

Marshall 20.1 4.4

Mcclain 95.9 23.9

Noble 23.3 14.3

Oklahoma 22.0 2.5

Osage 18.0 14.9

Pawnee 38.2 27.7

Payne 47.9 12.6

Pittsburg 0.6 0.0

Roger Mills 80.1 19.4

Seminole 78.8 16.1

Stephens 99.2 14.9

Texas 100.0 10.9
Appendix B – Water Acquisition Supplemental Information

B-33

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Oklahoma, cont. Washita 53.9 18.2

Woods 100.0 14.7

Pennsylvania Allegheny 15.7 15.3

Armstrong 45.3 36.8

Beaver 54.7 26.8

Blair 34.9 24.0

Bradford 100.0 65.2

Butler 51.8 42.8

Cameron 29.0 29.0

Centre 93.1 21.3

Clarion 61.5 55.8

Clearfield 38.4 22.7

Clinton 48.4 38.1

Columbia 77.5 56.7

Crawford 97.7 66.0

Elk 25.3 15.6

Fayette 19.2 16.1

Forest 100.0 78.3

Greene 31.9 31.9

Huntingdon 73.2 57.8

Indiana 52.2 49.1

Jefferson 60.7 46.1

Lawrence 40.5 38.8

Lycoming 60.0 29.3

McKean 56.6 33.3

Potter 93.7 58.1

Somerset 42.6 33.5

Sullivan 100.0 76.9

Susquehanna 79.9 74.7
Appendix B – Water Acquisition Supplemental Information 

B-34

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Pennsylvania, cont. Tioga 81.3 58.3

Venango 95.9 32.7

Warren 96.9 49.4

Washington 21.6 21.5

Westmoreland 21.3 19.8

Wyoming 100.0 70.6

Texas Andrews 100.0 23.4

Angelina 100.0 9.8

Archer 16.9 16.9

Atascosa 100.0 16.3

Austin 100.0 55.6

Bee 100.0 52.5

Borden 100.0 71.4

Bosque 88.7 30.3

Brazos 100.0 2.1

Brooks 100.0 35.3

Burleson 100.0 42.9

Cherokee 87.5 26.1

Clay 44.6 36.7

Cochran 100.0 23.3

Coke 29.0 28.9

Colorado 100.0 45.4

Concho 96.8 5.0

Cooke 75.5 8.9

Cottle 100.0 21.4

Crane 100.0 14.3

Crockett 100.0 42.5

Crosby 35.6 19.0

Culberson 100.0 13.8
Appendix B – Water Acquisition Supplemental Information

B-35

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Texas, cont. Dallas 1.0 0.7

Dawson 100.0 33.8

DeWitt 100.0 42.3

Denton 9.0 3.6

Dimmit 100.0 30.5

Ector 100.0 28.3

Edwards 100.0 42.1

Ellis 32.2 7.9

Erath 100.0 43.3

Fayette 100.0 27.6

Fisher NA 36.8

Franklin 0.9 0.0

Freestone 100.0 31.2

Frio 100.0 20.4

Gaines 100.0 45.5

Garza 20.1 17.2

Glasscock NA 100.0

Goliad NA 66.7

Gonzales 96.8 15.9

Grayson 56.0 4.2

Gregg 20.8 14.1

Grimes 100.0 26.0

Hansford 100.0 16.4

Hardeman 87.6 13.3

Hardin 100.0 29.5

Harrison 43.8 24.8

Hartley 100.0 39.7

Haskell 100.0 15.7

Hemphill 100.0 27.5
Appendix B – Water Acquisition Supplemental Information 

B-36

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Texas, cont. Hidalgo 9.2 1.6

Hockley 100.0 27.4

Hood 70.8 39.8

Houston 79.7 36.6

Howard 100.0 19.8

Hutchinson 27.3 14.9

Irion 100.0 50.0

Jack 46.7 43.8

Jefferson 25.0 5.8

Jim Hogg NA 25.0

Johnson 34.9 6.8

Jones 60.5 60.5

Karnes 100.0 17.6

Kenedy 100.0 25.0

Kent 100.0 37.5

King 100.0 33.3

Kleberg 100.0 1.9

Knox 86.2 24.2

La Salle 100.0 43.3

Lavaca 100.0 56.0

Lee 100.0 15.9

Leon 100.0 41.4

Liberty 98.5 42.5

Limestone 46.5 32.5

Lipscomb 100.0 23.5

Live Oak 32.8 32.1

Loving NA 0.0

Lynn 64.1 32.2

Madison 100.0 66.9
Appendix B – Water Acquisition Supplemental Information

B-37

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Texas, cont. Marion 13.7 8.4

Martin 100.0 48.9

Maverick 27.6 27.6

McMullen 100.0 40.0

Medina 98.0 23.6

Menard 36.4 36.4

Midland 100.0 22.1

Milam 82.5 41.1

Mitchell 100.0 14.7

Montague 57.1 49.7

Montgomery 100.0 26.6

Moore 100.0 8.1

Nacogdoches 55.6 21.6

Navarro 22.0 22.0

Newton 100.0 63.7

Nolan 100.0 17.6

Nueces 5.6 5.6

Ochiltree 100.0 16.8

Oldham 100.0 58.8

Orange 99.1 41.2

Palo Pinto 11.7 11.7

Panola 96.6 58.7

Parker 63.5 41.1

Pecos 100.0 31.3

Polk 41.9 41.7

Potter 100.0 12.6

Reagan 100.0 16.2

Reeves 100.0 31.1

Roberts 100.0 33.3
Appendix B – Water Acquisition Supplemental Information 

B-38

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Texas, cont. Robertson 97.1 22.5

Runnels 13.5 13.5

Rusk 90.7 41.8

Sabine 76.2 69.0

San Augustine 78.0 74.4

San Patricio 88.8 21.8

Schleicher 100.0 40.0

Scurry 32.5 27.7

Shelby 66.2 58.2

Sherman 100.0 33.3

Smith 48.0 13.7

Somervell 87.7 69.3

Starr 23.2 23.2

Stephens 13.5 13.5

Sterling NA 18.8

Stonewall NA 40.0

Sutton 100.0 26.7

Tarrant 3.7 1.3

Terrell 100.0 25.0

Terry 100.0 16.7

Tyler 100.0 73.6

Upshur 54.1 23.2

Upton 100.0 15.2

Van Zandt 65.7 39.0

Walker 57.7 30.6

Waller 100.0 37.2

Ward 100.0 4.5

Washington 48.2 36.0

Webb 99.4 0.5
Appendix B – Water Acquisition Supplemental Information

B-39

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

Texas, cont. Wharton 100.0 45.9

Wheeler 100.0 31.3

Wichita 8.8 2.9

Wilbarger 100.0 11.5

Willacy 28.4 28.4

Wilson 100.0 6.9

Winkler 100.0 3.8

Wise 51.3 50.4

Wood 21.3 12.9

Yoakum 100.0 36.0

Young 19.3 18.9

Zapata 13.9 13.9

Zavala 100.0 15.2

Utah Carbon 50.0 1.2

Duchesne 57.1 10.4

San Juan 68.3 47.5

Utah Sevier 100.0 10.0

Uintah 87.7 3.1

Virginia Buchanan NA 27.6

Dickenson 2.5 2.5

Wise 5.9 2.3

West Virginia Barbour 24.1 24.8

Brooke 33.4 6.8

Doddridge 60.6 62.1

Hancock 67.7 6.9

Harrison 8.8 8.9

Lewis 29.5 30.3

Marion 5.8 4.9

Marshall 96.5 12.0
Appendix B – Water Acquisition Supplemental Information 

B-40

State County

Percent domestic use 

water from groundwatera,b

Percent domestic use 

water self supplieda,c

West Virginia, cont. Monongalia 5.3 5.5

Ohio 5.4 3.4

Pleasants 100.0 27.9

Preston 66.1 41.0

Ritchie 45.2 46.4

Taylor 14.9 14.9

Tyler 44.4 39.2

Upshur 27.3 27.8

Webster 41.9 43.2

Wetzel 96.3 28.6

Wyoming Big Horn 79.4 11.3

Campbell 100.0 0.6

Carbon 63.8 6.7

Converse 96.5 17.0

Fremont 49.3 23.7

Goshen 100.0 21.1

Hot Springs 31.9 8.2

Johnson 40.8 35.4

Laramie 38.1 13.0

Lincoln 82.4 9.0

Natrona 69.0 6.6

Niobrara 100.0 16.3

Park 18.9 13.7

Sublette 54.6 22.1

Sweetwater 3.5 0.4

Uinta 19.5 11.5

Washakie 100.0 16.0

a Data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on November 11, 2014. Domestic water 

use is water used for indoor household purposes such as drinking, food preparation, bathing, washing clothes and dishes, 

flushing toilets, and outdoor purposes such as watering lawns and gardens (Maupin et al., 2014). 

b Percent domestic water use from groundwater estimated with the following equation: (Domestic public supply volume from 

groundwater + Domestic self-supplied volume from groundwater)/ Domestic total water use volume * 100. Domestic public 

supply volume from groundwater was estimated by multiplying the volume of domestic water from public supply by the ratio of 

public supply volume from groundwater to total public supply volume.

c Percent domestic water use self-supplied estimated by dividing the volume of domestic water self-supplied by total domestic 

water use volume.
Appendix B – Water Acquisition Supplemental Information

B-41

Table B-7. Projected hydraulic fracturing water use by Texas counties between 2015 and 2060, expressed as a percentage of 2010

total county water use. 

Hydraulic fracturing water use data from Nicot et al. (2012). Total water use data from 2010 from the USGS Water Census (Maupin et al., 2014). All 254 Texas 

counties are listed by descending order of percentages in 2030.

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

McMullen 126.2 137.0 152.1 165.1 176.7 164.0 145.3 126.6 108.0 89.3

Irion 36.1 59.2 70.5 63.7 53.4 43.1 32.8 22.4 12.1 5.4

La Salle 58.4 58.3 59.7 60.8 61.9 54.6 45.3 36.0 26.7 17.4

San Augustine 60.2 56.2 52.2 48.2 44.2 40.2 36.2 32.1 28.1 24.1

Sterling 12.0 32.0 39.9 40.5 41.0 34.7 28.3 21.9 15.6 10.7

Dimmit 38.2 38.1 38.9 39.0 38.7 33.9 27.9 22.0 16.0 10.1

Sabine 9.6 19.2 28.7 38.3 35.1 31.9 28.7 25.6 22.3 19.2

Leon 9.9 19.3 27.0 34.6 32.9 29.0 25.1 21.2 17.3 13.5

Karnes 48.1 43.0 37.9 32.6 27.2 21.8 16.4 11.0 5.6 0.2

Loving 13.1 17.4 23.4 29.4 28.8 26.2 23.6 20.9 18.3 15.7

Shackelford 0.0 7.9 15.7 23.6 21.2 18.9 16.5 14.1 11.8 9.4

Madison 5.5 11.8 15.7 19.7 17.4 15.2 13.0 10.9 8.7 6.5

Schleicher 10.5 15.8 19.1 19.7 17.1 14.5 11.9 9.3 6.7 4.7

Sutton 0.0 11.0 15.1 19.1 23.2 20.6 18.1 15.5 12.9 10.3

Shelby 11.0 20.4 19.4 18.4 17.4 15.7 14.1 12.5 10.9 9.3

DeWitt 26.9 24.1 21.4 18.4 15.4 12.3 9.3 6.3 3.2 0.2

Hemphill 25.7 23.1 20.5 17.8 15.2 12.6 10.0 7.3 4.7 2.1

Terrell 0.0 9.7 13.2 16.8 20.4 18.2 15.9 13.6 11.3 9.0

Coryell 7.0 24.4 22.8 16.5 10.1 3.8 0.0 0.0 0.0 0.0
Appendix B – Water Acquisition Supplemental Information 

B-42

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Montague 28.6 24.5 20.4 16.3 12.2 8.2 4.1 0.0 0.0 0.0

Crockett 7.6 12.5 14.8 13.4 11.2 9.1 6.9 4.7 2.5 1.1

Upton 12.1 15.2 14.1 12.9 11.7 9.8 7.9 5.9 4.0 2.7

Borden 3.1 8.6 12.0 12.1 12.2 10.3 8.4 6.4 4.5 3.1

Live Oak 13.3 12.4 11.5 11.8 12.2 12.7 13.2 11.7 9.8 7.8

Reagan 11.2 14.0 12.7 11.3 9.9 8.1 6.4 4.6 2.8 1.6

Clay 3.2 5.9 8.6 11.3 10.3 9.4 8.4 7.5 6.6 5.6

Wheeler 17.6 15.3 13.1 10.8 8.6 6.3 4.1 1.8 0.0 0.0

Lavaca 7.9 13.2 12.0 10.7 9.4 8.1 6.7 5.4 4.0 2.7

Washington 0.0 6.7 11.8 10.7 9.6 8.6 7.5 6.4 5.3 4.3

Nacogdoches 7.9 11.4 10.7 10.0 9.2 8.3 7.5 6.6 5.7 4.9

Hill 17.1 14.7 12.2 9.8 7.3 4.9 2.4 0.0 0.0 0.0

Jack 3.5 5.3 7.1 8.8 7.9 7.1 6.2 5.3 4.4 3.5

Panola 7.2 10.2 9.2 8.5 7.7 7.0 6.3 5.5 4.8 4.0

Jim Hogg 4.8 6.4 8.0 8.0 6.9 6.0 4.9 3.9 2.9 1.8

Howard 4.4 7.1 8.5 8.0 6.8 5.6 4.4 3.2 2.1 1.3

Parker 3.7 5.0 6.3 7.6 6.8 6.1 5.3 4.5 3.8 3.0

Hamilton 8.8 10.7 8.9 7.1 5.3 3.5 1.8 0.0 0.0 0.0

Johnson 14.2 11.9 9.5 7.1 4.7 2.4 0.0 0.0 0.0 0.0

Midland 6.7 8.3 7.7 7.1 6.2 5.2 4.1 3.0 2.0 1.2

Kenedy 4.1 5.4 6.8 6.8 5.9 5.1 4.1 3.3 2.4 1.6

Fayette 3.9 8.4 7.6 6.6 5.5 4.4 3.4 2.3 1.2 0.2
Appendix B – Water Acquisition Supplemental Information

B-43

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Lee 2.1 4.1 5.3 6.5 5.8 5.1 4.3 3.6 2.9 2.1

Winkler 2.9 3.8 5.1 6.3 6.0 5.4 4.7 4.1 3.4 2.8

Wilson 6.7 7.7 7.0 6.2 5.4 4.6 3.9 3.1 2.3 1.5

Martin 5.7 7.1 6.5 6.0 5.3 4.4 3.5 2.6 1.8 1.2

Burleson 1.0 2.9 4.3 5.7 5.1 4.5 3.9 3.3 2.6 2.0

Atascosa 6.3 5.7 5.6 5.6 5.6 5.6 5.0 4.2 3.4 2.7

Bosque 1.8 3.0 4.3 5.5 5.1 4.6 4.2 3.7 3.2 2.8

Webb 7.5 7.1 6.3 5.4 4.6 3.8 3.1 2.3 1.4 0.5

Gonzales 8.0 7.1 6.2 5.3 4.4 3.6 2.7 1.8 0.9 0.0

Marion 1.1 2.4 3.8 5.1 5.2 4.7 4.2 3.7 3.2 2.7

Harrison 4.3 6.1 5.5 5.1 4.6 4.2 3.7 3.3 2.9 2.4

Eastland 0.0 3.9 5.9 5.0 4.2 3.3 2.5 1.7 0.8 0.0

Archer 1.0 2.4 3.6 4.9 4.5 4.1 3.7 3.3 2.9 2.5

Zavala 4.7 5.5 5.2 4.9 4.6 4.3 4.0 3.4 2.7 2.0

Roberts 6.9 6.0 5.1 4.2 3.4 2.5 1.6 0.7 0.0 0.0

Maverick 2.5 3.0 3.6 4.2 4.8 4.5 4.0 3.6 3.1 2.6

Cooke 11.9 9.3 6.7 4.1 1.5 0.0 0.0 0.0 0.0 0.0

Ward 2.7 3.2 4.2 4.1 4.0 3.6 3.2 2.7 2.3 1.9

Austin 0.0 1.2 2.5 3.7 3.4 3.0 2.6 2.2 1.9 1.5

Reeves 1.4 1.8 2.7 3.7 3.9 3.6 3.3 3.0 2.6 2.3

Glasscock 3.1 4.1 3.9 3.6 3.1 2.6 2.1 1.5 1.0 0.7

Tyler 1.9 2.6 3.2 3.2 2.8 2.4 2.0 1.6 1.1 0.7
Appendix B – Water Acquisition Supplemental Information 

B-44

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Hood 1.4 2.0 2.6 3.2 2.9 2.6 2.2 1.9 1.6 1.3

Garza 1.5 2.0 2.5 2.9 2.7 2.4 2.1 1.8 1.5 1.2

Andrews 2.3 3.0 2.9 2.7 2.6 2.3 2.0 1.7 1.4 1.1

Crane 1.3 1.7 2.1 2.6 3.1 2.8 2.5 2.2 1.9 1.7

Erath 0.9 1.4 1.9 2.4 2.2 2.0 1.8 1.6 1.4 1.2

Wise 3.6 3.2 2.8 2.4 2.0 1.6 1.2 0.8 0.4 0.0

Upshur 0.2 0.9 1.7 2.4 2.9 2.6 2.3 2.1 1.8 1.5

Mitchell 1.2 1.6 2.0 2.4 2.1 1.9 1.7 1.4 1.2 0.9

Ector 1.5 2.0 2.1 2.3 2.2 1.9 1.7 1.4 1.2 1.0

Culberson 0.3 0.4 1.3 2.2 2.9 2.6 2.4 2.1 1.9 1.6

Lipscomb 1.7 3.0 2.6 2.1 1.7 1.3 0.8 0.4 0.0 0.0

Angelina 0.4 0.9 1.5 2.1 2.2 2.0 1.8 1.6 1.4 1.2

Houston 2.1 2.7 2.4 2.1 1.8 1.5 1.2 0.9 0.6 0.3

Frio 1.8 1.8 1.9 1.9 1.8 1.8 1.7 1.5 1.2 0.9

Newton 1.8 2.3 2.1 1.8 1.6 1.3 1.0 0.8 0.5 0.3

Kleberg 1.0 1.4 1.7 1.7 1.5 1.3 1.1 0.8 0.6 0.4

Brooks 1.0 1.3 1.7 1.7 1.5 1.2 1.0 0.8 0.6 0.4

Brazos 0.4 0.9 1.2 1.5 1.4 1.2 1.0 0.8 0.7 0.5

Comanche 0.4 0.7 1.0 1.4 1.2 1.1 1.0 0.8 0.7 0.5

Ochiltree 0.6 1.1 1.5 1.2 1.0 0.7 0.5 0.2 0.0 0.0

Palo Pinto 0.3 0.6 0.9 1.2 1.1 1.0 0.8 0.7 0.6 0.5

Limestone 0.9 1.0 1.1 1.2 1.1 1.0 0.8 0.7 0.6 0.4
Appendix B – Water Acquisition Supplemental Information

B-45

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Duval 0.7 0.9 1.1 1.1 1.0 0.8 0.7 0.5 0.4 0.3

Stephens 0.1 0.4 0.8 1.1 1.0 0.9 0.8 0.6 0.5 0.4

Dawson 0.5 0.8 1.0 1.1 1.1 1.0 0.8 0.6 0.5 0.3

Scurry 0.0 0.6 0.8 1.0 1.2 1.1 0.9 0.8 0.7 0.5

Bee 0.8 1.1 1.1 1.0 0.9 0.7 0.6 0.4 0.3 0.1

Val Verde 0.0 0.5 0.8 0.9 1.1 1.0 0.9 0.8 0.6 0.5

Colorado <0.1 0.3 0.6 0.9 0.8 0.7 0.6 0.5 0.4 0.4

Tarrant 2.1 1.7 1.3 0.9 0.4 0.0 0.0 0.0 0.0 0.0

Zapata 0.5 0.7 0.8 0.8 0.7 0.6 0.5 0.4 0.3 0.2

Ellis 0.3 0.5 0.6 0.8 0.7 0.6 0.6 0.5 0.4 0.3

Jim Wells 0.4 0.6 0.7 0.7 0.6 0.5 0.4 0.4 0.3 0.2

Lynn 0.0 0.4 0.6 0.7 0.8 0.8 0.7 0.6 0.5 0.4

Henderson 0.1 0.3 0.5 0.7 0.8 0.7 0.6 0.5 0.4 0.4

Hansford 0.0 0.4 0.8 0.7 0.5 0.4 0.3 0.2 0.1 0

Gaines 0.2 0.3 0.5 0.5 0.5 0.4 0.4 0.3 0.2 0.2

Gregg 0.1 0.2 0.3 0.4 0.4 0.4 0.4 0.3 0.3 0.2

Refugio 0.2 0.3 0.4 0.4 0.3 0.3 0.2 0.2 0.1 0.1

Caldwell 0.4 0.5 0.4 0.4 0.3 0.3 0.2 0.2 0.1 0.1

Pecos 0.1 0.1 0.2 0.4 0.5 0.4 0.4 0.3 0.3 0.2

Anderson 0.1 0.2 0.3 0.4 0.4 0.4 0.4 0.3 0.3 0.2

Young 0.0 0.1 0.2 0.4 0.3 0.3 0.3 0.2 0.2 0.1

San Patricio 0.2 0.3 0.4 0.4 0.3 0.3 0.2 0.2 0.1 0.1
Appendix B – Water Acquisition Supplemental Information 

B-46

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Smith 0.1 0.1 0.2 0.3 0.4 0.3 0.3 0.3 0.2 0.2

Cherokee 0.1 0.2 0.2 0.3 0.4 0.3 0.3 0.2 0.2 0.2

McLennan 0.1 0.1 0.2 0.3 0.3 0.2 0.2 0.2 0.2 0.1

Terry 0.0 0.2 0.2 0.3 0.3 0.3 0.3 0.2 0.2 0.2

Starr 0.2 0.2 0.3 0.3 0.2 0.2 0.2 0.1 0.1 0.1

Cochran 0.1 0.2 0.2 0.2 0.3 0.2 0.2 0.2 0.2 0.1

Jasper 0.2 0.3 0.2 0.2 0.2 0.1 0.1 0.1 0.1 <0.1

Dallas 0.2 0.3 0.2 0.2 0.1 0.1 <0.1 0.0 0.0 0.0

Robertson 0.1 0.2 0.2 0.2 0.2 0.1 0.1 0.1 0.1 0.1

Grimes <0.1 0.1 0.1 0.2 0.1 0.1 0.1 0.1 0.1 0.1

Yoakum 0.1 0.1 0.2 0.2 0.1 0.1 0.1 0.1 0.1 0.1

Freestone 0.1 0.1 0.1 0.2 0.2 0.1 0.1 0.1 0.1 0.1

Cass <0.1 0.1 0.1 0.2 0.2 0.2 0.1 0.1 0.1 0.1

Hutchinson 0.0 0.1 0.2 0.1 0.1 0.1 0.1 <0.1 <0.1 0.0

Rusk <0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 <0.1

Willacy <0.1 0.1 0.1 0.1 0.1 0.1 0.1 <0.1 <0.1 <0.1

Victoria <0.1 0.1 0.1 0.1 0.1 0.1 <0.1 <0.1 <0.1 <0.1

Sherman 0.0 0.0 <0.1 0.1 0.1 0.1 <0.1 <0.1 <0.1 <0.1

Calhoun <0.1 0.1 0.1 0.1 0.1 0.1 <0.1 <0.1 <0.1 <0.1

Lubbock 0.0 0.0 <0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1

Jackson <0.1 <0.1 0.1 0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Matagorda <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1
Appendix B – Water Acquisition Supplemental Information

B-47

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Polk <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Wharton <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Nueces <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Hidalgo <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Cameron <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Somervell <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Goliad <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Brazoria <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Fort Bend <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1

Aransas 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Armstrong 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Bailey 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Bandera 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Bastrop 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Baylor 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Bell 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Bexar 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Blanco 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Bowie 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Brewster 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Briscoe 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Brown 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Appendix B – Water Acquisition Supplemental Information 

B-48

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Burnet 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Callahan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Camp 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Carson 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Castro 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Chambers 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Childress 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Coke 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Coleman 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Collin 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Collingsworth 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Comal 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Concho 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Cottle 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Crosby 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Dallam 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Deaf Smith 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Delta 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Denton 1.7 1.1 0.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Dickens 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Donley 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Edwards 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Appendix B – Water Acquisition Supplemental Information

B-49

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

El Paso 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Falls 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Fannin 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Fisher 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Floyd 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Foard 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Franklin 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Galveston 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Gillespie 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Gray 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Grayson 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Guadalupe 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hale 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hall 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hardeman 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hardin 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Harris 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hartley 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Haskell 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hays 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hockley 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hopkins 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Appendix B – Water Acquisition Supplemental Information 

B-50

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Hudspeth 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Hunt 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Jeff Davis 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Jefferson 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Jones 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kaufman 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kendall 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kent 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kerr 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kimble 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

King 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kinney 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Knox 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Lamar 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Lamb 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Lampasas 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Liberty 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Llano 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

McCulloch 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Mason 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Medina 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Menard 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Appendix B – Water Acquisition Supplemental Information

B-51

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Milam 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Mills 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Montgomery 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Moore 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Morris 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Motley 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Navarro 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Nolan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Oldham 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Orange 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Parmer 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Potter 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Presidio 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Rains 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Randall 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Real 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Red River 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Rockwall 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Runnels 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

San Jacinto 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

San Saba 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Stonewall 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Appendix B – Water Acquisition Supplemental Information 

B-52

Projected hydraulic fracturing water use as a percentage of 2010 total water usea,b,c

Texas county 2015 2020 2025 2030 2035 2040 2045 2050 2055 2060

Swisher 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Taylor 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Throckmorton 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Titus 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Tom Green 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Travis 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Trinity 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Uvalde 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Van Zandt 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Walker 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Waller 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Wichita 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Wilbarger 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Williamson 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Wood 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

a Total water use data accessed from the USGS website (http://water.usgs.gov/watuse/data/2010/) on April 21, 2015 (Maupin et al., 2014). Data from Nicot et al. (2012)

transcribed. 

b Percentages calculated by dividing projected hydraulic fracturing water use volumes from Nicot et al. (2012) by 2010 total water use from the USGS (Maupin et al., 2014) and 

multiplying by 100. Note, the projected hydraulic fracturing water use volume from Nicot et al. (2012) 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. 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). Estimates of projected hydraulic fracturing water use as a percentage of 2010 total water use exceeded 100% when 

projected hydraulic fracturing water use exceeded 2010 total water use in that county in 2010. 

c Percentages less than 0.1 were not rounded and simply noted as “<0.1,” but where the percentage was actually zero because there was no projected hydraulic fracturing water 

use we noted that as “0.0.”
Appendix B – Water Acquisition Supplemental Information

B-53

B.2. Supplemental Discussion: Potential for Water Acquisition Impacts by 

Location 

This section includes an expanded discussion of the potential for water acquisition impacts by 

location. This discussion provides further examples of the concepts illustrated in Chapter 4, Section 

4.5, and includes a discussion for Oklahoma and Kansas (Section B.2.1) and Utah, New Mexico, and 

California (Section B.2.2). 

B.2.1. Oklahoma and Kansas 

Oklahoma had the fifth most disclosures in the EPA FracFocus 1.0 project database (5.0% of 

disclosures) (Table B-5, Figure 4-4). Three major basins—the Anadarko, which includes the 

Woodford play; the Arkoma, which includes the Fayetteville play; and the Ardmore, which includes 

the Woodford play—contain 67% of the disclosures in Oklahoma (Table B-5, Figure B-1). Few wells 

were reported for Kansas (Kansas disclosures comprise 0.4% of the EPA FracFocus 1.0 project 

database), but because of the shared geology of the Cherokee Platform across the two states, we 

group Kansas with Oklahoma. Oklahoma and Kansas were two of the three states where a large 

fraction of wells were not associated with a basin defined by the U.S. EIA (U.S. EPA, 2015c) (Table 

B-5).1

Figure B-1. Major U.S. EIA shale plays and basins for Oklahoma and Kansas. 

Source: EIA (2015). 

 

1Alaska was the other state in the EPA FracFocus 1.0 project database where the U.S. EIA shale basins did not adequately 

describe well locations, with all 37 wells in Alaska not associated with a U.S. EIA basin. For all other states, U.S. EIA shale 

basins captured 86%−100% of the wells in the EPA FracFocus 1.0 project database (U.S. EPA, 2015c). 
Appendix B – Water Acquisition Supplemental Information 

B-54

Types of water used: Water for hydraulic fracturing in Oklahoma and Kansas comes from both 

surface and groundwater (Kansas Water Office, 2014; Taylor, 2012). Data on temporary water use 

permits in Oklahoma (which make up the majority of water use permits for Oklahoma oil and gas 

mining) show that, in 2011, approximately 63% and 37% of water for hydraulic fracturing came 

from surface and groundwater, respectively (Taylor, 2012) (Table 4-1). General water use in 

Oklahoma follows an east-west divide, with the eastern half dependent on surface sources and the 

western half relying heavily on groundwater (OWRB, 2014).Water obtained for fracturing is 

assumed to fit this pattern as well. No data are available on the proportion of hydraulic fracturing 

water that is sourced from surface versus groundwater resources in Kansas. 

For both Oklahoma and Kansas, data are also lacking to describe the extent to which reused 

wastewater is used as a percentage of total injected volume. However, the quality of Oklahoma’s 

Woodford Shale wastewater has been described as low in TDS, and thus reuse could reduce the 

demand for fresh water (Kuthnert et al., 2012). 

Water use per well: Estimates of median water use per well in Oklahoma include 2.6 million gal (9.8 

million L) and 3 million gal (11 million L) (U.S. EPA; Murray, 2013, respectively). Water use for 

hydraulic fracturing increased from 2000 to 2011, driven by volumes required for fracturing 

horizontal wells across the state (Murray, 2013). Within the state, there are wide ranges in water 

use for different formations. According to the EPA FracFocus 1.0 project database, the Ardmore and 

Arkoma Basins of Oklahoma had the highest median water use in the country, with medians of 8.0 

and 6.7 million gal (30.3 and 25.4 million L) per well, respectively; whereas the Anadarko Basin had 

lower median water use per well (3.3 million gal (12.5 million L) (Table B-5). Wells not associated 

with a U.S. EIA basin had a median of 1.9 million gal (7.2 million L) per well (Table B-5). It is not 

clear why lower water volumes were reportedly used in unassociated wells, but Oklahoma has 

several CBM deposits in the eastern part of the state where very low water use per well has been 

reported (i.e., less than approximately 300,000 gal (1.1 million L) in the Arbuckle and Hartshorne 

formations) (Murray, 2013). Median water use per well in Kansas was 1.5 million gal (5.7 million 

L), focused mostly in a five-county area in the south-central and southwest portions of the state 

(Table B-5).

Water use/consumption at the county scale: Operators reported using an average of 71.9 million gal 

(272.2 million L) of water annually in Oklahoma counties with reported fracturing activity in 2011 

and 2012; in Kansas, this value was 3.5 million gal (13.2 million L) (Table B-2). Average hydraulic 

fracturing water use in 2011 and 2012 did not exceed 10% of 2010 total water use in any county in 

Oklahoma or Kansas (Table B-2). However, there were six counties in Oklahoma (Alfalfa, Canadian, 

Coal, Pittsburg, Rogers Mills, and Woods) where fracturing water consumption exceeded 10% of 

2010 total county water consumption. 

Potential for impacts: The potential for impacts on drinking water resources appears to be low in 

Oklahoma and Kansas at the county scale, since hydraulic fracturing water use and consumption 

are generally low as a percentage of total water use, consumption, and availability at this scale 

(Text Box 4-2, Figure 4-6a,b). If local impacts to water quantity or quality do occur, they are more 

likely to happen in western Oklahoma than in the eastern half of the state or Kansas. Of the six 

Oklahoma counties where fracturing consumption exceeded 10% of 2010 water consumption, 
Appendix B – Water Acquisition Supplemental Information

B-55

three (Alfalfa, Canadian, and Roger Mills) are in the western half of the state where surface water 

availability is lowest (Figure 4-7a). Surface water is fully allocated in the Panhandle and West 

Central regions, encompassing much of the state’s northwestern quadrant (OWRB, 2014). As a 

result, residents generally rely on groundwater in western Oklahoma (Table B-6), and it is likely 

that fracturing does as well. 

Projecting out to 2060, Oklahoma’s Water Plan concludes that aquifer storage depletions are likely 

in the Panhandle and West Central regions due to over-pumping, particularly for irrigation (OWRB, 

2014). Groundwater depletions are anticipated to be small relative to storage, but will be the 

largest in summer months and may lead to higher pumping costs, the need for deeper water wells, 

lower water yields, and detrimental effects on water quality (OWRB, 2014). Drought conditions are 

likely to exacerbate this problem, and Oklahoma’s Water Plan raises the potential for climate 

change to affect future water supplies in the state (OWRB, 2014). In the adjacent Texas Panhandle, 

future irrigation needs may go unmet (TWDB, 2012), and this may be the case in western Oklahoma 

as well. 

Aquifer depletions in western Oklahoma may be associated with groundwater quality degradation, 

particularly under drought conditions. The central portion of the Ogallala aquifer underlying the 

Oklahoma Panhandle and western Oklahoma contains elevated levels of some constituents (e.g., 

nitrate) due to over-pumping, although generally it is of better quality than the southern portion of 

the aquifer (Gurdak et al., 2009). Additional groundwater withdrawals for hydraulic fracturing in 

western Oklahoma may add to these water quality issues, particularly in combination with other 

substantial water uses (e.g., irrigation) (Gurdak et al., 2009). 

B.2.2. Utah, New Mexico, and California 

Together, Utah, New Mexico, and California accounted for approximately 9% of disclosures in the 

EPA FracFocus 1.0 project database (3.8%, 3.1% and 1.9% of disclosures, respectively) (Table B-5, 

Figure 4-4). Almost all reported hydraulic fracturing in Utah and California was in the UintaPiceance Basin (99%) and San Joaquin Basin (95%), respectively. Activity in New Mexico mostly 

occurs in the Permian and San Juan Basins, which together comprised 96% of reported disclosures 

in that state (Figure B-2).
Appendix B – Water Acquisition Supplemental Information 

B-56

Figure B-2. Major U.S. EIA shale plays and basins for Utah, New Mexico, and California. 

Source: EIA (2015). 

Types of water used: Of these three states, California has the most information available on the 

sources of water used for hydraulic fracturing. Most current and proposed fracturing activity occurs 

in Kern County in the San Joaquin Basin, where operators depend mainly on surface water 

purchased from nearby irrigation districts (CCST, 2014). California irrigation districts receive water 

allocated by the State Water Project, and deliveries may be restricted or eliminated during drought 

years (CCST, 2014).1 In addition to publicly-supplied surface water, operators may also self-supply 

a smaller proportion of water from on-site groundwater wells (CCST, 2014). Most water used for 

hydraulic fracturing in California is fresh (91% of annual water used in well stimulation) (CCST, 

2015a). Approximately 13% of water demand for hydraulic fracturing is offset by the reuse of 

wastewater, according to well stimulation records (CCST, 2015a) (Table 4-2). 

The source, quality, and provisioning of water used for hydraulic fracturing in Utah and New 

Mexico are not as well characterized. A 2010 New Mexico water use report summarizes 

withdrawals for a variety of water use categories, and 26% and 74% of mining water use (which 

includes water used for oil and gas production) came from surface and groundwater withdrawals, 

respectively (NM OSE, 2013). If hydraulic fracturing water use in New Mexico follows the same 

pattern as other mining uses (e.g., for metals, coal, geothermal), then it is likely that groundwater is 

the primary source. To our knowledge, no data are available to characterize the source of water for 

 

1

 The California State Water Project is a water storage and distribution system maintained by the California Department of 

Water Resources, which provides water for urban and agricultural water suppliers in Northern California, the San 

Francisco Bay Area, the San Joaquin Valley, the Central Coast, and Southern California (California Department of Water 

Resources, 2015). 
Appendix B – Water Acquisition Supplemental Information

B-57

hydraulic fracturing operations in Utah. In addition, data are lacking on the reuse of wastewater as 

a proportion of total water injected for both Utah and New Mexico. 

Water use per well: Median water use per well in Utah, New Mexico, and California is lower than in 

other states in the EPA FracFocus 1.0 project database: Utah ranks 13th (approximately 302,000 gal 

or 1.14 million L), New Mexico ranks 14th (approximately 175,000 gal or 662,000 L), and California 

ranks 15th (approximately 77,000 gal or 291,000 L) out of the 15 states (Table B-5). A possible 

explanation for the low water use per well in Utah and New Mexico is the presence of CBM in the 

Uinta (Utah) and San Juan (New Mexico) Basins. Low water use per well in California is attributed 

to the prevalence of vertical wells and the use of crosslinked gels. Vertical wells dominate because 

the complex geology precludes long horizontal drilling and fracturing (CCST, 2014). 

For California, the California Council on Science and Technology (CCST) reports average water use 

per well of 130,000 gal (490,000 L), which agrees with the state average of approximately 131,700 

gal (498,500 L) according to the EPA FracFocus 1.0 project database (CCST, 2014) (Table B-5); this 

is to be expected, because estimates from CCST are also based on data submitted to FracFocus. 

Water use/consumption at the county scale: Hydraulic fracturing in Utah, New Mexico, and 

California uses relatively small amounts of water at the county scale compared to most other states 

(Table B-1). Only in four counties (Duchesne and Uintah Counties in Utah, and Eddy and Lea 

Counties in New Mexico) did hydraulic fracturing operators use more than 50 million gal (189 

million L) annually in 2011 and 2012 (Table B-2). Fracturing water use and consumption did not 

exceed 1% of 2010 total water use and consumption in any county. 

Potential for impacts: At present, hydraulic fracturing does not use or consume much water 

compared to other users or consumers in Utah, New Mexico, and California at the county scale 

(Figure 4-2a,b). Likewise, it also does not use much water compared to county level water 

availability estimates (Text Box 4-2, Figure 4-6a,b). In general, however, Utah, New Mexico, and 

California have low surface water availability (Figure 4-7a), high groundwater dependence (Figure 

4-7b), and have experienced frequent periods of drought over the last decade (National Drought 

Mitigation Center, 2015). All of these factors increase the potential for localized impacts. In 

California, two recent studies conclude changes in water quantity or quality are possible in the San 

Joaquin Basin due to hydraulic fracturing withdrawals, especially within Kern County where oil and 

gas activities are concentrated and fresh water is in limited supply (Tiedeman et al., 2016; CCST, 

2015a). The combination of factors also suggest future problems could arise if hydraulic fracturing 

water withdrawals increase substantially in these states beyond present levels, without 

commensurate steps to reduce fresh water demand. 
Appendix B – Water Acquisition Supplemental Information 

B-58

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Appendix C – Chemical Mixing Supplemental Information 

C-1 

Appendix C. Chemical Mixing Supplemental 

Information 
Appendix C – Chemical Mixing Supplemental Information 

C-2 

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Appendix C – Chemical Mixing Supplemental Information 

C-3 

Appendix C. Chemical Mixing Supplemental Information 

C.1. Most Frequently Reported Chemicals in Gas- and Oil-Producing Wells 

Table C-1. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0 project 

database for gas-producing wells, with the number of disclosures (for reported chemicals), 

percentage of disclosures, and the median maximum concentration (% by mass) of that 

chemical in hydraulic fracturing fluid. 

Chemicals ranked by frequency of occurrence (U.S. EPA, 2015c). See Text Box 5-2 for more information. 

Chemical name CASRN

Number of 

disclosures

Percentage of 

disclosures

Median maximum 

concentration in hydraulic 

fracturing fluid (% by mass)

Hydrochloric acid 7647-01-0 12,351 72.8% 15%

Methanol 67-56-1 12,269 72.3% 30%

Distillates, petroleum, 

hydrotreated light 64742-47-8 11,897 70.1% 30%

Isopropanol 67-63-0 8,008 47.2% 30%

Water 7732-18-5 7,998 47.1% 63%

Ethanol 64-17-5 6,325 37.3% 5%

Propargyl alcohol 107-19-7 5,811 34.2% 10%

Glutaraldehyde 111-30-8 5,635 33.2% 30%

Ethylene glycol 107-21-1 5,493 32.4% 35%

Citric acid 77-92-9 4,832 28.5% 60%

Sodium hydroxide 1310-73-2 4,656 27.4% 5%

Peroxydisulfuric acid, 

diammonium salt 7727-54-0 4,618 27.2% 100%

Quartz 14808-60-7 3,758 22.1% 10%

2,2-Dibromo-3-

nitrilopropionamide 10222-01-2 3,668 21.6% 100%

Sodium chloride 7647-14-5 3,608 21.3% 30%

Guar gum 9000-30-0 3,586 21.1% 60%

Acetic acid 64-19-7 3,563 21.0% 50%

2-Butoxyethanol 111-76-2 3,325 19.6% 10%

Naphthalene 91-20-3 3,294 19.4% 5%

Solvent naphtha, petroleum, 

heavy arom.

64742-94-5 3,287 19.4% 30%
Appendix C – Chemical Mixing Supplemental Information 

C-4 

Chemical name CASRN

Number of 

disclosures

Percentage of 

disclosures

Median maximum 

concentration in hydraulic 

fracturing fluid (% by mass)

Quaternary ammonium 

compounds, benzyl-C12-16-

alkyldimethyl, chlorides

68424-85-1 3,259 19.2% 7%

Potassium hydroxide 1310-58-3 2,843 16.8% 15%

Ammonium chloride 12125-02-9 2,483 14.6% 10%

Choline chloride 67-48-1 2,477 14.6% 75%

Poly(oxy-1,2-ethanediyl)-

nonylphenyl-hydroxy (mixture) 127087-87-0 2,455 14.5% 5%

Sodium chlorite 7758-19-2 2,372 14.0% 10%

1,2,4-Trimethylbenzene 95-63-6 2,229 13.1% 1%

Carbonic acid, dipotassium salt 584-08-7 2,154 12.7% 60%

Methenamine 100-97-0 2,134 12.6% 1%

Formic acid 64-18-6 2,118 12.5% 60%

Didecyl dimethyl ammonium 

chloride 7173-51-5 2,063 12.2% 10%

N,N-Dimethylformamide 68-12-2 1,892 11.2% 13%

Phenolic resin 9003-35-4 1,852 10.9% 5%

Thiourea polymer 68527-49-1 1,702 10.0% 30%

Polyethylene glycol 25322-68-3 1,696 10.0% 60%
Appendix C – Chemical Mixing Supplemental Information 

C-5 

Table C-2. Chemicals reported in 10% or more of disclosures in the EPA FracFocus 1.0 project 

database for oil-producing wells, with the number of disclosures (for reported chemicals), 

percentage of disclosures, and the median maximum concentration (% by mass) of that 

chemical in hydraulic fracturing fluid. 

Chemicals ranked by frequency of occurrence (U.S. EPA, 2015c). 

Chemical name CASRN

Number of 

disclosures

Percentage of 

disclosures

Median maximum 

concentration in 

hydraulic fracturing 

fluid (% by mass)

Methanol 67-56-1 12,484 71.8% 30%

Distillates, petroleum, hydrotreated 

light 64742-47-8 10,566 60.8% 40%

Peroxydisulfuric acid, diammonium salt 7727-54-0 10,350 59.6% 100%

Ethylene glycol 107-21-1 10,307 59.3% 30%

Hydrochloric acid 7647-01-0 10,029 57.7% 15%

Guar gum 9000-30-0 9,110 52.4% 50%

Sodium hydroxide 1310-73-2 8,609 49.5% 10%

Quartz 14808-60-7 8,577 49.4% 2%

Water 7732-18-5 8,538 49.1% 67%

Isopropanol 67-63-0 8,031 46.2% 15%

Potassium hydroxide 1310-58-3 7,206 41.5% 15%

Glutaraldehyde 111-30-8 5,927 34.1% 15%

Propargyl alcohol 107-19-7 5,599 32.2% 5%

Acetic acid 64-19-7 4,623 26.6% 30%

2-Butoxyethanol 111-76-2 4,022 23.1% 10%

Solvent naphtha, petroleum, heavy 

arom.

64742-94-5 3,821 22.0% 5%

Sodium chloride 7647-14-5 3,692 21.2% 25%

Ethanol 64-17-5 3,536 20.3% 45%

Citric acid 77-92-9 3,310 19.0% 60%

Phenolic resin 9003-35-4 3,109 17.9% 5%

Naphthalene 91-20-3 3,060 17.6% 5%

Nonyl phenol ethoxylate 9016-45-9 2,829 16.3% 20%

Diatomaceous earth, calcined 91053-39-3 2,655 15.3% 100%
Appendix C – Chemical Mixing Supplemental Information 

C-6 

Chemical name CASRN

Number of 

disclosures

Percentage of 

disclosures

Median maximum 

concentration in 

hydraulic fracturing 

fluid (% by mass)

Methenamine 100-97-0 2,559 14.7% 1%

Tetramethylammonium chloride 75-57-0 2,428 14.0% 1%

Carbonic acid, dipotassium salt 584-08-7 2,402 13.8% 60%

Ethoxylated propoxylated C12-14 

alcohols 68439-51-0 2,342 13.5% 2%

Choline chloride 67-48-1 2,264 13.0% 75%

Boron sodium oxide 1330-43-4 2,228 12.8% 30%

Tetrakis(hydroxymethyl)phosphonium 

sulfate 55566-30-8 2,130 12.3% 50%

1,2,4-Trimethylbenzene 95-63-6 2,118 12.2% 1%

Boric acid 10043-35-3 2,070 11.9% 25%

Polyethylene glycol 25322-68-3 2,025 11.7% 5%

2-Mercaptoethanol 60-24-2 2,012 11.6% 100%

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 1,988 11.4% 98%

Formic acid 64-18-6 1,948 11.2% 60%

Sodium persulfate 7775-27-1 1,914 11.0% 100%

Phosphonic acid 13598-36-2 1,865 10.7% 1%

Sodium tetraborate decahydrate 1303-96-4 1,862 10.7% 30%

Potassium metaborate 13709-94-9 1,682 9.7% 60%

Ethylenediaminetetraacetic acid 

tetrasodium salt hydrate 64-02-8 1,676 9.6% 0%

Poly(oxy-1,2-ethanediyl)-nonylphenylhydroxy (mixture) 127087-87-0 1,668 9.6% 5%
Appendix C – Chemical Mixing Supplemental Information 

C-7 

C.2. Most Frequently Reported Chemicals for Each State 

Table C-3a. Chemicals most frequently reported in disclosures in the EPA FracFocus 1.0 project database for each state and 

number (and percentage) of disclosures where a chemical is reported for that state, Alabama to Montana. 

The 20 most frequently reported hydraulic fracturing fluid chemicals were identified for the 20 states that reported in disclosures in the EPA FracFocus 1.0 

project database, resulting in a total of 93 chemicals. The chemicals were ranked by counting the number of states where that chemical was in the top 20; 

chemicals used most widely among the most states come first. For example, methanol is reported in 19 of 20 states, so methanol is ranked first (U.S. EPA, 

2015c). 

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Methanol 67-56-1

55

(100%)

1333 

(99.7%)

228 

(39.0%)

2883 

(63.3%)

77 

(79.4%)

596 

(59.2%)

13 

(92.9%)

3 

(75%)

121 

(62.7%)

Distillates, 

petroleum, 

hydrotreated light

64742-47-8

9 

(45%)

743 

(55.6%)

322 

(55.0%)

3358 

(73.7%)

87 

(89.7%)

844 

(83.9%)

14 

(100%)

4 

(100%)

115 

(59.6%)

Ethylene glycol 107-21-1

55 

(100%)

20 

(100%)

291 

(21.8%)

350 

(59.8%)

61 

(62.9%)

341 

(33.9%)

10 

(71.4%)

3 

(75%)

95 

(49.2%)

Isopropanol 67-63-0

55 

(100%)

13 

(65%)

586 

(43.9%)

2586 

(56.8%)

24 

(24.7%)

515 

(51.2%)

11 

(78.6%)

123 

(63.7%)

Quartz 14808-60-7

20 

(100%)

519 

(88.7%)

1048 

(23.0%)

22 

(22.7%)

377 

(37.5%)

2 

(50%)

124 

(64.2%)

Sodium hydroxide 1310-73-2

20 

(100%)

285 

(21.3%)

403 

(68.9%)

996 

(21.9%)

27 

(27.8%)

535

(53.2%)

2 

(50%)

105 

(54.4%)

Ethanol 64-17-5

603 

(45.1%)

2258 

(49.6%)

78 

(80.4%)

420 

(41.7%)

4 

(100%)

Guar gum 9000-30-0

10 

(50%)

545 

(93.2%)

494 

(49.1%) 2 (50%) 83 (43.0%)

Hydrochloric acid 7647-01-0

55 

(100%)

1330

(99.5%)

2408 

(52.9%)

82 

(84.5%)

569 

(56.6%)

45 

(23.3%)

Peroxydisulfuric acid, 

diammonium salt 7727-54-0

10 

(50%)

484 

(82.7%)

21 

(21.6%)

273 

(27.2%)

8 

(57.1%)

119 

(61.7%)

Propargyl alcohol 107-19-7

813 

(60.8%)

69 

(71.1%)

299 

(29.7%)

5

(35.7%)
Appendix C – Chemical Mixing Supplemental Information 

C-8 

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Glutaraldehyde 111-30-8

737 

(55.1%)

73 

(75.3%)

364 

(36.3%)

2 

(50%)

Naphthalene 91-20-3

55 

(100%)

1363

(29.9%)

41

(42.3%)

293

(29.2%)

12 

(85.7%)

95 

(49.2%)

2-Butoxyethanol 111-76-2

55 

(100%)

20 

(100%)

11 

(78.6%)

Citric acid 77-92-9

45 

(46.4%)

Saline 7647-14-5

1574 

(34.5%)

408 

(40.6%)

2 

(50%)

Solvent naphtha, 

petroleum, heavy 

arom.

64742-94-5

1507

(33.1%)

42

(43.3%)

135 

(70.0%)

Quaternary 

ammonium 

compounds, benzylC12-16-

alkyldimethyl, 

chlorides

68424-85-1

375 

(28.0%)

52 

(53.6%)

2 

(50%)

2,2-Dibromo-3-

nitrilopropionamide 10222-01-2

55 

(100%)

2215

(48.6%)

10 

(71.4%)

70 

(36.3%)

Potassium hydroxide 1310-58-3

340 

(33.8%)

4 

(100%)

115

(59.6%)

Choline chloride 67-48-1

1235

(27.1%)

Polyethylene glycol 25322-68-3

55 

(100%)

7 

(50%)

69 

(35.8%)

1,2,4-

Trimethylbenzene 95-63-6

1211 

(26.63%)

39 

(40.2%)

Ammonium chloride 12125-02-9

277 

(20.7%)

1280

(28.0%)
Appendix C – Chemical Mixing Supplemental Information 

C-9 

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Diatomaceous earth, 

calcined 91053-39-3

20 

(100%)

417 

(71.3%)

Didecyl dimethyl 

ammonium chloride 7173-51-5

317 

(23.7%)

2 

(50%)

Sodium chlorite 7758-19-2

352 

(35.0%)

4 

(100%)

Sodium erythorbate 6381-77-7

435 

(32.5%)

29 

(29.9%)

N,NDimethylformamide 68-12-2

Nonyl phenol 

ethoxylate 9016-45-9

Poly(oxy-1,2-

ethanediyl)-

nonylphenyl-hydroxy 

(mixture)

127087-87-

0

1150 

(25.2%)

39 

(40.2%)

Sodium persulfate 7775-27-1

4 

(100%)

Tetramethylammoni

um chloride 75-57-0

85

(44.0%)

1,2-Propylene glycol 57-55-6

10 

(71.4%)

5-Chloro-2-methyl3(2H)-isothiazolone 26172-55-420 

(100%)

389 

(66.5%)

Acetic acid 64-19-7

959 

(21.0%)

284

(28.2%)

Ammonium acetate 631-61-8

2 

(50%)

Boric acid 10043-35-3

3 

(15%)
Appendix C – Chemical Mixing Supplemental Information 

C-10

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Carbonic acid, 

dipotassium salt 584-08-7

1159

(25.4%)

Cristobalite 14464-46-1

20 

(100%)

389 

(66.5%)

Formic acid 64-18-6 55 (100%) 293 

(29.1%)

Hemicellulase 

enzyme

9012-54-8

Hemicellulase 

enzyme concentrate

9025-56-3

395 

(67.5%)

Iron(II) sulfate 

heptahydrate 7782-63-0

7 

(50%)

Magnesium chloride 7786-30-3

20 

(100%)

389 

(66.5%)

Magnesium nitrate 10377-60-3

20 

(100%)

389 

(66.5%)

Phenolic resin 9003-35-4

Sodium hypochlorite 7681-52-9

1046

(23.0%)

Sodium tetraborate 

decahydrate 1303-96-4

14 

(70%)

Solvent naphtha, 

petroleum, heavy 

aliph.

64742-96-7

7 

(50%)

2 

(50%)

1-Butoxy-2-propanol 5131-66-8

315 

(53.8%)

1-Propanol 71-23-8

1232

(27.0%)
Appendix C – Chemical Mixing Supplemental Information 

C-11

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

1,2-

Ethanediaminium, N, 

N'-bis[2-[bis(2-

hydroxyethyl)methyl

ammonio]ethyl]-

N,N'bis(2-

hydroxyethyl)-N,N'-

dimethyl-

,tetrachloride

138879-

94-4

343 

(58.6%)

2-bromo-3-

nitrilopropionamide 1113-55-9

2-Ethylhexanol 104-76-7

83 

(43.0052%)

2-Methyl-3(2H)-

isothiazolone 2682-20-4

20 

(100%)

389 

(66.5%)

2-Propenoic acid, 

polymer with 2-

propenamide

9003-06-9

Alkenes, C>10 

.alpha.-

64743-02-8

241 

(18.0%)

Benzene, 1,1'-oxybis-

, tetrapropylene 

derivs., sulfonated

119345-

03-8

50 

(25.9%)

Benzenesulfonic acid, 

dodecyl-, compd. 

with N1-(2-

aminoethyl)-1,2-

ethanediamine (1:?)

40139-72-8

48 

(24.9%)

Benzyldimethyldodec

ylammonium 

chloride

139-07-1

268 

(20.0%)

Benzylhexadecyldime

thylammonium 

chloride

122-18-9

268 

(20.0%)
Appendix C – Chemical Mixing Supplemental Information 

C-12

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Boron sodium oxide 1330-43-4

361 

(61.7%)

C10-C16 ethoxylated 

alcohol 68002-97-1

3 

(15%)

Calcium chloride 10043-52-4

20 

(100%)

Carbon dioxide 124-38-9

7 

(50%)

Cinnamaldehyde (3-

phenyl-2-propenal) 104-55-2

55 

(100%)

Diethylene glycol 111-46-6

Diethylene glycol 

monobutyl ether 112-34-5

7 

(50%)

Diethylenetriamine 111-40-0

55 

(28.5%)

Distillates, 

petroleum, 

hydrotreated light 

paraffinic

64742-55-8

314 

(53.7%)

Distillates, 

petroleum, 

hydrotreated middle

64742-46-7

3 

(15%)

Ethoxylated C12-16 

alcohols 68551-12-2

Ethoxylated C14-15 

alcohols 68951-67-7

241 

(18.0%)

Formic acid, 

potassium salt 590-29-4

Glycerin, natural 56-81-5

7 

(50%)
Appendix C – Chemical Mixing Supplemental Information 

C-13

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Isotridecanol, 

ethoxylated 9043-30-5

312 

(53.3%)

Methenamine 100-97-0

298

(29.6%)

Naphtha, petroleum, 

hydrotreated heavy 64742-48-9

Poly(oxy-1,2-

ethanediyl), .alpha.,

.alpha.'-[[(9Z)-9-

octadecenylimino]di2,1-ethanediyl]

bis[.omega.-hydroxy26635-93-8

9 

(64.3%)

Potassium chloride 7447-40-7

7 

(50%)

Sodium bromate 7789-38-0

7 

(50%)

Sodium perborate 

tetrahydrate 10486-00-7

Sulfamic acid 5329-14-6

2 

(50%)

Terpenes and 

Terpenoids, sweet 

orange-oil

68647-72-3

2 

(50%)

Tetradecyl dimethyl 

benzyl ammonium 

chloride

139-08-2

268 

(20.0%)

Tetrakis(hydroxymet

hyl)phosphonium 

sulfate

55566-30-8

Thiourea polymer 68527-49-1

384

(28.7%)
Appendix C – Chemical Mixing Supplemental Information 

C-14

Chemical name CASRN Alabama Alaska Arkansas California Colorado Kansas Louisiana Michigan Mississippi Montana

Tri-n-butyl tetradecyl 

phosphonium 

chloride

81741-28-8

Trisodium phosphate 7601-54-9

19

(19.6%)
Appendix C – Chemical Mixing Supplemental Information 

C-15

Table C-3b. Chemicals most frequently reported in disclosures in the EPA FracFocus 1.0 project database for each state and 

number (and percentage) of disclosures where a chemical is reported for that state, New Mexico to Wyoming. 

The 20 most frequently reported hydraulic fracturing fluid chemicals were identified for the 20 states that reported in disclosures in the EPA FracFocus 1.0 

project database, resulting in a total of 93 chemicals. The chemicals were ranked by counting the number of states where that chemical was in the top 20; 

chemicals used most widely among the most states come first. For example, methanol is reported in 19 of 20 states, so methanol is ranked first (U.S. EPA, 

2015c). 

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

Methanol 67-56-1

1012 

(90.8%)

1059 

(53.3%)

76 

(52.1%)

1270 

(70.3%)

1633 

(68.6%)

12664 

(78.5%)

984 

(78.5%)

48 

(60.8%)

153 

(64.0%)

460 

(38.4%)

Distillates, petroleum, 

hydrotreated light 64742-47-8

699 

(62.7%)

943 

(47.5%)

122 

(83.6%)

1270 

(70.3%)

1434 

(60.2%)

10677 

(66.1%)

934 

(74.5%)

196 

(82.0%)

612 

(51.1%)

Ethylene glycol 107-21-1

503 

(45.1%)

724 

(36.4%)

83 

(56.8%)

843 

(46.7%)

807 

(33.9%)

9591 

(59.4%)

1065 

(85.0%)

22 

(27.8%)

141 

(59.0%)

Isopropanol 67-63-0

695 

(62.3%)

739 

(37.2%)

71 

(48.6%)

764 

(42.28%)

735 

(30.9%)

7731 

(47.9%)

661 

(52.8%)

43 

(54.4%)

74 

(31.0%)

516 

(43.1%)

Quartz 14808-60-7

762 

(68.3%)

920 

(46.3%)

66

(45.2%)

491 

(27.2%)

6869 

(42.6%)

503 

(40.1%)

53 

(22.2%)

356 

(29.7%)

Sodium hydroxide 1310-73-2

329 

(29.5%)

1028 

(51.7%)

490 

(27.1%)

406 

(17.0%)

7371 

(45.7%)

466 

(37.2%)

688 

(57.4%)

Ethanol 64-17-5

529 

(47.4%)

545 

(27.4%)

87 

(59.6%)

838 

(46.4%)

388 

(16.3%)

3439 

(21.3%)

50 

(63.3%)

130 

(54.3%)

298 

(24.9%)

Guar gum 9000-30-0

702 

(63.0%)

1094 

(55.1%)

74 

(50.7%)

457 

(25.3%)

538 

(22.6%)

6863 

(42.5%)

538 

(42.9%)

55 

(23.0%)

823 

(68.7%)

Hydrochloric acid 7647-01-0

880 

(78.9%)

145 

(99.3%)

1372 

(75.9%)

2279 

(95.7%)

11424 

(70.8%)

1064 

(84.9%)

68 

(86.1%)

229 

(95.8%)

Peroxydisulfuric acid, 

diammonium salt 7727-54-0

836 

(75.0%)

1089 

(54.8%)

93 

(63.7%)

713 

(39.5%)

8666 

(53.7%)

483 

(38.5%)

128 

(53.6%)

771 

(64.4%)

Propargyl alcohol 107-19-7

760 

(68.2%)

72 

(49.3%)

732 

(40.5%)

1371 

(57.6%)

6269 

(38.8%)

456 

(36.4%)

22 

(27.8%)

138 

(57.7%)
Appendix C – Chemical Mixing Supplemental Information 

C-16

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

Glutaraldehyde 111-30-8

632 

(56.7%)

105 

(71.9%)

989 

(54.7%)

819 

(34.4%)

6470 

(40.1%)

169 

(70.7%)

260 

(21.7%)

Naphthalene 91-20-3

864 

(43.5%)

448 

(24.8%)

478 

(38.1%)

7 

(8.9%)

2-Butoxyethanol 111-76-2

412 

(37.0%)

498 

(20.9%)

3898 

(24.1%)

663 

(52.9%)

70 

(88.6%)

62 

(25.9%)

Citric acid 77-92-9

447 

(40.1%)

96 

(65.8%)

644 

(35.6%)

701 

(29.4%)

3820 

(23.7%)

992 

(79.2%)

63 

(79.8%)

98 

(41.0%)

Saline 7647-14-5

491 

(24.7%)

3462 

(21.4%)

7 

(8.9%)

53 

(22.2%)

274 

(22.9%)

Solvent naphtha, 

petroleum, heavy arom. 64742-94-5

981 

(49.4%)

557 

(30.8%)

2751 

(17.0%)

7 

(8.9%)

415 

(34.6%)

Quaternary ammonium 

compounds, benzyl-C12-

16-alkyldimethyl, 

chlorides

68424-85-1

54 

(37.0%)

597 

(33.0%)

373 

(15.7%)

53 

(22.2%)

2,2-Dibromo-3-

nitrilopropionamide 10222-01-2

804 

(33.8%)

22 

(27.8%)

Potassium hydroxide 1310-58-3

1176 

(59.2%)

106 

(72.6%)

6369 

(39.5%)

Choline chloride 67-48-1

384 

(34.4%)

55 

(37.7%)

649 

(51.8%)

45 

(57.0%)

Polyethylene glycol 25322-68-3

567 

(28.5%)

688 

(28.9%)

1,2,4-Trimethylbenzene 95-63-6

496 

(25.0%)

7 

(8.9%)

Ammonium chloride 12125-02-9

732 

(30.7%)

50 

(20.9%)
Appendix C – Chemical Mixing Supplemental Information 

C-17

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

Diatomaceous earth, 

calcined 91053-39-3

419 

(37.6%)

435 

(34.7%)

Didecyl dimethyl 

ammonium chloride 7173-51-5

46 

(31.6%)

49 

(20.5%)

Sodium chlorite 7758-19-2

482 

(24.3%)

271 

(22.6%)

Sodium erythorbate 6381-77-7

10 

(12.7%)

76 

(31.8%)

N,N-Dimethylformamide 68-12-2

68 

(46.6%)

355 

(19.6%)

410 

(32.7%)

Nonyl phenol ethoxylate 9016-45-9

333 

(29.9%)

447 

(35.7%)

25 

(31.6%)

Poly(oxy-1,2-ethanediyl)-

nonylphenyl-hydroxy 

(mixture)

127087-87-0

7 

(8.9%)

Sodium persulfate 7775-27-1

373 

(15.7%)

308 

(25.7%)

Tetramethylammonium 

chloride 75-57-0

579 

(29.1%)

315 

(26.3%)

1,2-Propylene glycol 57-55-622 

(27.8%)

5-Chloro-2-methyl-3(2H)-

isothiazolone 26172-55-4

Acetic acid 64-19-7

Ammonium acetate 631-61-8

323 

(27.0%)

Boric acid 10043-35-3

82 

(56.2%)
Appendix C – Chemical Mixing Supplemental Information 

C-18

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

Carbonic acid, 

dipotassium salt 584-08-7

482 

(24.2%)

Cristobalite 14464-46-1

Formic acid 64-18-6

Hemicellulase enzyme 9012-54-8

367 

(15.4%)

11 

(13.9%)

Hemicellulase enzyme 

concentrate

9025-56-3

331 

(29.7%)

Iron(II) sulfate 

heptahydrate 7782-63-0

22 

(27.8%)

Magnesium chloride 7786-30-3

Magnesium nitrate 10377-60-3

Phenolic resin 9003-35-4

419 

(37.6%)

2903 

(18.0%)

Sodium hypochlorite 7681-52-9

282 

(23.5%)

Sodium tetraborate 

decahydrate 1303-96-4

265 

(22.1%)

Solvent naphtha, 

petroleum, heavy aliph. 64742-96-7

1-Butoxy-2-propanol 5131-66-8

1-Propanol 71-23-8
Appendix C – Chemical Mixing Supplemental Information 

C-19

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

1,2-Ethanediaminium, N, 

N'-bis[2-[bis(2-

hydroxyethyl)

methylammonio]ethyl]-

N,N'bis(2-hydroxyethyl)-

N,N'-dimethyl-, 

tetrachloride

138879-94-4

2-Bromo-3-

nitrilopropionamide 1113-55-9

11 

(13.9%)

2-Ethylhexanol 104-76-7

2-Methyl-3(2H)-

isothiazolone 2682-20-4

2-Propenoic acid, polymer 

with 2-propenamide 9003-06-9

486 

(38.8%)

Alkenes, C>10 .alpha.- 64743-02-8

Benzene, 1,1'-oxybis-, 

tetrapropylene derivs., 

sulfonated

119345-03-8

Benzenesulfonic acid, 

dodecyl-, compd. with N1-

(2-aminoethyl)-1,2-

ethanediamine (1:?)

40139-72-8

Benzyldimethyldodecylam

monium chloride 139-07-1

Benzylhexadecyldimethyla

mmonium chloride 122-18-9

Boron sodium oxide 1330-43-4

C10-C16 ethoxylated 

alcohol 68002-97-1
Appendix C – Chemical Mixing Supplemental Information 

C-20

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

Calcium chloride 10043-52-4

Carbon dioxide 124-38-9

Cinnamaldehyde (3-

phenyl-2-propenal) 104-55-2

Diethylene glycol 111-46-6

45 

(30.8%)

Diethylene glycol 

monobutyl ether 112-34-5

Diethylenetriamine 111-40-0

Distillates, petroleum, 

hydrotreated light 

paraffinic

64742-55-8

Distillates, petroleum, 

hydrotreated middle 64742-46-7

Ethoxylated C12-16 

alcohols 68551-12-2

57 

(23.8%)

Ethoxylated C14-15 

alcohols 68951-67-7

Formic acid, potassium 

salt 590-29-4

361 

(30.1%)

Glycerin, natural 56-81-5

Isotridecanol, ethoxylated 9043-30-5

Methenamine 100-97-0

Naphtha, petroleum, 

hydrotreated heavy 64742-48-9

384 

(32.1%)
Appendix C – Chemical Mixing Supplemental Information 

C-21

Chemical name CASRN

New 

Mexico

North 

Dakota Ohio Oklahoma

Pennsylvania Texas Utah VirginiaWest 

Virginia Wyoming

Poly(oxy-1,2-ethanediyl), 

.alpha.,.alpha.'-[[(9Z)-9-

octadecenylimino]di-2,1-

ethanediyl]bis[.omega.-

hydroxy26635-93-8

Potassium chloride 7447-40-7

Sodium bromate 7789-38-0

Sodium perborate 

tetrahydrate 10486-00-7

351 

(19.4%)

Sulfamic acid 5329-14-6

Terpenes and terpenoids, 

sweet orange-oil 68647-72-3

Tetradecyl dimethyl 

benzyl ammonium 

chloride

139-08-2

Tetrakis(hydroxymethyl)p

hosphonium sulfate 55566-30-8

945 

(75.4%)

Thiourea polymer 68527-49-1

Tri-n-butyl tetradecyl 

phosphonium chloride 81741-28-8

350 

(14.7%)

Trisodium phosphate 7601-54-9
Appendix C – Chemical Mixing Supplemental Information 

C-22

C.3. Estimating Volume and Mass for 74 Chemicals Reported in Disclosures in 

the EPA FracFocus 1.0 Project Database 

Volume and mass were estimated using the chemical data reported in the disclosures in the EPA 

FracFocus 1.0 project database. The total hydraulic fracturing fluid volume reported was used to 

calculate the total fluid mass by assuming the fluid has a density of 1 g/mL. This is a simplifying 

assumption based on the fact that more than 93% of disclosures are inferred to use water as a base 

fluid. Water had a median concentration of 88% (by mass) in the fracturing fluid, with 10th and 90th

percentiles of 77% and 95%. Roughly 2% of disclosures reported the use of non-aqueous base 

fluids, which contained roughly 60% (median) water (U.S. EPA, 2015c). The use of non-aqueous 

base fluids would introduce additional error in our calculations. We made the simplifying 

assumption that this error is negligible. Some disclosures reported using brine, which has a density 

between 1.0 and 1.1 g/mL. This would introduce at most an error of 10% for the fluid calculation 

(the difference of a chemical being present at 10 versus 9 gal, 1,000 versus 900 gal). We also 

assume that the mass of chemicals present in calculating the total fluid mass is negligible. Given that 

≤2% of the fluid volume are chemicals, and assuming the density of which is 3 mg/L, the error 

introduced is approximately 6%. For reference, for the chemicals we are calculating volumes, 

chlorine dioxide is the densest at 2.757 mg/L. Chemical with densities less than 1 mg/L introduce 

approximately <1% error. 

Next, the mass of each chemical per disclosure was calculated. Each chemical is reported in 

disclosures to FracFocus 1.0 as a maximum concentration by mass in the hydraulic fracturing fluid. 

This introduces error, as we only know that it is equal to or less than this mass fraction. In EPA’s 

analysis of the EPA FracFocus 1.0 project database (U.S. EPA, 2015a), an example additive is 

comprised of three chemicals with maximum ingredient concentration of 60% in the additive and a 

maximum concentration of 0.22% in the hydraulic fracturing fluid. Each of the three chemicals 

cannot be present at 60%. Because of how chemical information was reported to FracFocus 1.0, we 

have no way to know the actual proportions of each chemical in the additive and thus must 

calculate chemical mass based on the given information. Therefore, our calculations likely 

overestimate actual volumes. However, in some cases, the concentration in the additive that is 

given is less than 100% and only one chemical is listed in the additive. In these cases, it appears that 

the disclosure is reporting the concentration of that chemical in water. Hydrogen chloride (HCl) is 

listed as the sole ingredient in the acid additive, and the maximum concentration is 40% by mass. In 

this case, the HCl is diluted down to 40%, so the total volume would be underestimated. 

After all the chemical masses are calculated, the volume is calculated by dividing chemical mass by 

density. 

Given the limited information available, due to the limits of the FracFocus 1.0 chemical reporting 

and general lack of publicly available data, and despite the errors associated with these 

calculations, these calculations provide context for the general magnitude of volumes for each of the 

chemicals used on-site. These calculations are used to calculate median volumes for each chemical 

on a per well basis. These volume calculations are for the chemicals themselves, not the additives. 
Appendix C – Chemical Mixing Supplemental Information 

C-23

The analysis considered 34,495 disclosures and 672,358 ingredient records that met selected 

quality assurance criteria, including: completely parsed; unique combination of fracture date and 

API well number; fracture date between January 1, 2011, and February 28, 2013; criteria for water 

volumes; valid CASRN; and valid concentrations. Disclosures that did not meet quality assurance 

criteria (4,035) or other, query-specific criteria were excluded from our analysis. 

Density data were gathered from Reaxys® and other sources as noted. Reaxys® 

(http://www.elsevier.com/online-tools/reaxys) is an online database of chemistry literature and 

data. Direct density source, as provided by Reaxys®, is provided in Table C-7. 

Reporting hydraulic fracturing well records to FracFocus 1.0 was required in six of the 20 states 

with data in FracFocus between January 1, 2011, and February 28, 2013. An additional three states 

required disclosure to either FracFocus or the state, and five states required reporting to the state. 

Reporting to FracFocus 1.0 was optional in other states. Some states changed their reporting 

requirements during the course of the study. The EPA FracFocus 1.0 project database, developed 

using data directly from FracFocus 1.0, therefore does not encompass all data on chemicals used in 

hydraulic fracturing. As stated in Text Box 4-2, this mix of voluntary and mandatory disclosure 

requirements limits the completeness of data included in the EPA FracFocus 1.0 project database 

for estimating hydraulic fracturing fluid compositions and volumes. According to a comparison 

between the EPA FracFocus 1.0 project database reported fluid volumes and literature values, 

water use per well was reported to be about 86% of the literature values (median of estimated 

values; see Chapter 4, Text Box 4-1). If the fluid volume is underreported, then estimated chemical 

volumes based on fluid volume would be similarly underestimated. Using the underreporting of 

86%, then the estimated median chemical volume would be 760 gal (2,900 L). 
Appendix C – Chemical Mixing Supplemental Information 

C-24

Table C-4. Estimated mean, median, 5th percentile, and 95th percentile volumes in gallons for 

chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, 

where density information was available. 

Chemicals are listed in alphabetical order. Density information came from Reaxys® and other sources. All density 

sources are referenced in Table C-7. 

Volume (gal)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile

(4R)-1-methyl-4-(prop-1-en-2-

yl)cyclohexene 5989-27-5 2,702 406 0 19,741

1-Butoxy-2-propanol 5131-66-8 167 21 5 654

1-Decanol 112-30-1 28 4 0 33

1-Octanol 111-87-5 5 4 0 10

1-Propanol 71-23-8 128 55 6 367

1,2-Propylene glycol 57-55-6 13,105 72 4 61,071

1,2,4-Trimethylbenzene 95-63-6 38 6 0 43

2-Butoxyethanol 111-76-2 385 26 0 1,811

2-Ethylhexanol 104-76-7 100 11 0 292

2-Mercaptoethanol 60-24-2 1,175 445 0 4,194

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 183 5 0 341

Acetic acid 64-19-7 646 47 0 1,042

Acetic anhydride 108-24-7 239 50 3 722

Acrylamide 79-06-1 95 3 0 57

Adipic acid 124-04-9 153 0 0 109

Aluminum chloride 7446-70-0 2 0 0 0

Ammonia 7664-41-7 44 35 2 138

Ammonium acetate 631-61-8 839 117 0 1,384

Ammonium chloride 12125-02-9 526 58 3 548

Ammonium hydroxide 1336-21-6 7 2 0 14

Benzyl chloride 100-44-7 52 0 0 40

Carbonic acid, dipotassium salt 584-08-7 467 113 0 1,729

Chlorine dioxide 10049-04-4 31 11 0 28

Choline chloride 67-48-1 2,131 290 28 4,364
Appendix C – Chemical Mixing Supplemental Information 

C-25

Volume (gal)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile

Cinnamaldehyde (3-phenyl-2-propenal) 104-55-2 68 3 0 697

Citric acid 77-92-9 163 20 1 269

Dibromoacetonitrile 3252-43-5 22 13 1 45

Diethylene glycol 111-46-6 168 16 0 102

Diethylenetriamine 111-40-0 92 21 0 207

Dodecane 112-40-3 190 31 0 151

Ethanol 64-17-5 831 121 1 2,645

Ethanolamine 141-43-5 70 30 0 283

Ethyl acetate 141-78-6 0 0 0 0

Ethylene glycol 107-21-1 614 184 4 2,470

Ferric chloride 7705-08-0 0 0 0 0

Formalin 50-00-0 200 0 0 8

Formic acid 64-18-6 501 38 1 1,229

Fumaric acid 110-17-8 2 0 0 12

Glutaraldehyde 111-30-8 1,313 122 2 1,165

Glycerin, natural 56-81-5 413 109 10 911

Glycolic acid 79-14-1 38 10 4 94

Hydrochloric acid 7647-01-0 28,320 3,110 96 26,877

Isopropanol 67-63-0 2,095 55 0 1,264

Isopropylamine 75-31-0 83 121 0 172

Magnesium chloride 7786-30-3 14 0 0 2

Methanol 67-56-1 1,218 110 2 3,731

Methenamine 100-97-0 3,386 100 0 3,648

Methoxyacetic acid 625-45-6 36 4 2 115

N,N-Dimethylformamide 68-12-2 119 10 0 216

Naphthalene 91-20-3 72 12 0 204

Nitrogen, liquid 7727-37-9 41,841 26,610 3,091 108,200

Ozone 10028-15-6 15,844 15,473 8,785 26,063
Appendix C – Chemical Mixing Supplemental Information 

C-26

Volume (gal)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile

Peracetic acid 79-21-0 300 268 50 663

Phosphonic acid 13598-36-2 1,201 0 0 3

Phosphoric acid Divosan X-Tend 

formulation 7664-38-2 13 4 0 15

Potassium acetate 127-08-2 209 1 0 994

Propargyl alcohol 107-19-7 183 2 0 51

Saline 7647-14-5 876 85 0 1,544

Saturated sucrose 57-50-1 1 1 0 2

Silica, amorphous 7631-86-9 6,877 8 0 38,371

Sodium carbonate 497-19-8 228 16 0 1,319

Sodium formate 141-53-7 0 0 0 0

Sodium hydroxide 1310-73-2 551 38 0 1,327

Sulfur dioxide 7446-09-5 0 0 0 0

Sulfuric acid 7664-93-9 3 0 0 3

tert-Butyl hydroperoxide (70% solution 

in Water) 75-91-2 156 64 0 557

Tetramethylammonium chloride 75-57-0 970 483 2 3,508

Thioglycolic acid 68-11-1 55 7 2 229

Toluene 108-88-3 18 0 0 11

Tridecane 629-50-5 190 31 0 190

Triethanolamine 102-71-6 846 60 0 2,264

Triethyl phosphate 78-40-0 55 1 0 533

Triethylene glycol 112-27-6 5,198 116 28 945

Triisopropanolamine 122-20-3 46 4 1 330

Trimethyl borate 121-43-7 83 40 4 283

Undecane 1120-21-4 273 29 0 1,641
Appendix C – Chemical Mixing Supplemental Information 

C-27

Table C-5. Estimated mean, median, 5th percentile, and 95th percentile volumes in liters for 

chemicals reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, 

where density information was available. 

Chemicals are listed in alphabetical order. Density information came from Reaxys® and other sources. All density 

sources are referenced in Table C-7. 

Volume (L)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile

(4R)-1-methyl-4-(prop-1-en-2-

yl)cyclohexene 5989-27-5 10,229 1,536 0 74,729

1-Butoxy-2-propanol 5131-66-8 631 80 18 2,475

1-Decanol 112-30-1 107 14 1 123

1-Octanol 111-87-5 21 14 1 39

1-Propanol 71-23-8 483 208 22 1,391

1,2-Propylene glycol 57-55-6 49,607 274 15 231,179

1,2,4-Trimethylbenzene 95-63-6 145 24 0 165

2-Butoxyethanol 111-76-2 1,459 98 0 6,856

2-Ethylhexanol 104-76-7 377 40 1 1,106

2-Mercaptoethanol 60-24-2 4,449 1,685 0 15,878

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 692 18 0 1,292

Acetic acid 64-19-7 2,446 176 0 3,945

Acetic anhydride 108-24-7 906 189 12 2,734

Acrylamide 79-06-1 361 10 0 216

Adipic acid 124-04-9 578 0 0 414

Aluminum chloride 7446-70-0 6 0 0 0

Ammonia 7664-41-7 166 134 7 523

Ammonium acetate 631-61-8 3,177 444 0 5,238

Ammonium chloride 12125-02-9 1,992 218 12 2,074

Ammonium hydroxide 1336-21-6 27 6 1 52

Benzyl chloride 100-44-7 196 1 0 151

Carbonic acid, dipotassium salt 584-08-7 1,769 429 0 6,544

Chlorine dioxide 10049-04-4 117 43 1 106

Choline chloride 67-48-1 8,068 1,096 107 16,521
Appendix C – Chemical Mixing Supplemental Information 

C-28

Volume (L)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile

Cinnamaldehyde (3-phenyl-2-propenal) 104-55-2 258 12 0 2,638

Citric acid 77-92-9 618 77 5 1,019

Dibromoacetonitrile 3252-43-5 82 50 4 170

Diethylene glycol 111-46-6 636 61 1 384

Diethylenetriamine 111-40-0 347 80 0 785

Dodecane 112-40-3 719 117 0 572

Ethanol 64-17-5 3,144 458 6 10,011

Ethanolamine 141-43-5 264 112 0 1,070

Ethyl acetate 141-78-6 0 0 0 0

Ethylene glycol 107-21-1 2,324 697 14 9,349

Ferric chloride 7705-08-0 0 0 0 0

Formalin 50-00-0 756 2 0 31

Formic acid 64-18-6 1,896 144 2 4,653

Fumaric acid 110-17-8 9 0 0 46

Glutaraldehyde 111-30-8 4,972 462 6 4,409

Glycerin, natural 56-81-5 1,565 412 38 3,447

Glycolic acid 79-14-1 146 39 14 356

Hydrochloric acid 7647-01-0 107,204 11,772 362 101,741

Isopropanol 67-63-0 7,932 210 1 4,786

Isopropylamine 75-31-0 314 458 0 652

Magnesium chloride 7786-30-3 52 0 0 8

Methanol 67-56-1 4,609 416 6 14,125

Methenamine 100-97-0 12,817 378 0 13,810

Methoxyacetic acid 625-45-6 136 17 8 436

N,N-Dimethylformamide 68-12-2 449 38 2 819

Naphthalene 91-20-3 271 44 0 774

Nitrogen, liquid 7727-37-9 158,384 100,731 11,700 409,583

Ozone 10028-15-6 59,976 58,570 33,254 98,658
Appendix C – Chemical Mixing Supplemental Information 

C-29

Volume (L)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile

Peracetic acid 79-21-0 1,137 1,016 190 2,511

Phosphonic acid 13598-36-2 4,547 2 0 11

Phosphoric acid Divosan X-Tend 

formulation 7664-38-2 51 15 0 57

Potassium acetate 127-08-2 790 3 0 3,762

Propargyl alcohol 107-19-7 693 9 0 193

Saline 7647-14-5 3,317 321 0 5,844

Saturated sucrose 57-50-1 5 2 0 6

Silica, amorphous 7631-86-9 26,031 32 0 145,251

Sodium carbonate 497-19-8 862 62 0 4,991

Sodium formate 141-53-7 1 1 0 1

Sodium hydroxide 1310-73-2 2,087 144 1 5,024

Sulfur dioxide 7446-09-5 2 0 0 0

Sulfuric acid 7664-93-9 10 0 0 12

tert-Butyl hydroperoxide (70% solution in 

Water) 75-91-2 591 242 0 2,109

Tetramethylammonium chloride 75-57-0 3,672 1,830 8 13,279

Thioglycolic acid 68-11-1 208 28 6 868

Toluene 108-88-3 69 0 0 41

Tridecane 629-50-5 721 118 0 721

Triethanolamine 102-71-6 3,203 228 0 8,570

Triethyl phosphate 78-40-0 209 6 0 2,019

Triethylene glycol 112-27-6 19,676 439 106 3,579

Triisopropanolamine 122-20-3 174 16 4 1,249

Trimethyl borate 121-43-7 314 152 16 1,072

Undecane 1120-21-4 1,035 111 0 6,212
Appendix C – Chemical Mixing Supplemental Information 

C-30

Table C-6. Calculated mean, median, 5th percentile, and 95th percentile chemical masses 

reported in 100 or more disclosures in the EPA FracFocus 1.0 project database, where density 

information was available. 

Density information came from Reaxys® and other sources. All density sources are referenced in Table C-7. 

Number of disclosures reported for each chemical is also included. 

Mass (kg)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile Disclosures

(4R)-1-methyl-4-(prop-1-en-2-

yl)cyclohexene 5989-27-5 8,593 1,290 0 62,772 578

1-Butoxy-2-propanol 5131-66-8 555 71 16 2,178 773

1-Decanol 112-30-1 89 12 1 102 434

1-Octanol 111-87-5 17 12 1 32 434

1-Propanol 71-23-8 386 167 18 1,113 1,481

1,2-Propylene glycol 57-55-6 51,095 282 15 238,114 1,023

1,2,4-Trimethylbenzene 95-63-6 126 21 0 143 3,976

2-Butoxyethanol 111-76-2 1,313 88 0 6,170 6,778

2-Ethylhexanol 104-76-7 313 34 0 918 1,291

2-Mercaptoethanol 60-24-2 489 185 0 1,747 2,051

2,2-Dibromo-3-

nitrilopropionamide 10222-01-2 1,660 44 0 3,102 4,927

Acetic acid 64-19-7 2,544 183 0 4,103 7,643

Acetic anhydride 108-24-7 969 203 12 2,925 1,377

Acrylamide 79-06-1 408 11 0 244 251

Adipic acid 124-04-9 785 0 0 564 233

Aluminum chloride 7446-70-0 15 0 0 0 122

Ammonia 7664-41-7 111 90 4 351 398

Ammonium acetate 631-61-8 3,718 520 0 6,129 1,504

Ammonium chloride 12125-02-9 2,530 277 16 2,633 3,288

Ammonium hydroxide 1336-21-6 48 11 2 94 1,173

Benzyl chloride 100-44-7 214 1 0 165 1,833

Carbonic acid, dipotassium salt 584-08-7 4,298 1,042 0 15,902 4,093

Chlorine dioxide 10049-04-4 321 117 3 291 331

Choline chloride 67-48-1 9,440 1,282 125 19,329 4,241
Appendix C – Chemical Mixing Supplemental Information 

C-31

Mass (kg)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile Disclosures

Cinnamaldehyde (3-phenyl-2-

propenal) 104-55-2 284 13 0 2,902 1,377

Citric acid 77-92-9 989 123 8 1,630 7,503

Dibromoacetonitrile 3252-43-5 193 118 11 403 272

Diethylene glycol 111-46-6 712 68 1 430 1,732

Diethylenetriamine 111-40-0 330 76 0 746 784

Dodecane 112-40-3 539 88 0 429 131

Ethanol 64-17-5 2,484 361 4 7,908 9,233

Ethanolamine 141-43-5 267 113 0 1,081 585

Ethyl acetate 141-78-6 0 0 0 0 110

Ethylene glycol 107-21-1 2,557 767 15 10,283 14,767

Ferric chloride 7705-08-0 0 0 0 0 118

Formalin 50-00-0 816 2 0 34 456

Formic acid 64-18-6 2,313 176 2 5,677 3,781

Fumaric acid 110-17-8 15 0 0 75 224

Glutaraldehyde 111-30-8 4,972 462 6 4,409 10,963

Glycerin, natural 56-81-5 1,972 519 47 4,343 1,829

Glycolic acid 79-14-1 217 58 21 530 595

Hydrochloric acid 7647-01-0 107,204 11,772 362 101,741 20,996

Isopropanol 67-63-0 6,187 163 1 3,733 15,058

Isopropylamine 75-31-0 213 311 0 444 255

Magnesium chloride 7786-30-3 120 1 0 18 1,113

Methanol 67-56-1 3,641 329 5 11,159 23,225

Methenamine 100-97-0 15,380 454 0 16,572 4,412

Methoxyacetic acid 625-45-6 161 20 9 514 584

N,N-Dimethylformamide 68-12-2 422 36 2 770 2,972

Naphthalene 91-20-3 220 35 0 627 5,945

Nitrogen, liquid 7727-37-9 129,875 82,599 9,594 335,858 713

Ozone 10028-15-6 129 126 71 212 209
Appendix C – Chemical Mixing Supplemental Information 

C-32

Mass (kg)

Name CASRN Mean Median

5

th

Percentile

95th

Percentile Disclosures

Peracetic acid 79-21-0 1,251 1,117 209 2,762 221

Phosphonic acid 13598-36-2 7,730 3 0 18 2,216

Phosphoric acid Divosan X-Tend 

formulation 7664-38-2 48 14 0 54 315

Potassium acetate 127-08-2 1,216 5 0 5,793 325

Propargyl alcohol 107-19-7 658 9 0 183 10,771

Saline 7647-14-5 7,197 696 0 12,682 6,673

Saturated sucrose 57-50-1 6 2 0 7 125

Silica, amorphous 7631-86-9 57,267 71 0 319,553 2,423

Sodium carbonate 497-19-8 2,191 158 0 12,678 396

Sodium formate 141-53-7 2 1 1 2 204

Sodium hydroxide 1310-73-2 4,445 306 2 10,701 12,585

Sulfur dioxide 7446-09-5 2 0 0 0 224

Sulfuric acid 7664-93-9 18 0 0 22 402

tert-Butyl hydroperoxide (70% 

solution in water) 75-91-2 532 218 0 1,898 814

Tetramethylammonium chloride 75-57-0 4,296 2,141 10 15,537 3,162

Thioglycolic acid 68-11-1 277 37 8 1,155 156

Toluene 108-88-3 59 0 0 35 214

Tridecane 629-50-5 541 88 0 541 132

Triethanolamine 102-71-6 3,588 255 0 9,599 1,498

Triethyl phosphate 78-40-0 222 6 0 2,140 991

Triethylene glycol 112-27-6 22,038 491 119 4,008 528

Triisopropanolamine 122-20-3 177 17 4 1,274 251

Trimethyl borate 121-43-7 292 141 14 997 294

Undecane 1120-21-4 766 82 0 4,597 241
Appendix C – Chemical Mixing Supplemental Information 

C-33

Table C-7. Associated chemical densities and references used to calculate chemical mass and 

estimate chemical volume. 

Name CASRN Density (g/mL) Reference

(4R)-1-methyl-4-(prop-1-en-2-yl)cyclohexene 5989-27-5 0.84 Dejoye Tanzi et al. (2012)

1-Butoxy-2-propanol 5131-66-8 0.88 Pal et al. (2013)

1-Decanol 112-30-1 0.83 Faria et al. (2013)

1-Octanol 111-87-5 0.82 Dubey and Kumar (2013)

1-Propanol 71-23-8 0.8 Rani and Maken (2013)

1,2-Propylene glycol 57-55-6 1.03 Moosavi et al. (2013)

1,2,4-Trimethylbenzene 95-63-6 0.87 He et al. (2008)

2-Butoxyethanol 111-76-2 0.9 Dhondge et al. (2010)

2-Ethylhexanol 104-76-7 0.83 Laavi et al. (2012)

2-Mercaptoethanol 60-24-2 0.11 Rawat et al. (1976)

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 2.4 Fels (1900)

Acetic acid 64-19-7 1.04 Thalladi et al. (2000)

Acetic anhydride 108-24-7 1.07 Radwan and Hanna (1976)

Acrylamide 79-06-1 1.13 Carpenter and Davis (1957)

Adipic acid 124-04-9 1.36 Thalladi et al. (2000)

Aluminum chloride 7446-70-0 2.48 Sigma-Aldrich (2015a)

Ammonia 7664-41-7 0.67 Harlow et al. (1997)

Ammonium acetate 631-61-8 1.17 Biltz and Balz (1928)

Ammonium chloride 12125-02-9 1.27 Haynes (2014)

Ammonium hydroxide 1336-21-6 1.8 Xiao et al. (2013)

Benzyl chloride 100-44-7 1.09 Sarkar et al. (2012)

Carbonic acid, dipotassium salt 584-08-7 2.43 Sigma-Aldrich (2014b)

Chlorine dioxide 10049-04-4 2.757 Haynes (2014)

Choline chloride 67-48-1 1.17 Shanley and Collin (1961)

Cinnamaldehyde (3-phenyl-2-propenal) 104-55-2 1.1 Masood et al. (1976)

Citric acid 77-92-9 1.6 Bennett and Yuill (1935)

Dibromoacetonitrile 3252-43-5 2.37 Wilt (1956)

Diethylene glycol 111-46-6 1.12 Chasib (2013)

Diethylenetriamine 111-40-0 0.95 Dubey and Kumar (2011)

Dodecane 112-40-3 0.75 Baragi et al. (2013)

Ethanol 64-17-5 0.79 Kiselev et al. (2012)

Ethanolamine 141-43-5 1.01 Blanco et al. (2013)
Appendix C – Chemical Mixing Supplemental Information 

C-34

Name CASRN Density (g/mL) Reference

Ethyl acetate 141-78-6 0.89 Laavi et al. (2013)

Ethylene glycol 107-21-1 1.1 Rodnikova et al. (2012)

Ferric chloride 7705-08-0 2.9 Haynes (2014)

Formalin 50-00-0 1.08 Alfa Aesar (2015)

Formic acid 64-18-6 1.22 Casanova et al. (1981)

Fumaric acid 110-17-8 1.64 Huffman and Fox (1938)

Glutaraldehyde 111-30-8 1 Oka (1962)

Glycerin, natural 56-81-5 1.26 Egorov et al. (2013)

Glycolic acid 79-14-1 1.49 Pijper (1971)

Hydrochloric acid 7647-01-0 1 Steinhauser et al. (1990)

Isopropanol 67-63-0 0.78 Zhang et al. (2013)

Isopropylamine 75-31-0 0.68 Sarkar and Roy (2009)

Magnesium chloride 7786-30-3 2.32 Haynes (2014)

Methanol 67-56-1 0.79 Kiselev et al. (2012)

Methenamine 100-97-0 1.2 Mak (1965)

Methoxyacetic acid 625-45-6 1.18 Haynes (2014)

N,N-Dimethylformamide 68-12-2 0.94 Smirnov and Badelin (2013)

Naphthalene 91-20-3 0.81 Dyshin et al. (2008)

Nitrogen, liquid 7727-37-9 0.82 finemech (2012)

Ozone 10028-15-6 0.002144 Haynes (2014)

Peracetic acid 79-21-0 1.1 Sigma-Aldrich (2015b)

Phosphonic acid 13598-36-2 1.7 Sigma-Aldrich (2014a)

Phosphoric acid Divosan X-Tend formulation 7664-38-2 0.94 Fadeeva et al. (2004)

Potassium acetate 127-08-2 1.54 Haynes (2014)

Propargyl alcohol 107-19-7 0.95 Vijaya Kumar et al. (1996)

Saline 7647-14-5 2.17 Sigma-Aldrich (2010)

Saturated sucrose 57-50-1 1.13 Hagen and Kaatze (2004)

Silica, amorphous 7631-86-9 2.2 Fujino et al. (2004)

Sodium carbonate 497-19-8 2.54 Haynes (2014)

Sodium formate 141-53-7 1.97 Fuess et al. (1982)

Sodium hydroxide 1310-73-2 2.13 Haynes (2014)

Sulfur dioxide 7446-09-5 1.3 Sigma-Aldrich (2015c)

Sulfuric acid 7664-93-9 1.83 Sigma-Aldrich (2015d)
Appendix C – Chemical Mixing Supplemental Information 

C-35

Name CASRN Density (g/mL) Reference

tert-Butyl hydroperoxide (70% solution in 

water) 75-91-2 0.9 Sigma-Aldrich (2007)

Tetramethylammonium chloride 75-57-0 1.17 Haynes (2014)

Thioglycolic acid 68-11-1 1.33 Biilmann (1906)

Toluene 108-88-3 0.86 Martinez-Reina et al. (2012)

Tridecane 629-50-5 0.75 Zhang et al. (2011)

Triethanolamine 102-71-6 1.12 Blanco et al. (2013)

Triethyl phosphate 78-40-0 1.06 Krakowiak et al. (2001)

Triethylene glycol 112-27-6 1.12 Afzal et al. (2009)

Triisopropanolamine 122-20-3 1.02 IUPAC (2014)

Trimethyl borate 121-43-7 0.93 Sigma-Aldrich (2015e)

Undecane 1120-21-4 0.74 de Oliveira et al. (2011)
Appendix C – Chemical Mixing Supplemental Information 

C-36

C.4. Estimating Spill Rates Based on State Spill Report Data

Several studies have provided estimates for the frequency of hydraulic fracturing-related spills. 

This section compiles analyses for three states: Pennsylvania, Colorado, and North Dakota (Table 

C-8).

In Pennsylvania, spills related to hydraulic fracturing activity are estimated to occur at a rate 

between 0.4 to 12.2 reported spills per 100 wells installed in the Marcellus Shale. Three studies 

(Rahm et al., 2015; Brantley et al., 2014; Gradient, 2013) calculated a spill rate for the Marcellus 

Shale in Pennsylvania using reports from the Pennsylvania Department of Environmental 

Protection (PA DEP) Oil and Gas Compliance Report Database. The PA DEP database provides a 

searchable format based on Notices of Violations from routine inspections or investigations of spill 

reports or complaints. Each study had different criteria for inclusion, presented in Table C-8, 

resulting in a range of rates even when using the same data source. Spill estimates include different 

criteria for how the rates were calculated. All three of these sources consider spills that occur 

during hydraulic fracturing activity. These include produced water, hydraulic fracturing chemicals, 

and diesel. Brantley et al. (2014) present data for major spills (> 400 gal or 1,514 L) that reached a 

water body, which would be a low-end estimate of the total number of spills occuring on site. 

In Colorado, there is an estimated average of 1.3 reported spills on or near the well pad for every 

100 hydraulically fractured wells, based on spill reports from the Colorado Oil and Gas 

Conservation Commission (COGCC) Information System. In its study of spills related to hydraulic 

fracturing, the EPA determined that Colorado spill reports were the most detailed spill reports from 

among the nine state data sources investigated and generally provided more of the information 

needed to determine whether a spill was related to hydraulic fracturing (U.S. EPA, 2015j). Here, we 

estimate the spill rate in Colorado by dividing the number of hydraulic fracturing-related spills 

identified by the EPA (U.S. EPA, 2015j, Appendix B) by the number of wells hydraulically fractured 

in Colorado for specific time periods between January 2006 and April 2012. We used three data 

sources to estimate the number of wells: (1) there were 172 reported spills in Colorado for the 

15,000 wells fractured from January 2006 to April 2012 (DrillingInfo, 2012), (2) there were 50 

reported spills in Colorado for the 3,559 wells fractured from January 2011 to April 2012 (U.S. EPA, 

2015c), and (3) there were 41 reported spills in Colorado for the 3,000 wells fractured from 

September 2009 to October 2010 (U.S. EPA, 2013a). These data give an estimated average of 1.3 

reported spills on or near the well pad for every 100 hydraulically fractured wells (Table C-8).

In North Dakota, using the North Dakota spills database, there were an estimated 2.6 reported 

spills of hydraulic fracturing fluids and chemicals per 100 wells fractured in 2015 (North Dakota 

Department of Health, 2015; see Appendix E). There were 22 reported spills of injection fluid and 

17 spills of injection chemical. In 2015, there were 1490 wells fractured (North Dakota Department

of Mineral Resources, 2016). Due to including only spills of fluids and chemicals, this estimate may 

fall on the low side. 

The spill rates presented in Table C-8 are based on spill reports found in three state data sources 

and are limited by both the spills reported in the state data sources and the inclusion criteria 

defined by each of the studies. Spills identified from state data sources are likely a subset of the 

total number of spills that occurred within a state for a specified time period. Some spills may not 
Appendix C – Chemical Mixing Supplemental Information 

C-37

be recorded in state data sources, because they do not meet the spill reporting requirements in 

place at the time of the spill. Additionally, the PA DEP Notices of Violation may include spills not 

specifically related to hydraulic fracturing, such as spills of drilling fluids. 

The inclusion criteria used by each of the studies affects which spills are used to calculate a spill 

rate. More restrictive criteria, such as only counting spills that were greater than 400 gal (1,514 L), 

results in a lower number of spills being used for estimating spill rates, while less restrictive 

criteria, such as all spills from wells marked unconventional in the PA DEP database, results in a 

greater number of spills being used for estimating spill rates. Rahm et al. applied the least 

restrictive criteria of the four studies (i.e., spills from unconventional wells) when identifying spills, 

while Brantley et al. applied more restrictive criteria (i.e., spills of > 400 gal or 1,514 L in which 

spilled fluids reached a surface water body). This would contribute to the different spill rates 

calculated by these two studies. 

Based on previous studies and the analysis here, hydraulic fracturing-related spills rates in 

Pennsylvania, Colorado, and North Dakota range from 0.4 to 12.2 reported spills per 100 wells, with 

a median rate of 2.6 reported spills for every 100 wells. These numbers may not be representative 

of national spill rates or rates in other regions. 

Table C-8. Estimations of spill rates. 

Spill rates from four different sources. Each source used different criteria to identify and include spills in their 

analysis. 

Spill ratea Data source Time period Inclusion criteria Information source

0.4b, 0.8c PA DEPd 2008 - 2013 Volume spilled > 400 gal; all spills 

reported to reach water body.e Brantley et al. (2014)

3.3f PA DEPd 2009 - 2012

“Unconventional” well; spills with

unknown volumes not included. Includes 

any spill during HF activities

Gradient (2013)

12.2g, 11.6h PA DEPd

2007 - July 

2013

“Unconventional” well based on 

environmental violation rates. Rahm et al. (2015)

1.3i COGCCj

Jan 2006 -

May 2012

Specifically related to hydraulic fracturing 

on or near well pad U.S. EPA (2013a)

2.6i ND 2015 Spills reported as injection fluid (22) or 

injection chemical (17)

North Dakota Department 

of Health (2015)

Median Spill Rate: 2.6 reported spills per 100 wells

a Spill rate is the number of reported spills per 100 wells.

b Spill rate is calculated as the number of spills per 100 wells spudded.

c Spill rate is calculated as number of spills per 100 wells completed.

d PA DEP (2016). 

e 32 spills >400 gal: 9 were brine (e.g., produced water), 7 were gel or hydraulic fracturing fluids, 5 were hydrostatic test waters 

or sediments, 2 were unknown, 1 was diesel.

f Spill rate is calculated as the number of spills per 100 wells installed.

g Mean spill rate is calculated as the number of spills per 100 wells drilled.

h Median spill rate is calculated as the number of spills per 100 drilled.

i Spill rate is calculated as the number of spills per 100 wells fractured.

j COGCC (2016). 
Appendix C – Chemical Mixing Supplemental Information 

C-38

C.5. Selected Physicochemical Properties of Organic Chemicals Used in Hydraulic Fracturing Fluids 

Table C-9. Selected physicochemical properties of organic chemicals reported as used in hydraulic fracturing fluids. 

Properties are provided for chemicals, where available from EPI SuiteTM version 4.1 (U.S. EPA, 2012b). Selected physicochemical properties of organic chemicals 

reported as used in hydraulic fracturing fluids. In the table, “--” indicates no information is available. 

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

(13Z)-N,N-bis(2-hydroxyethyl)-Nmethyldocos-13-en-1-aminium chloride 120086-58-0 4.38 -- 0.3827 3.32 × 10−15

-- --

(2,3-Dihydroxypropyl)trimethyl

ammonium chloride 34004-36-9 -5.8 -- 1.00 × 106 9.84 × 10−18

-- --

(E)-Crotonaldehyde 123-73-9 0.6 -- 4.15 × 104 5.61 × 10−5 1.90 × 10−5 1.94 × 10−5

[Nitrilotris(methylene)]tris-phosphonic 

acid pentasodium salt 2235-43-0 −5.45 −3.53 1.00 × 106 1.65 × 10−34

-- --

1-(1-Naphthylmethyl)quinolinium 

chloride 65322-65-8 5.57 -- 0.02454 1.16 × 10−7

-- --

1-(Alkyl* amino)-3-aminopropane 

*(42%C12, 26%C18, 15%C14, 8%C16, 

5%C10, 4%C8)

68155-37-3 4.74 -- 23.71 6.81 × 10−8 2.39 × 10−8--

1-(Phenylmethyl)pyridinium Et Me 

derivatives, chlorides 68909-18-2 4.1 -- 14.13 1.78 × 10−5

-- --

1,2,3-Trimethylbenzene 526-73-8 3.63 3.66 75.03 7.24 × 10−3 6.58 × 10−3 4.36 × 10−3

1,2,4-Trimethylbenzene 95-63-6 3.63 3.63 79.59 7.24 × 10−3 6.58 × 10−3 6.16 × 10−3

1,2-Benzisothiazolin-3-one 2634-33-5 0.64 -- 2.14 × 104 6.92 × 10−9-- --

1,2-Dibromo-2,4-dicyanobutane 35691-65-7 1.63 -- 424 3.94 × 10−10-- --
Appendix C – Chemical Mixing Supplemental Information 

C-39

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

1,2-Dimethylbenzene 95-47-6 3.09 3.12 224.1 6.56 × 10−3 6.14 × 10−3 5.18 × 10−3

1,2-Ethanediaminium, N,N'-bis[2-[bis(2-

hydroxyethyl)methylammonio]ethyl]-

N,N'-bis(2-hydroxyethyl)-N,N'-dimethyl-, 

tetrachloride

138879-94-4 −23.19 -- 1.00 × 106 2.33 × 10−35-- --

1,2-Propylene glycol 57-55-6 -0.78 −0.92 8.11 × 105 1.74 × 10−7 1.31 × 10−10 1.29 × 10−8

1,2-Propylene oxide 75-56-9 0.37 0.03 1.29 × 105 1.60 × 10−4 1.23 × 10−4 6.96 × 10−5

1,3,5-Triazine 290-87-9 −0.2 0.12 1.03 × 105 1.21 × 10−6-- --

1,3,5-Triazine-1,3,5(2H,4H,6H)-triethanol 4719-04-4 −4.67 -- 1.00 × 106 1.08 × 10−11-- --

1,3,5-Trimethylbenzene 108-67-8 3.63 3.42 120.3 7.24 × 10−3 6.58 × 10−3 8.77 × 10−3

1,3-Butadiene 106-99-0 2.03 1.99 792.3 7.79 × 10−2 7.05 × 10−2 7.36 × 10−2

1,3-Dichloropropene 542-75-6 2.29 2.04 1,994 2.45 × 10−2 3.22 × 10−3 3.55 × 10−3

1,4-Dioxane 123-91-1 −0.32 −0.27 2.14 × 105 5.91 × 10−6 1.12 × 10−7 4.80 × 10−6

1,6-Hexanediamine 124-09-4 0.35 -- 5.34 × 105 3.21 × 10−9 7.05 × 10−10--

1,6-Hexanediamine dihydrochloride 6055-52-3 0.35 -- 5.34 × 105 3.21 × 10−9 7.05 × 10−10--

1-[2-(2-Methoxy-1-methylethoxy)-1-

methylethoxy]-2-propanol 20324-33-8 −0.2 -- 1.96 × 105 2.36 × 10−11 4.55 × 10−13

--

1-Amino-2-propanol 78-96-6 −1.19 −0.96 1.00 × 106 4.88 × 10−10 2.34 × 10−10--

1-Benzylquinolinium chloride 15619-48-4 4.4 -- 6.02 1.19 × 10−6-- --

1-Butanol 71-36-3 0.84 0.88 7.67 × 104 9.99 × 10−6 9.74 × 10−6 8.81 × 10−6

1-Butoxy-2-propanol 5131-66-8 0.98 -- 4.21 × 104 1.30 × 10−7 4.88 × 10−8--
Appendix C – Chemical Mixing Supplemental Information 

C-40

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

1-Decanol 112-30-1 3.79 4.57 28.21 5.47 × 10−5 7.73 × 10−5 3.20 × 10−5

1-Dodecyl-2-pyrrolidinone 2687-96-9 5.3 4.2 5.862 7.12 × 10−7-- --

1-Eicosene 3452-07-1 10.03 -- 1.26 × 10−5 1.89 × 101 6.74 × 101--

1-Ethyl-2-methylbenzene 611-14-3 3.58 3.53 96.88 8.71 × 10−3 9.52 × 10−3 5.53 × 10−3

1-Hexadecene 629-73-2 8.06 -- 0.001232 6.10 1.69 × 101--

1-Hexanol 111-27-3 1.82 2.03 6,885 1.76 × 10−5 1.94 × 10−5 1.71 × 10−5

1-Methoxy-2-propanol 107-98-2 −0.49 -- 1.00 × 106 5.56 × 10−8 1.81 × 10−8 9.20 × 10−7

1-Octadecanamine, acetate (1:1) 2190-04-7 7.71 -- 0.04875 9.36 × 10−4 2.18 × 10−3--

1-Octadecanamine, N,N-dimethyl- 124-28-7 8.39 -- 0.008882 4.51 × 10−3 3.88 × 10−2--

1-Octadecene 112-88-9 9.04 -- 1.256× 10-4 10.7 3.38 × 101--

1-Octanol 111-87-5 2.81 3 814 3.10 × 10−5 3.88 × 10−5 2.45 × 10−5

1-Pentanol 71-41-0 1.33 1.51 2.09 × 104 1.33 × 10−5 1.38 × 10−5 1.30 × 10−5

1-Propanaminium, 3-chloro-2-hydroxyN,N,N-trimethyl-, chloride 3327-22-8 −4.48 -- 1.00 × 106 9.48 × 10−17

-- --

1-Propanesulfonic acid 5284-66-2 −1.4 -- 1.00 × 106 2.22 × 10−8-- --

1-Propanol 71-23-8 0.35 0.25 2.72 × 105 7.52 × 10−6 6.89 × 10−6 7.41 × 10−6

1-Propene 115-07-1 1.68 1.77 1,162 1.53 × 10−1 1.58 × 10−1 1.96 × 10−1

1-tert-Butoxy-2-propanol 57018-52-7 0.87 -- 5.24 × 104 1.30 × 10−7 5.23 × 10−8--

1-Tetradecene 1120-36-1 7.08 -- 0.01191 3.46 8.48 --
Appendix C – Chemical Mixing Supplemental Information 

C-41

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

1-Tridecanol 112-70-9 5.26 -- 4.533 1.28 × 10−4 2.18 × 10−4--

1-Undecanol 112-42-5 4.28 -- 43.04 7.26 × 10−5 1.09 × 10−4--

2-(2-Butoxyethoxy)ethanol 112-34-5 0.29 0.56 7.19 × 104 1.52 × 10−9 4.45 × 10−11 7.20 × 10−9

2-(2-Ethoxyethoxy)ethanol 111-90-0 −0.69 −0.54 8.28 × 105 8.63 × 10−10 2.23 × 10−11 2.23 × 10−8

2-(2-Ethoxyethoxy)ethyl acetate 112-15-2 0.32 -- 3.09 × 104 5.62 × 10−8 7.22 × 10−10 2.29 × 10−8

2-(Dibutylamino)ethanol 102-81-8 2.01 2.65 3,297 9.70 × 10−9 1.02 × 10−8--

2-(Hydroxymethylamino)ethanol 34375-28-5 −1.53 -- 1.00 × 106 1.62 × 10−12-- --

2-(Thiocyanomethylthio)benzothiazole 21564-17-0 3.12 3.3 41.67 6.49 × 10−12-- --

2,2'-(Diazene-1,2-diyldiethane-1,1-

diyl)bis-4,5-dihydro-1H-imidazole 

dihydrochloride

27776-21-2 2.12 -- 193.3 3.11 × 10−14-- --

2,2'-(Octadecylimino)diethanol 10213-78-2 6.85 -- 0.08076 1.06 × 10−8 7.39 × 10−12--

2,2'-[Ethane-1,2-

diylbis(oxy)]diethanamine 929-59-9 −2.17 -- 1.00 × 106 2.50 × 10−13 8.10 × 10−16

--

2,2'-Azobis(2-amidinopropane) 

dihydrochloride 2997-92-4 −3.28 -- 1.00 × 106 1.21 × 10−14

-- --

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 1.01 0.82 2,841 6.16 × 10−14-- 1.91 × 10−8

2,2-Dibromopropanediamide 73003-80-2 0.37 -- 1.00 × 104 3.58 × 10−14-- --

2,4-Hexadienoic acid, potassium salt, 

(2E,4E)-

24634-61-5 1.62 1.33 1.94 × 104 5.72 × 10−7 4.99 × 10−8--

2,6,8-Trimethyl-4-nonanol 123-17-1 4.48 -- 24.97 9.63 × 10−5 4.45 × 10−4--
Appendix C – Chemical Mixing Supplemental Information 

C-42

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

2-Acrylamido-2-methyl-1-propanesulfonic 

acid 15214-89-8 −2.19 -- 1.00 × 106 5.18 × 10−15

-- --

2-Amino-2-methylpropan-1-ol 124-68-5 −0.74 -- 1.00 × 106 6.48 × 10−10-- --

2-Aminoethanol hydrochloride 2002-24-6 −1.61 −1.31 1.00 × 106 3.68 × 10−10 9.96 × 10−11--

2-Bromo-3-nitrilopropionamide 1113-55-9 −0.31 -- 3,274 5.35 × 10−13-- --

2-Butanone oxime 96-29-7 1.69 0.63 3.66 × 104 1.04 × 10−5-- --

2-Butoxy-1-propanol 15821-83-7 0.98 -- 4.21 × 104 1.30 × 10−7 4.88 × 10−8--

2-Butoxyethanol 111-76-2 0.57 0.83 6.45 × 104 9.79 × 10−8 2.08 × 10−8 1.60 × 10−6

2-Dodecylbenzenesulfonic acid- N-(2-

aminoethyl)ethane-1,2-diamine(1:1) 40139-72-8 4.78 -- 0.7032 6.27 × 10−8

-- --

2-Ethoxyethanol 110-80-5 −0.42 −0.32 7.55 × 105 5.56 × 10−8 1.04 × 10−8 4.70 × 10−7

2-Ethoxynaphthalene 93-18-5 3.74 -- 38.32 4.13 × 10−5 4.06 × 10−4--

2-Ethyl-1-hexanol 104-76-7 2.73 -- 1,379 3.10 × 10−5 4.66 × 10−5 2.65 × 10−5

2-Ethyl-2-hexenal 645-62-5 2.62 -- 548.6 2.06 × 10−4 4.88 × 10−4--

2-Ethylhexyl benzoate 5444-75-7 5.19 -- 1.061 2.52 × 10−4 2.34 × 10−4--

2-Hydroxyethyl acrylate 818-61-1 −0.25 −0.21 5.07 × 105 4.49 × 10−9 7.22 × 10−10--

2-Hydroxyethylammonium hydrogen 

sulphite 13427-63-9 −1.61 −1.31 1.00 × 106 3.68 × 10−10 9.96 × 10−11

--

2-Hydroxy-N,N-bis(2-hydroxyethyl)-Nmethylethanaminium chloride 7006-59-9 −6.7 -- 1.00 × 106 4.78 × 10−19

-- --

2-Mercaptoethanol 60-24-2 −0.2 -- 1.94 × 105 1.27 × 10−7 3.38 × 10−8 1.80 × 10−7
Appendix C – Chemical Mixing Supplemental Information 

C-43

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

2-Methoxyethanol 109-86-4 −0.91 −0.77 1.00 × 106 4.19 × 10−8 7.73 × 10−9 3.30 × 10−7

2-Methyl-1-propanol 78-83-1 0.77 0.76 9.71 × 104 9.99 × 10−6 1.17 × 10−5 9.78 × 10−6

2-Methyl-2,4-pentanediol 107-41-5 0.58 -- 3.26 × 104 4.06 × 10−7 3.97 × 10−10--

2-Methyl-3(2H)-isothiazolone 2682-20-4 −0.83 -- 5.37 × 105 4.96 × 10−8-- --

2-Methyl-3-butyn-2-ol 115-19-5 0.45 0.28 2.40 × 105 1.04 × 10−6-- 3.91 × 10−6

2-Methylbutane 78-78-4 2.72 -- 184.6 1.29 1.44 1.40

2-Methylquinoline hydrochloride 62763-89-7 2.69 2.59 498.5 7.60 × 10−7 2.13 × 10−6--

2-Phosphono-1,2,4-butanetricarboxylic 

acid 37971-36-1 −1.66 -- 1.00 × 106 1.17 × 10−26

-- --

2-Phosphonobutane-1,2,4-tricarboxylic 

acid, potassium salt (1:x) 93858-78-7 −1.66 -- 1.00 × 106 1.17 × 10−26

-- --

2-Propenoic acid, 2-(2-

hydroxyethoxy)ethyl ester 13533-05-6 −0.52 −0.3 3.99 × 105 6.98 × 10−11 1.54 × 10−12

--

3-(Dimethylamino)propylamine 109-55-7 −0.45 -- 1.00 × 106 6.62 × 10−9 4.45 × 10−9--

3,4,4-Trimethyloxazolidine 75673-43-7 0.13 -- 8.22 × 105 6.63 × 10−6-- --

3,5,7-Triazatricyclo(3.3.1.13,7))decane, 1-

(3-chloro-2-propenyl)-, chloride, (Z)-

51229-78-8 −5.92 -- 1.00 × 106 1.76 × 10−8-- --

3,7-Dimethyl-2,6-octadienal 5392-40-5 3.45 -- 84.71 3.76 × 10−4 4.35 × 10−5--

3-Hydroxybutanal 107-89-1 −0.72 -- 1.00 × 106 4.37 × 10−9 2.28 × 10−9--

3-Methoxypropylamine 5332-73-0 −0.42 -- 1.00 × 106 1.56 × 10−7 1.94 × 10−8--

3-Phenylprop-2-enal 104-55-2 1.82 1.9 2,150 1.60 × 10−6 3.38 × 10−7--
Appendix C – Chemical Mixing Supplemental Information 

C-44

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

4,4-Dimethyloxazolidine 51200-87-4 −0.08 -- 1.00 × 106 3.02 × 10−6-- --

4,6-Dimethyl-2-heptanone 19549-80-5 2.56 -- 528.8 2.71 × 10−4 4.55 × 10−4--

4-[Abieta-8,11,13-trien-18-yl(3-oxo-3-

phenylpropyl)amino]butan-2-one 

hydrochloride

143106-84-7 7.72 -- 0.002229 2.49 × 10−12 1.20 × 10−14--

4-Ethyloct-1-yn-3-ol 5877-42-9 2.87 -- 833.9 4.27 × 10−6-- --

4-Hydroxy-3-methoxybenzaldehyde 121-33-5 1.05 1.21 6,875 8.27 × 10−11 2.81 × 10−9 2.15 × 10−9

4-Methoxybenzyl formate 122-91-8 1.61 -- 2,679 1.15 × 10−6 2.13 × 10−6--

4-Methoxyphenol 150-76-5 1.59 1.58 1.65 × 104 3.32 × 10−8 5.35 × 10−7--

4-Methyl-2-pentanol 108-11-2 1.68 -- 1.38 × 104 1.76 × 10−5 3.88 × 10−5 4.45 × 10−5

4-Methyl-2-pentanone 108-10-1 1.16 1.31 8,888 1.16 × 10−4 1.34 × 10−4 1.38 × 10−4

4-Nonylphenol 104-40-5 5.99 5.76 1.57 5.97 × 10−6 1.23 × 10−5 3.40 × 10−5

5-Chloro-2-methyl-3(2H)-isothiazolone 26172-55-4 −0.34 -- 1.49 × 105 3.57 × 10−8-- --

Acetaldehyde 75-07-0 −0.17 −0.34 2.57 × 105 6.78 × 10−5 6.00 × 10−5 6.67 × 10−5

Acetic acid 64-19-7 0.09 −0.17 4.76 × 105 5.48 × 10−7 2.94 × 10−7 1.00 × 10−7

Acetic acid, C6-8-branched alkyl esters 90438-79-2 3.25 -- 117.8 9.60 × 10−4 1.07 × 10−3--

Acetic acid, hydroxy-, reaction products 

with triethanolamine 68442-62-6 −2.48 −1 1.00 × 106 4.18 × 10−12 3.38 × 10−19 7.05 × 10−13

Acetic acid, mercapto-, monoammonium 

salt 5421-46-5 0.03 0.09 2.56 × 105 1.94 × 10−8

-- --

Acetic anhydride 108-24-7 −0.58 -- 3.59 × 105 3.57 × 10−5-- 5.71 × 10−6
Appendix C – Chemical Mixing Supplemental Information 

C-45

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Acetone 67-64-1 −0.24 −0.24 2.20 × 105 4.96 × 10−5 3.97 × 10−5 3.50 × 10−5

Acetonitrile, 2,2',2''-nitrilotris- 7327-60-8 −1.39 -- 1.00 × 106 2.61 × 10−15-- --

Acetophenone 98-86-2 1.67 1.58 4,484 9.81 × 10−6 1.09 × 10−5 1.04 × 10−5

Acetyltriethyl citrate 77-89-4 1.34 -- 688.2 6.91 × 10−11-- --

Acrolein 107-02-8 0.19 −0.01 1.40 × 105 3.58 × 10−5 1.94 × 10−5 1.22 × 10−4

Acrylamide 79-06-1 −0.81 −0.67 5.04 × 105 5.90 × 10−9-- 1.70 × 10−9

Acrylic acid 79-10-7 0.44 0.35 1.68 × 105 2.89 × 10−7 1.17 × 10−7 3.70 × 10−7

Acrylic acid, with sodium-2-acrylamido-2-

methyl-1-propanesulfonate and sodium 

phosphinate

110224-99-2 −2.19 -- 1.00 × 106 5.18 × 10−15-- --

Alcohols, C10-12, ethoxylated 67254-71-1 5.47 -- 0.9301 1.95 × 10−2 2.03 × 10−2--

Alcohols, C11-14-iso-, C13-rich 68526-86-3 5.19 -- 5.237 1.28 × 10−4 2.62 × 10−4--

Alcohols, C11-14-iso-, C13-rich, 

ethoxylated 78330-21-9 4.91 -- 5.237 1.25 × 10−6 7.73 × 10−7

--

Alcohols, C12-13, ethoxylated 66455-14-9 5.96 -- 0.2995 2.58 × 10−2 2.87 × 10−2--

Alcohols, C12-14, ethoxylated 

propoxylated 68439-51-0 6.67 -- 0.02971 7.08 × 10−4 1.23 × 10−4

--

Alcohols, C12-14-secondary 126950-60-5 5.19 -- 5.237 1.28 × 10−4 3.62 × 10−4--

Alcohols, C12-16, ethoxylated 68551-12-2 6.45 -- 0.09603 3.43 × 10−2 4.06 × 10−2--

Alcohols, C14-15, ethoxylated 68951-67-7 7.43 -- 0.009765 6.04 × 10−2 8.10 × 10−2--

Alcohols, C6-12, ethoxylated 68439-45-2 4.49 -- 8.832 1.10 × 10−2 1.02 × 10−2--
Appendix C – Chemical Mixing Supplemental Information 

C-46

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Alcohols, C7-9-iso-, C8-rich, ethoxylated 78330-19-5 2.46 -- 1,513 3.04 × 10−7 1.38 × 10−7--

Alcohols, C9-11, ethoxylated 68439-46-3 4.98 -- 2.874 1.47 × 10−2 1.44 × 10−2--

Alcohols, C9-11-iso-, C10-rich, 

ethoxylated 78330-20-8 4.9 -- 3.321 1.47 × 10−2 2.39 × 10−2

--

Alkanes, C12-14-iso- 68551-19-9 6.65 -- 0.03173 1.24 × 101 2.28 × 101--

Alkanes, C13-16-iso- 68551-20-2 7.63 -- 0.003311 2.19 × 101 4.55 × 101--

Alkenes, C>10 alpha- 64743-02-8 8.55 -- 0.0003941 8.09 2.39 × 101--

Alkyl* dimethyl ethylbenzyl ammonium 

chloride *(50%C12, 30%C14, 17%C16, 

3%C18)

85409-23-0_1 3.97 -- 3.23 1.11 × 10−11-- --

Alkyl* dimethyl ethylbenzyl ammonium 

chloride *(60%C14, 30%C16, 5%C12, 

5%C18)

68956-79-6 4.95 -- 0.3172 1.96 × 10−11-- --

Alkylbenzenesulfonate, linear 42615-29-2 4.71 -- 0.8126 6.27 × 10−8-- --

alpha-Lactose monohydrate 5989-81-1 −5.12 -- 1.00 × 106 4.47 × 10−22 9.81 × 10−45--

alpha-Terpineol 98-55-5 3.33 2.98 371.7 1.58 × 10−5 3.15 × 10−6 1.22 × 10−5

Amaranth 915-67-3 1.63 -- 1.789 1.49 × 10−30-- --

Aminotrimethylene phosphonic acid 6419-19-8 −5.45 −3.53 1.00 × 106 1.65 × 10−34-- --

Ammonium acetate 631-61-8 0.09 −0.17 4.76 × 105 5.48 × 10−7 2.94 × 10−7 1.00 × 10−7

Ammonium acrylate 10604-69-0 0.44 0.35 1.68 × 105 2.89 × 10−7 1.17 × 10−7 3.70 × 10−7

Ammonium citrate (1:1) 7632-50-0 −1.67 −1.64 1.00 × 106 8.33 × 10−18-- 4.33 × 10−14
Appendix C – Chemical Mixing Supplemental Information 

C-47

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Ammonium citrate (2:1) 3012-65-5 −1.67 −1.64 1.00 × 106 8.33 × 10−18-- 4.33 × 10−14

Ammonium dodecyl sulfate 2235-54-3 2.42 -- 163.7 1.84 × 10−7-- --

Ammonium hydrogen carbonate 1066-33-7 −0.46 -- 8.42 × 105 6.05 × 10−9-- --

Ammonium lactate 515-98-0 −0.65 −0.72 1.00 × 106 1.13 × 10−7-- 8.13 × 10−8

Anethole 104-46-1 3.39 -- 98.68 2.56 × 10−4 2.23 × 10−3--

Aniline 62-53-3 1.08 0.9 2.08 × 104 1.90 × 10−6 2.18 × 10−6 2.02 × 10−6

Benactyzine hydrochloride 57-37-4 2.89 -- 292.1 2.07 × 10−10-- --

Benzamorf 12068-08-5 4.71 -- 0.8126 6.27 × 10−8-- --

Benzene 71-43-2 1.99 2.13 2,000 5.39 × 10−3 5.35 × 10−3 5.55 × 10−3

Benzene, C10-16-alkyl derivatives 68648-87-3 8.43 9.36 0.0002099 1.78 × 10−1 3.97 × 10−1--

Benzenesulfonic acid 98-11-3 −1.17 -- 6.90 × 105 2.52 × 10−9-- --

Benzenesulfonic acid, (1-methylethyl)-, 37953-05-2 0.29 -- 2.46 × 104 4.89 × 10−9-- --

Benzenesulfonic acid, (1-methylethyl)-, 

ammonium salt 37475-88-0 0.29 -- 2.46 × 104 4.89 × 10−9

-- --

Benzenesulfonic acid, (1-methylethyl)-, 

sodium salt 28348-53-0 0.29 -- 2.46 × 104 4.89 × 10−9

-- --

Benzenesulfonic acid, C10-16-alkyl 

derivatives, compounds with 

cyclohexylamine

255043-08-4 4.71 -- 0.8126 6.27 × 10−8-- --
Appendix C – Chemical Mixing Supplemental Information 

C-48

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Benzenesulfonic acid, C10-16-alkyl 

derivatives, compounds with 

triethanolamine

68584-25-8 5.2 -- 0.255 8.32 × 10−8-- --

Benzenesulfonic acid, C10-16-alkyl 

derivatives, potassium salts 68584-27-0 5.2 -- 0.255 8.32 × 10−8

-- --

Benzenesulfonic acid, dodecyl-, branched, 

compounds with 2-propanamine 90218-35-2 4.49 -- 1.254 6.27 × 10−8

-- --

Benzenesulfonic acid, mono-C10-16-alkyl 

derivatives, sodium salts 68081-81-2 4.22 -- 2.584 4.72 × 10−8

-- --

Benzoic acid 65-85-0 1.87 1.87 2,493 1.08 × 10−7 4.55 × 10−8 3.81 × 10−8

Benzyl chloride 100-44-7 2.79 2.3 1,030 2.09 × 10−3 3.97 × 10−4 4.12 × 10−4

Benzyldimethyldodecylammonium 

chloride 139-07-1 2.93 -- 36.47 7.61 × 10−12

-- --

Benzylhexadecyldimethylammonium 

chloride 122-18-9 4.89 -- 0.3543 2.36 × 10−11

-- --

Benzyltrimethylammonium chloride 56-93-9 −2.47 -- 1.00 × 106 3.37 × 10−13-- --

Bicine 150-25-4 −3.27 -- 3.52 × 105 1.28 × 10−14-- --

Bis(1-methylethyl)naphthalenesulfonic 

acid, cyclohexylamine salt 68425-61-6 2.92 -- 43.36 9.29 × 10−10

-- --

Bis(2-chloroethyl) ether 111-44-4 1.56 1.29 6,435 1.89 × 10−4 4.15 × 10−7 1.70 × 10−5

Bisphenol A 80-05-7 3.64 3.32 172.7 9.16 × 10−12-- --

Bronopol 52-51-7 −1.51 -- 8.37 × 105 6.35 × 10−21-- --
Appendix C – Chemical Mixing Supplemental Information 

C-49

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Butane 106-97-8 2.31 2.89 135.6 9.69 × 10−1 8.48 × 10−1 9.50 × 10−1

Butanedioic acid, sulfo-, 1,4-bis(1,3-

dimethylbutyl) ester, sodium salt 2373-38-8 3.98 -- 0.1733 1.61 × 10−12

-- --

Butene 25167-67-3 2.17 2.4 354.8 2.03 × 10−1 2.68 × 10−1 2.33 × 10−1

Butyl glycidyl ether 2426-08-6 1.08 0.63 2.66 × 104 4.37 × 10−6 5.23 × 10−7 2.47 × 10−5

Butyl lactate 138-22-7 0.8 -- 5.30 × 104 8.49 × 10−5-- 1.92 × 10−6

Butyryl trihexyl citrate 82469-79-2 8.21 -- 5.56 × 10−5 3.65 × 10−9-- --

C.I. Acid Red 1 3734-67-6 0.51 -- 6.157 3.73 × 10−29-- --

C.I. Acid Violet 12, disodium salt 6625-46-3 0.59 -- 3.379 2.21 × 10−30-- --

C.I. Pigment Red 5 6410-41-9 7.65 -- 4.38 × 10−5 4.36 × 10−21-- --

C.I. Solvent Red 26 4477-79-6 9.27 -- 5.68 × 10−5 5.48 × 10−13 4.66 × 10−13--

C10-16-Alkyldimethylamines oxides 70592-80-2 2.87 -- 89.63 1.14 × 10−13-- --

C10-C16 Ethoxylated alcohol 68002-97-1 4.99 -- 4.532 1.25 × 10−6 4.66 × 10−7--

C12-14 tert-Alkyl ethoxylated amines 73138-27-9 3.4 -- 264.2 1.29 × 10−10-- --

Calcium dodecylbenzene sulfonate 26264-06-2 4.71 -- 0.8126 6.27 × 10−8-- --

Camphor 76-22-2 3.04 2.38 339.1 7.00 × 10−5-- 8.10 × 10−5

Carbon dioxide 124-38-9 0.83 0.83 2.57 × 104 1.52 × 10−2-- 1.52 × 10−2

Carbonic acid, dipotassium salt 584-08-7 −0.46 -- 8.42 × 105 6.05 × 10−9-- --

Chloromethane 74-87-3 1.09 0.91 2.26× 104 8.20× 10−3 8.88× 10−3 8.82× 10−3
Appendix C – Chemical Mixing Supplemental Information 

C-50

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Chlorobenzene 108-90-7 2.64 2.84 400.5 3.99× 10−3 4.55× 10−3 3.11× 10−3

Choline bicarbonate 78-73-9 −5.16 -- 1.00 × 106 2.03 × 10−16-- --

Choline chloride 67-48-1 −5.16 -- 1.00 × 106 2.03 × 10−16-- --

Citric acid 77-92-9 −1.67 −1.64 1.00 × 106 8.33 × 10−18-- 4.33 × 10−14

Citronellol 106-22-9 3.56 3.91 105.5 5.68 × 10−5 2.13 × 10−5--

Coconut trimethylammonium chloride 61789-18-2 1.22 -- 2,816 9.42 × 10−11-- --

Coumarin 91-64-5 1.51 1.39 5,126 6.95 × 10−6-- 9.92 × 10−8

Cumene 98-82-8 3.45 3.66 75.03 1.05 × 10−2 1.23 × 10−2 1.15 × 10−2

Cyclohexane 110-82-7 3.18 3.44 43.02 2.55 × 10−1 1.94 × 10−1 1.50 × 10−1

Cyclohexanol 108-93-0 1.64 1.23 3.37 × 104 4.90 × 10−6 3.70 × 10−6 4.40 × 10−6

Cyclohexanone 108-94-1 1.13 0.81 2.41 × 104 5.11 × 10−5 1.28 × 10−5 9.00 × 10−6

Cyclohexylamine sulfate 19834-02-7 1.63 1.49 6.40 × 104 1.38 × 10−5-- 4.16 × 10−6

D&C Red no. 28 18472-87-2 9.62 -- 1.64 × 10−8 6.37 × 10−21-- --

D&C Red no. 33 3567-66-6 0.48 -- 11.87 1.15 × 10−26-- --

Daidzein 486-66-8 2.55 -- 568.4 3.91 × 10−16-- --

Dapsone 80-08-0 0.77 0.97 3,589 3.11 × 10−14-- --

Dazomet 533-74-4 0.94 0.63 1.94 × 104 2.84 × 10−3-- 4.98 × 10−10

Decyldimethylamine 1120-24-7 4.46 -- 82.23 4.68 × 10−4 2.45 × 10−3--

D-Glucitol 50-70-4 −3.01 −2.2 1.00 × 106 7.26 × 10−13 2.94 × 10−29--
Appendix C – Chemical Mixing Supplemental Information 

C-51

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

D-Gluconic acid 526-95-4 −1.87 -- 1.00 × 106 4.74 × 10−13-- --

D-Glucopyranoside, methyl 3149-68-6 −2.5 -- 1.00 × 106 1.56 × 10−14 2.23 × 10−24--

D-Glucose 50-99-7 −2.89 −3.24 1.00 × 106 9.72 × 10−15 1.62 × 10−26--

Di(2-ethylhexyl) phthalate 117-81-7 8.39 7.6 0.001132 1.18 × 10−5 1.02 × 10−5 2.70 × 10−7

Dibromoacetonitrile 3252-43-5 0.47 -- 9,600 4.06 × 10−7-- --

Dichloromethane 75-09-2 1.34 1.25 1.10 × 104 9.14 × 10−3 3.01 × 10−3 3.25 × 10−3

Didecyldimethylammonium chloride 7173-51-5 4.66 -- 0.9 6.85 × 10−10-- --

Diethanolamine 111-42-2 −1.71 −1.43 1.00 × 106 3.92 × 10−11 3.46 × 10−15 3.87 × 10−11

Diethylbenzene 25340-17-4 4.07 3.72 58.86 1.16 × 10−2 1.47 × 10−2 2.61 × 10−3

Diethylene glycol 111-46-6 −1.47 -- 1.00 × 106 2.03 × 10−9 1.20 × 10−13--

Diethylene glycol monomethyl ether 111-77-3 −1.18 -- 1.00 × 106 6.50 × 10−10 1.65 × 10−11--

Diethylenetriamine 111-40-0 −2.13 -- 1.00 × 106 3.10 × 10−13 1.09 × 10−14--

Diisobutyl ketone 108-83-8 2.56 -- 528.8 2.71 × 10−4 4.55 × 10−4 1.17 × 10−4

Diisopropanolamine 110-97-4 −0.88 −0.82 1.00 × 106 6.91 × 10−11 1.90 × 10−14--

Diisopropylnaphthalene 38640-62-9 6.08 -- 0.2421 1.99 × 10−3 1.94 × 10−3--

Dimethyl adipate 627-93-0 1.39 1.03 7,749 9.77 × 10−7 1.28 × 10−7 2.31 × 10−6

Dimethyl glutarate 1119-40-0 0.9 0.62 2.02 × 104 7.36 × 10−7 9.09 × 10−8 6.43 × 10−7

Dimethyl succinate 106-65-0 0.4 0.35 3.96 × 104 5.54 × 10−7 6.43 × 10−8--

Dimethylaminoethanol 108-01-0 −0.94 -- 1.00 × 106 1.77 × 10−9 1.77 × 10−9 3.73 × 10−7
Appendix C – Chemical Mixing Supplemental Information 

C-52

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Dimethyldiallylammonium chloride 7398-69-8 −2.49 -- 1.00 × 106 7.20 × 10−12-- --

Diphenyl oxide 101-84-8 4.05 4.21 15.58 1.18 × 10−4 2.81 × 10−4 2.79 × 10−4

Dipropylene glycol 25265-71-8 −0.64 -- 3.11 × 105 3.58 × 10−9 6.29 × 10−10--

Di-sec-butylphenol 31291-60-8 5.41 -- 3.723 3.74 × 10−6 6.89 × 10−6--

Disodium 

dodecyl(sulphonatophenoxy)benzenesulp

honate

28519-02-0 5.05 -- 0.0353 6.40 × 10−16-- --

Disodium ethylenediaminediacetate 38011-25-5 −4.79 -- 1.00 × 106 1.10 × 10−16-- --

Disodium ethylenediaminetetraacetate 

dihydrate 6381-92-6 −3.86 -- 2.28 × 105 1.17 × 10−23

-- 5.77 × 10−16

D-Lactic acid 10326-41-7 −0.65 −0.72 1.00 × 106 1.13 × 10−7-- 8.13 × 10−8

D-Limonene 5989-27-5 4.83 4.57 4.581 3.80 × 10−1-- 3.19 × 10−2

Docusate sodium 577-11-7 6.1 -- 0.001227 5.00 × 10−12-- --

Dodecane 112-40-3 6.23 6.1 0.1099 9.35 1.34 × 101 8.18

Dodecylbenzene 123-01-3 7.94 8.65 0.001015 1.34 × 10−1 2.81 × 10−1--

Dodecylbenzenesulfonic acid 27176-87-0 4.71 -- 0.8126 6.27 × 10−8-- --

Dodecylbenzenesulfonic acid, 

monoethanolamine salt 26836-07-7 4.71 -- 0.8126 6.27 × 10−8

-- --

Epichlorohydrin 106-89-8 0.63 0.45 5.06 × 104 5.62 × 10−5 2.62 × 10−6 3.04 × 10−5

Ethanaminium, N,N,N-trimethyl-2-[(1-

oxo-2-propenyl)oxy]-, chloride 44992-01-0 −3.1 -- 1.00 × 106 6.96 × 10−15

-- --
Appendix C – Chemical Mixing Supplemental Information 

C-53

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Ethane 74-84-0 1.32 1.81 938.6 5.50 × 10−1 4.25 × 10−1 5.00 × 10−1

Ethanol 64-17-5 −0.14 −0.31 7.92 × 105 5.67 × 10−6 4.88 × 10−6 5.00 × 10−6

Ethanol, 2,2',2''-nitrilotris-, 

tris(dihydrogen phosphate) (ester), 

sodium salt

68171-29-9 −3.13 -- 1.00 × 106 3.08 × 10−36-- --

Ethanol, 2-[2-[2-

(tridecyloxy)ethoxy]ethoxy]-, hydrogen 

sulfate, sodium salt

25446-78-0 2.09 -- 42 9.15 × 10−13-- --

Ethanolamine 141-43-5 −1.61 −1.31 1.00 × 106 3.68 × 10−10 9.96 × 10−11--

Ethoxylated dodecyl alcohol 9002-92-0 4.5 -- 14.19 9.45 × 10−7 3.30 × 10−7--

Ethyl acetate 141-78-6 0.86 0.73 2.99 × 104 2.33 × 10−4 1.58 × 10−4 1.34 × 10−4

Ethyl acetoacetate 141-97-9 −0.2 0.25 5.62 × 104 1.57 × 10−7-- 1.20 × 10−6

Ethyl benzoate 93-89-0 2.32 2.64 421.5 4.61 × 10−5 2.45 × 10−5 7.33 × 10−5

Ethyl lactate 97-64-3 −0.18 -- 4.73 × 105 4.82 × 10−5-- 5.83 × 10−7

Ethyl salicylate 118-61-6 3.09 2.95 737.1 6.04 × 10−6 3.01 × 10−9--

Ethylbenzene 100-41-4 3.03 3.15 228.6 7.89 × 10−3 8.88 × 10−3 7.88 × 10−3

Ethylene 74-85-1 1.27 1.13 3,449 9.78 × 10−2 1.62 × 10−1 2.28 × 10−1

Ethylene glycol 107-21-1 −1.2 −1.36 1.00 × 106 1.31 × 10−7 5.60 × 10−11 6.00 × 10−8

Ethylene oxide 75-21-8 −0.05 −0.3 2.37 × 105 1.20 × 10−4 5.23 × 10−5 1.48 × 10−4

Ethylenediamine 107-15-3 −1.62 −2.04 1.00 × 106 1.03 × 10−9 1.77 × 10−10 1.73 × 10−9

Ethylenediaminetetraacetic acid 60-00-4 −3.86 -- 2.28 × 105 1.17 × 10−23-- 5.77 × 10−16
Appendix C – Chemical Mixing Supplemental Information 

C-54

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Ethylenediaminetetraacetic acid 

tetrasodium salt 64-02-8 −3.86 -- 2.28 × 105 1.17 × 10−23

-- 5.77 × 10−16

Ethylenediaminetetraacetic acid, 

disodium salt 139-33-3 −3.86 -- 2.28 × 105 1.17 × 10−23

-- 5.77 × 10−16

Ethyne 74-86-2 0.5 0.37 1.48 × 104 2.40 × 10−2 2.45 × 10−2 2.17 × 10−2

Fatty acids, C18-unsaturated, dimers 61788-89-4 14.6 -- 2.31 × 10−10 4.12 × 10−8 9.74 × 10−9--

FD&C Blue no. 1 3844-45-9 −0.15 -- 0.2205 2.25 × 10−35-- --

FD&C Yellow no. 5 1934-21-0 −1.82 -- 7.388 1.31 × 10−28-- --

FD&C Yellow no. 6 2783-94-0 1.4 -- 242.7 3.26 × 10−23-- --

Formaldehyde 50-00-0 0.35 0.35 5.70 × 104 9.29 × 10−5 6.14 × 10−5 3.37 × 10−7

Formamide 75-12-7 −1.61 −1.51 1.00 × 106 1.53 × 10−8-- 1.39 × 10−9

Formic acid 64-18-6 −0.46 −0.54 9.55 × 105 7.50 × 10−7 5.11 × 10−7 1.67 × 10−7

Formic acid, potassium salt 590-29-4 −0.46 −0.54 9.55 × 105 7.50 × 10−7 5.11 × 10−7 1.67 × 10−7

Fumaric acid 110-17-8 0.05 −0.48 1.04 × 105 1.35 × 10−12 8.48 × 10−14--

Furfural 98-01-1 0.83 0.41 5.36 × 104 1.34 × 10−5-- 3.77 × 10−6

Furfuryl alcohol 98-00-0 0.45 0.28 2.21 × 105 2.17 × 10−7-- 7.86 × 10−8

Galantamine hydrobromide 69353-21-5 2.29 -- 1,606 1.70 × 10−13-- --

Gluconic acid 133-42-6 −1.87 -- 1.00 × 106 4.74 × 10−13-- --

Glutaraldehyde 111-30-8 −0.18 -- 1.67 × 105 1.10 × 10−7 2.39 × 10−8--

Glycerol 56-81-5 −1.65 −1.76 1.00 × 106 6.35 × 10−9 1.51 × 10−15 1.73 × 10−8
Appendix C – Chemical Mixing Supplemental Information 

C-55

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Glycine, N-(carboxymethyl)-N-(2-

hydroxyethyl)-, disodium salt 135-37-5 −3.04 -- 1.90 × 105 3.90 × 10−17

-- --

Glycine, N-(hydroxymethyl)-, 

monosodium salt 70161-44-3 −3.41 -- 7.82 × 105 1.80 × 10−12

-- --

Glycine, N,N-bis(carboxymethyl)-, 

trisodium salt 5064-31-3 −3.81 -- 7.39 × 105 1.19 × 10−16

-- --

Glycine, N-[2-

[bis(carboxymethyl)amino]ethyl]-N-(2-

hydroxyethyl)-, trisodium salt

139-89-9 −4.09 -- 4.31 × 105 3.81 × 10−24-- --

Glycolic acid 79-14-1 −1.07 −1.11 1.00 × 106 8.54 × 10−8 6.29 × 10−11--

Glycolic acid sodium salt 2836-32-0 −1.07 −1.11 1.00 × 106 8.54 × 10−8 6.29 × 10−11--

Glyoxal 107-22-2 −1.66 -- 1.00 × 106 3.70 × 10−7-- 3.33 × 10−9

Glyoxylic acid 298-12-4 −1.4 -- 1.00 × 106 2.98 × 10−9-- --

Heptane 142-82-5 3.78 4.66 3.554 2.27 2.39 2.00

Hexadecyltrimethylammonium bromide 57-09-0 3.18 -- 28.77 2.93 × 10−10-- --

Hexane 110-54-3 3.29 3.9 17.24 1.71 1.69 1.80

Hexanedioic acid 124-04-9 0.23 0.08 1.67 × 105 9.53 × 10−12 8.10 × 10−13 4.71 × 10−12

Hydroxyvalerenic acid 1619-16-5 3.31 -- 282.1 -- -- --

Indole 120-72-9 2.05 2.14 1,529 8.86 × 10−7 1.99 × 10−6 5.28 × 10−7

Isoascorbic acid 89-65-6 −1.88 −1.85 1.00 × 106 4.07 × 10−8-- --

Isobutane 75-28-5 2.23 2.76 175.1 9.69 × 10−1 1.02 1.19
Appendix C – Chemical Mixing Supplemental Information 

C-56

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Isobutene 115-11-7 2.23 2.34 399.2 2.40 × 10−1 2.34 × 10−1 2.18 × 10−1

Isooctanol 26952-21-6 2.73 -- 1,379 3.10 × 10−5 4.66 × 10−5 9.21 × 10−5

Isopentyl alcohol 123-51-3 1.26 1.16 4.16 × 104 1.33 × 10−5 1.65 × 10−5 1.41 × 10−5

Isopropanol 67-63-0 0.28 0.05 4.02 × 105 7.52 × 10−6 1.14 × 10−5 8.10 × 10−6

Isopropanolamine dodecylbenzene 42504-46-1 7.94 8.65 0.001015 1.34 × 10−1 2.81 × 10−1--

Isopropylamine 75-31-0 0.27 0.26 8.38 × 105 1.34 × 10−5-- 4.51 × 10−5

Isoquinoline 119-65-3 2.14 2.08 1,551 6.88 × 10−7 4.15 × 10−7--

Isoquinoline, reaction products with 

benzyl chloride and quinoline 68909-80-8 2.14 2.08 1,551 6.88 × 10−7 4.15 × 10−7

--

Isoquinolinium, 2-(phenylmethyl)-, 

chloride 35674-56-7 4.4 -- 6.02 1.19 × 10−6

-- --

Lactic acid 50-21-5 −0.65 −0.72 1.00 × 106 1.13 × 10−7-- 8.13 × 10−8

Lactose 63-42-3 −5.12 -- 1.00 × 106 4.47 × 10−22 9.81 × 10−45--

Lauryl hydroxysultaine 13197-76-7 −1.3 -- 7.71 × 104 1.04 × 10−21-- --

L-Dilactide 4511-42-6 1.65 -- 3,165 1.22 × 10−5-- --

L-Glutamic acid 56-86-0 −3.83 −3.69 9.42 × 105 1.47 × 10−14-- --

L-Lactic acid 79-33-4 −0.65 −0.72 1.00 × 106 1.13 × 10−7-- 8.13 × 10−8

Methane 74-82-8 0.78 1.09 2,610 4.14 × 10−1 6.58 × 10−1 6.58 × 10−1

Methanol 67-56-1 −0.63 −0.77 1.00 × 106 4.27 × 10−6 3.62 × 10−6 4.55 × 10−6

Methenamine 100-97-0 −4.15 -- 1.00 × 106 1.63 × 10−1-- 1.64 × 10−9
Appendix C – Chemical Mixing Supplemental Information 

C-57

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Methoxyacetic acid 625-45-6 −0.68 -- 1.00 × 106 4.54 × 10−8 8.68 × 10−9 6.42 × 10−9

Methyl salicylate 119-36-8 2.6 2.55 1,875 4.55 × 10−6 2.23 × 10−9 9.81 × 10−5

Methyl vinyl ketone 78-94-4 0.41 -- 6.06 × 104 2.61 × 10−5 1.38 × 10−5 4.65 × 10−5

Methylcyclohexane 108-87-2 3.59 3.61 28.4 3.39 × 10−1 3.30 × 10−1 4.30 × 10−1

Methylene bis(thiocyanate) 6317-18-6 0.62 -- 2.72 × 104 2.61 × 10−8-- --

Methylenebis(5-methyloxazolidine) 66204-44-2 −0.58 -- 1.00 × 106 1.07 × 10−7-- --

Morpholine 110-91-8 −0.56 −0.86 1.00 × 106 1.14 × 10−7 3.22 × 10−9 1.16 × 10−6

Morpholinium, 4-ethyl-4-hexadecyl-, 

ethyl sulfate 78-21-7 4.54 -- 0.9381 2.66 × 10−12

-- --

N-(2-Acryloyloxyethyl)-N-benzyl-N,Ndimethylammonium chloride 46830-22-2 −1.39 -- 4.42 × 105 5.62 × 10−16

-- --

N-(3-Chloroallyl)hexaminium chloride 4080-31-3 −5.92 -- 1.00 × 106 1.76 × 10−8-- --

N,N,N-Trimethyl-3-((1-

oxooctadecyl)amino)-1-propanaminium 

methyl sulfate

19277-88-4 4.38 -- 0.7028 2.28 × 10−16-- --

N,N,N-Trimethyloctadecan-1-aminium 

chloride 112-03-8 4.17 -- 2.862 5.16 × 10−10

-- --

N,N'-Dibutylthiourea 109-46-6 2.57 2.75 2,287 4.17 × 10−6-- --

N,N-Dimethyldecylamine oxide 2605-79-0 1.4 -- 2,722 4.88 × 10−14-- --

N,N-Dimethylformamide 68-12-2 −0.93 −1.01 9.78 × 105 7.38 × 10−8-- 7.39 × 10−8
Appendix C – Chemical Mixing Supplemental Information 

C-58

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

N,N-Dimethylmethanamine 

hydrochloride 593-81-7 0.04 0.16 1.00 × 106 3.65 × 10−5 1.28 × 10−4 1.04 × 10−4

N,N-Dimethyl-methanamine-N-oxide 1184-78-7 −3.02 -- 1.00 × 106 3.81 × 10−15-- --

N,N-dimethyloctadecylamine 

hydrochloride 1613-17-8 8.39 -- 0.008882 4.51 × 10−3 3.88 × 10−2

--

N,N'-Methylenebisacrylamide 110-26-9 −1.52 -- 7.01 × 104 1.14 × 10−9-- --

Naphthalene 91-20-3 3.17 3.3 142.1 5.26 × 10−4 3.70 × 10−4 4.40 × 10−4

Naphthalenesulfonic acid, bis(1-

methylethyl)-

28757-00-8 2.92 -- 43.36 9.29 × 10−10-- --

Naphthalenesulphonic acid, bis (1-

methylethyl)-methyl derivatives 99811-86-6 4.02 -- 3.45 1.13 × 10−9

-- --

Naphthenic acid ethoxylate 68410-62-8 3.41 -- 112.5 3.62 × 10−8 2.74 × 10−9--

Nitrilotriacetamide 4862-18-4 −4.75 -- 1.00 × 106 1.61 × 10−18-- --

Nitrilotriacetic acid 139-13-9 −3.81 -- 7.39 × 105 1.19 × 10−16-- --

Nitrilotriacetic acid trisodium 

monohydrate 18662-53-8 −3.81 -- 7.39 × 105 1.19 × 10−16

-- --

N-Methyl-2-pyrrolidone 872-50-4 −0.11 −0.38 2.48 × 105 3.16 × 10−8-- 3.20 × 10−9

N-Methyldiethanolamine 105-59-9 −1.5 -- 1.00 × 106 8.61 × 10−11 2.45 × 10−14 3.14 × 10−11

N-Methylethanolamine 109-83-1 −1.15 −0.94 1.00 × 106 8.07 × 10−10 2.50 × 10−10--

N-Methyl-N-hydroxyethyl-Nhydroxyethoxyethylamine 68213-98-9 −1.78 -- 1.00 × 106 1.34 × 10−12 5.23 × 10−17

--
Appendix C – Chemical Mixing Supplemental Information 

C-59

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

N-Oleyl diethanolamide 13127-82-7 6.63 -- 0.1268 9.35 × 10−9 1.94 × 10−12--

Oleic acid 112-80-1 7.73 7.64 0.01151 4.48 × 10−5 1.94 × 10−5--

Pentaethylenehexamine 4067-16-7 −3.67 -- 1.00 × 106 8.36 × 10−24 2.56 × 10−27--

Pentane 109-66-0 2.8 3.39 49.76 1.29 1.20 1.25

Pentyl acetate 628-63-7 2.34 2.3 996.8 5.45 × 10−4 4.45 × 10−4 3.88 × 10−4

Pentyl butyrate 540-18-1 3.32 -- 101.9 9.60 × 10−4 8.88 × 10−4--

Peracetic acid 79-21-0 −1.07 -- 1.00 × 106 1.39 × 10−6-- 2.14 × 10−6

Phenanthrene 85-01-8 4.35 4.46 0.677 5.13 × 10−5 2.56 × 10−5 4.23 × 10−5

Phenol 108-95-2 1.51 1.46 2.62 × 104 5.61 × 10−7 6.58 × 10−7 3.33 × 10−7

Phosphonic acid 

(dimethylamino(methylene)) 29712-30-9 −1.9 -- 1.00 × 106 1.00 × 10−24

-- --

Phosphonic acid, (((2-[(2-hydroxyethyl) 

(phosphonomethyl)amino)ethyl)imino]bis

(methylene))bis-, compd. with 2-

aminoethanol

129828-36-0 −6.73 -- 1.00 × 106 5.29 × 10−42-- --

Phosphonic acid, (1-hydroxyethylidene)

bis-, potassium salt 67953-76-8 −0.01 -- 1.34 × 105 9.79 × 10−26

-- --

Phosphonic acid, (1-hydroxyethylidene)

bis-, tetrasodium salt 3794-83-0 −0.01 -- 1.34 × 105 9.79 × 10−26

-- --

Phosphonic acid, [[(phosphonomethyl)

imino]bis[2,1-ethanediylnitrilobis

(methylene)]]tetrakis15827-60-8 −9.72 -- 1.00 × 106

-- -- --
Appendix C – Chemical Mixing Supplemental Information 

C-60

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Phosphonic acid, [[(phosphonomethyl)

imino]bis[2,1-ethanediylnitrilobis

(methylene)]]tetrakis-, ammonium salt 

(1:x)

70714-66-8 −9.72 -- 1.00 × 106-- -- --

Phosphonic acid, [[(phosphonomethyl)

imino]bis[2,1-ethanediylnitrilobis

(methylene)]]tetrakis-, sodium salt

22042-96-2 −9.72 -- 1.00 × 106-- -- --

Phosphonic acid, [[(phosphonomethyl)

imino]bis[6,1-hexanediylnitrilobis

(methylene)]]tetrakis34690-00-1 −5.79 -- 1.00 × 106

-- -- --

Phthalic anhydride 85-44-9 2.07 1.6 3,326 6.35 × 10−6-- 1.63 × 10−8

Poly(oxy-1,2-ethanediyl), 

.alpha.-(octylphenyl)-.omega.-hydroxy-, 

branched

68987-90-6 5.01 -- 3.998 1.24 × 10−7 1.07 × 10−6--

Potassium acetate 127-08-2 0.09 −0.17 4.76 × 105 5.48 × 10−7 2.94 × 10−7 1.00 × 10−7

Potassium oleate 143-18-0 7.73 7.64 0.01151 4.48 × 10−5 1.94 × 10−5--

Propane 74-98-6 1.81 2.36 368.9 7.30 × 10−1 6.00 × 10−1 7.07 × 10−1

Propanol, 1(or 2)-(2-

methoxymethylethoxy)-

34590-94-8 −0.27 -- 4.27 × 105 1.15 × 10−9 1.69 × 10−9--

Propargyl alcohol 107-19-7 −0.42 −0.38 9.36 × 105 5.88 × 10−7-- 1.15 × 10−6

Propylene carbonate 108-32-7 0.08 −0.41 2.58 × 105 3.63 × 10−4-- 3.45 × 10−8

Propylene pentamer 15220-87-8 6.28 -- 0.05601 3.92 × 10−1 1.09 × 10−3--

p-Xylene 106-42-3 3.09 3.15 228.6 6.56 × 10−3 6.14 × 10−3 6.90 × 10−3
Appendix C – Chemical Mixing Supplemental Information 

C-61

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Pyrimidine 289-95-2 −0.06 −0.4 2.87 × 105 2.92 × 10−6-- --

Pyrrole 109-97-7 0.88 0.75 3.12 × 104 9.07 × 10−6 7.73 × 10−6 1.80 × 10−5

Quaternary ammonium compounds, diC8-10-alkyldimethyl, chlorides 68424-95-3 2.69 -- 90.87 2.20 × 10−10

-- --

Quinaldine 91-63-4 2.69 2.59 498.5 7.60 × 10−7 2.13 × 10−6--

Quinoline 91-22-5 2.14 2.03 1,711 6.88 × 10−7 1.54 × 10−6 1.67 × 10−6

Rhodamine B 81-88-9 6.03 -- 0.0116 -- -- --

Sodium 1-octanesulfonate 5324-84-5 1.06 -- 5,864 9.15 × 10−8-- --

Sodium 2-mercaptobenzothiolate 2492-26-4 2.86 2.42 543.4 3.63 × 10−8-- --

Sodium acetate 127-09-3 0.09 −0.17 4.76 × 105 5.48 × 10−7 2.94 × 10−7 1.00 × 10−7

Sodium benzoate 532-32-1 1.87 1.87 2,493 1.08 × 10−7 4.55 × 10−8 3.81 × 10−8

Sodium bicarbonate 144-55-8 −0.46 -- 8.42 × 105 6.05 × 10−9-- --

Sodium bis(tridecyl) sulfobutanedioate 2673-22-5 11.15 -- 7.46 × 10−9 8.51 × 10−11-- --

Sodium C14-16 alpha-olefin sulfonate 68439-57-6 4.36 -- 2.651 4.95 × 10−7-- --

Sodium caprylamphopropionate 68610-44-6 −0.26 -- 615.1 1.19 × 10−9 2.45 × 10−10--

Sodium carbonate 497-19-8 −0.46 -- 8.42 × 105 6.05 × 10−9-- --

Sodium chloroacetate 3926-62-3 0.34 0.22 1.95 × 105 1.93 × 10−7 8.88 × 10−8 9.26 × 10−9

Sodium decyl sulfate 142-87-0 1.44 -- 1,617 1.04 × 10−7-- --

Sodium D-gluconate 527-07-1 −1.87 -- 1.00 × 106 4.74 × 10−13-- --
Appendix C – Chemical Mixing Supplemental Information 

C-62

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Sodium diacetate 126-96-5 0.09 −0.17 4.76 × 105 5.48 × 10−7 2.94 × 10−7 1.00 × 10−7

Sodium dichloroisocyanurate 2893-78-9 1.28 -- 3,613 3.22 × 10−12-- --

Sodium dl-lactate 72-17-3 −0.65 −0.72 1.00 × 106 1.13 × 10−7-- 8.13 × 10−8

Sodium dodecyl sulfate 151-21-3 2.42 -- 163.7 1.84 × 10−7-- --

Sodium erythorbate (1:1) 6381-77-7 −1.88 −1.85 1.00 × 106 4.07 × 10−8-- --

Sodium ethasulfate 126-92-1 0.38 -- 1.82 × 104 5.91 × 10−8-- --

Sodium formate 141-53-7 −0.46 −0.54 9.55 × 105 7.50 × 10−7 5.11 × 10−7 1.67 × 10−7

Sodium hydroxymethanesulfonate 870-72-4 −3.85 -- 1.00 × 106 4.60 × 10−13-- --

Sodium l-lactate 867-56-1 −0.65 −0.72 1.00 × 106 1.13 × 10−7-- 8.13 × 10−8

Sodium maleate (1:x) 18016-19-8 0.05 −0.48 1.04 × 105 1.35 × 10−12 8.48 × 10−14--

Sodium N-methyl-N-oleoyltaurate 137-20-2 4.43 -- 0.4748 1.00 × 10−12-- --

Sodium octyl sulfate 142-31-4 0.46 -- 1.58 × 104 5.91 × 10−8-- --

Sodium salicylate 54-21-7 2.24 2.26 3,808 1.42 × 10−8 5.60 × 10−12 7.34 × 10−9

Sodium sesquicarbonate 533-96-0 −0.46 -- 8.42 × 105 6.05 × 10−9-- --

Sodium thiocyanate 540-72-7 0.58 -- 4.36 × 104 1.46 × 10−4-- --

Sodium trichloroacetate 650-51-1 1.44 1.33 1.20 × 104 2.39 × 10−8-- 1.35 × 10−8

Sodium xylenesulfonate 1300-72-7 −0.07 -- 5.89 × 104 3.06 × 10−9-- --

Sorbic acid 110-44-1 1.62 1.33 1.94 × 104 5.72 × 10−7 4.99 × 10−8--

Sorbitan sesquioleate 8007-43-0 14.32 -- 2.31 × 10−11 7.55 × 10−12 1.25 × 10−16--
Appendix C – Chemical Mixing Supplemental Information 

C-63

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Sorbitan, mono-(9Z)-9-octadecenoate 1338-43-8 5.89 -- 0.01914 1.42 × 10−12 5.87 × 10−20--

Sorbitan, monooctadecanoate 1338-41-6 6.1 -- 0.01218 1.61 × 10−12 2.23 × 10−19--

Sorbitan, tri-(9Z)-9-octadecenoate 26266-58-0 22.56 -- 1.12 × 10−19 4.02 × 10−11 2.68 × 10−13--

Styrene 100-42-5 2.89 2.95 343.7 2.76 × 10−3 2.81 × 10−3 2.75 × 10−3

Sucrose 57-50-1 −4.27 −3.7 1.00 × 106 4.47 × 10−22-- --

Sulfan blue 129-17-9 −1.34 -- 50.67 1.31 × 10−26-- --

Sulfuric acid, mono-C12-18-alkyl esters, 

sodium salts 68955-19-1 3.9 -- 5.165 4.29 × 10−7

-- --

Sulfuric acid, mono-C6-10-alkyl esters, 

ammonium salts 68187-17-7 0.46 -- 1.58 × 104 5.91 × 10−8

-- --

Symclosene 87-90-1 0.94 -- 4,610 6.19 × 10−11-- --

tert-Butyl hydroperoxide 75-91-2 0.94 -- 1.97 × 104 1.60 × 10−5-- --

tert-Butyl perbenzoate 614-45-9 2.89 -- 159.2 2.06 × 10−4-- --

Tetradecane 629-59-4 7.22 7.2 0.009192 1.65 × 101 2.68 × 101 9.20

Tetradecyldimethylbenzylammonium 

chloride 139-08-2 3.91 -- 3.608 1.34 × 10−11

-- --

Tetraethylene glycol 112-60-7 −2.02 -- 1.00 × 106 4.91 × 10−13 5.48 × 10−19--

Tetraethylenepentamine 112-57-2 −3.16 -- 1.00 × 106 2.79 × 10−20 4.15 × 10−23--

Tetrakis(hydroxymethyl)phosphonium 

sulfate 55566-30-8 −5.03 -- 1.00 × 106 9.17 × 10−13

-- --

Tetramethylammonium chloride 75-57-0 −4.18 -- 1.00 × 106 4.17 × 10−12-- --
Appendix C – Chemical Mixing Supplemental Information 

C-64

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Thiamine hydrochloride 67-03-8 0.95 -- 3,018 8.24 × 10−17-- --

Thiocyanic acid, ammonium salt 1762-95-4 0.58 -- 4.36 × 104 1.46 × 10−4-- --

Thioglycolic acid 68-11-1 0.03 0.09 2.56 × 105 1.94 × 10−8-- --

Thiourea 62-56-6 −1.31 −1.08 5.54 × 105 1.58 × 10−7-- 1.98 × 10−9

Toluene 108-88-3 2.54 2.73 573.1 5.95 × 10−3 5.73 × 10−3 6.64 × 10−3

Tributyl phosphate 126-73-8 3.82 4 7.355 3.19 × 10−6-- 1.41 × 10−6

Tributyltetradecylphosphonium chloride 81741-28-8 11.22 -- 7.90 × 10−7 2.61 × 10−1-- --

Tridecane 629-50-5 6.73 -- 0.02746 1.24 × 101 1.90 × 101 2.88

Triethanolamine 102-71-6 −2.48 −1 1.00 × 106 4.18 × 10−12 3.38 × 10−19 7.05 × 10−13

Triethanolamine hydrochloride 637-39-8 −2.48 −1 1.00 × 106 4.18 × 10−12 3.38 × 10−19 7.05 × 10−13

Triethanolamine hydroxyacetate 68299-02-5 −2.97 -- 1.00 × 106 6.28 × 10−11-- --

Triethyl citrate 77-93-0 0.33 -- 2.82 × 104 6.39 × 10−10-- 3.84 × 10−9

Triethyl phosphate 78-40-0 0.87 0.8 1.12 × 104 5.83 × 10−7-- 3.60 × 10−8

Triethylene glycol 112-27-6 −1.75 −1.75 1.00 × 106 3.16 × 10−11 2.56 × 10−16--

Triethylenetetramine 112-24-3 −2.65 -- 1.00 × 106 9.30 × 10−17 6.74 × 10−19--

Triisopropanolamine 122-20-3 −1.22 -- 1.00 × 106 9.77 × 10−12 4.35 × 10−18--

Trimethanolamine 14002-32-5 −3.95 -- 1.00 × 106 1.42 × 10−8-- --

Trimethylamine 75-50-3 0.04 0.16 1.00 × 106 3.65 × 10−5 1.28 × 10−4 1.04 × 10−4

Tripotassium citrate monohydrate 6100-05-6 −1.67 −1.64 1.00 × 106 8.33 × 10−18-- 4.33 × 10−14
Appendix C – Chemical Mixing Supplemental Information 

C-65

Log Kow Water solubility

estimate from

log Kow

(mg/L at 25°C)

Henry's law constant

(atm-m3/mol at 25°C)

Chemical name CASRN Estimated Measured Bond method

Group 

method 25 Measured

Tripropylene glycol monomethyl ether 25498-49-1 −0.2 -- 1.96 × 105 2.36 × 10−11 4.55 × 10−13--

Trisodium citrate 68-04-2 −1.67 −1.64 1.00 × 106 8.33 × 10−18-- 4.33 × 10−14

Trisodium citrate dihydrate 6132-04-3 −1.67 −1.64 1.00 × 106 8.33 × 10−18-- 4.33 × 10−14

Trisodium ethylenediaminetetraacetate 150-38-9 −3.86 -- 2.28 × 105 1.17 × 10−23-- 5.77 × 10−16

Trisodium ethylenediaminetriacetate 19019-43-3 −4.32 -- 1.00 × 106 3.58 × 10−20-- --

Tromethamine 77-86-1 −1.56 -- 1.00 × 106 8.67 × 10−13-- --

Undecane 1120-21-4 5.74 -- 0.2571 7.04 9.52 1.93

Urea 57-13-6 −1.56 −2.11 4.26 × 105 3.65 × 10−10-- 1.74 × 10−12

Xylenes 1330-20-7 3.09 3.2 207.2 6.56 × 10−3 6.14 × 10−3 7.18 × 10−3
Appendix C – Chemical Mixing Supplemental Information 

C-66

C.6. Details on the EPI (Estimation Programs Interface) SuiteTM

The EPI (Estimation Programs Interface) SuiteTM (U.S. EPA, 2012b) is an open-source, Windows®-

based suite of physicochemical property and environmental fate estimation programs developed by 

the EPA’s Office of Pollution Prevention and Toxics and Syracuse Research Corporation. More 

information on EPI SuiteTM is available at http://www.epa.gov/oppt/exposure/pubs/episuite.htm. 

Although only physicochemical properties from EPI SuiteTM are provided here, other sources of 

information were also consulted. QikProp (Schrodinger, 2012) and LeadScope (Leadscope Inc., 

2012) are commercial products designed primarily as drug development and screening tools. 

Properties generated by QikProp and LeadScope are generally more relevant to drug development 

than to environmental assessment. 

QikProp is specifically focused on drug discovery and provides predictions for physically significant 

descriptors and pharmaceutically (and toxicologically) relevant properties useful in predicting 

ADME (adsorption, distribution, metabolism, and excretion) characteristics of drug candidates. 

QikProp's use of whole-molecule descriptors that have a straightforward physical interpretation (as 

opposed to fragment-based descriptors). 

LeadScope is a program designed for interpreting chemical and biological screening data that can 

assist pharmaceutical scientists in finding promising drug candidates. The software organizes the 

chemical data by structural features familiar to medicinal chemists. Graphs are used to summarize 

the data, and structural classes are highlighted that are statistically correlated with biological 

activity. It incorporates chemically-based data mining, visualization, and advanced informatics 

techniques (e.g., prediction tools, scaffold generators). 

Physicochemical properties of chemicals were generated from the two-dimensional (2-D) chemical 

structures from the EPA National Center for Computational Toxicology’s Distributed StructureSearchable Toxicity (NCCT DSSTox) Database Network in structure-data file (SDF) format. For EPI 

SuiteTM properties, both the desalted and non-desalted 2-D files were run using the program’s batch 

mode (i.e., processing many molecules at once) to calculate environmentally-relevant, chemical 

property descriptors. The chemical descriptors in QikProp require 3-D chemical structures. For 

these calculations, the 2-D desalted chemical structures were converted to 3-D using the Rebuild3D 

function in the Molecular Operating Environment software (CCG, 2011). All computed 

physicochemical properties are added into the structure-data file prior to assigning toxicological 

properties. 

Both LeadScope and Qikprop software require input of desalted structures. Therefore, the 

structures were desalted, a process where salts and complexes are simplified to the neutral, 

uncomplexed form of the chemical, using the “Desalt Batch” option in the ACD Labs ChemFolder. All 

LeadScope general chemical descriptors (Parent Molecular Weight, AlogP, Hydrogen Bond 

Acceptors, Hydrogen Bond Donors, Lipinski Score, Molecular Weight, Parent Atom Count, Polar 

Surface Area, and Rotatable Bonds) were calculated by default. 
Appendix C – Chemical Mixing Supplemental Information 

C-67

C.7. Top 20 lists for most mobile and least mobile chemicals 

Table C-10 and Table C-11 present the 20 highest and lowest log Kow (approximate surrogate for 

most mobile and least mobile) chemicals, known to be used in hydraulic fracturing fluids, 

respectively, as ranked by log Kow. These were taken from the list of 917 chemicals with estimated 

values for physicochemical properties. These tables also include values for aqueous solubility and 

Henry’s law constant, as well as frequency of use, based on chemical information reported in 

disclosures in the EPA FracFocus 1.0 project database (U.S. EPA, 2015a, c). 

Table C-10 shows the chemicals that have the lowest log Kow and are, thus, the most mobile. These 

chemicals are fully miscible (i.e., they will mix completely with water), which means they may move 

through the environment at high concentrations, leading to greater severity of impact. These 

chemicals generally have low volatility, based on their negative log Henry’s law constants (i.e., will 

remain in water and will not be lost to the air). These chemicals will dissolve in water and move 

rapidly through the environment (e.g., via infiltration into the subsurface or via overland flow to 

surface waters). Chemicals exhibiting this combination of properties have greater potential to cause 

immediate impacts to drinking water resources. Most of the chemicals in the table were 

infrequently reported (≤2% of wells) in the EPA FracFocus 1.0 project database (U.S. EPA, 2015a). 

However, choline chloride (14% of wells), used for clay control, and 

tetrakis(hydroxymethyl)phosphonium sulfate (11% of wells), a biocide, were more commonly 

reported. 

Table C-11 shows the chemicals that have the highest log Kow and are, thus, the least mobile. The 

estimated aqueous solubilities for some of these chemicals are extremely low, with highest 

solubilities of <10 μg/L. Therefore, the concentration of these chemicals dissolved in water will be 

low. The estimated Henry’s law constants are more variable for these low-mobility chemicals. 

Chemicals with high log Kow values (>0) and high Henry’s law constants will sorb strongly to organic 

phases and solids and may volatilize. However, their strong preference for the organic or solid 

phase may slow or reduce volatilization. The chemicals with low Henry’s law constants will readily 

sorb to organic phases and solids. Less mobile chemicals will move slowly through the soil and have 

potentially delayed and longer-term impacts to drinking water resources. Seven of the chemicals in 

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 alpha-olefins with carbon 

numbers greater than 10 used as a corrosion inhibitor, were more commonly reported. The least 

mobile organic chemical is sorbitan, tri-(9Z)-9-octadecenoate, a mineral oil co-emulsifier (0.05% of 

wells), with an estimated log Kow of 22.56.1

 

1 Sorbitan, tri-(9Z)-9-octadecenoate, CASRN 26266-58-0, is soluble in hydrocarbons and insoluble in water, listed as an 

effective coupling agent and co-emulsifier for mineral oil (Santa Cruz Biotechnology, 2015; ChemicalBook, 2010). 
Appendix C – Chemical Mixing Supplemental Information 

C-68

Table C-10. Ranking of the 20 most mobile organic chemicals, as determined by the largest log Kow, with CASRN, percent of wells 

where the chemical is reported from January 1, 2011 to February 28, 2013 (U.S. EPA, 2015c), and physicochemical properties (log 

Kow, solubility, and Henry’s law constant) as estimated by EPI SuiteTM. 

For organic salts, parameters are estimated using the desalted form.

Rank Chemical name CASRN

Percent of 

wells

(U.S. EPA, 

2015c)

a

Estimated 

log Kow

(unitless)b

Estimated 

water 

solubility 

(mg/L @ 

25oC)c

Estimated Henry's 

law constant 

(atm m3/mole @ 

25oC)d

1

1,2-Ethanediaminium, N,N'-bis[2-[bis(2-

hydroxyethyl)methylammonio]ethyl]-N,N'-bis(2-

hydroxyethyl)-N,N'-dimethyl-, tetrachloride

138879-94-4 2% -23.19 1.00 × 106 2.33 × 10-35

2

Phosphonic acid, [[(phosphonomethyl)imino]bis [2,1-

ethanediylnitrilobis(methylene)]]tetrakis15827-60-8 0.2% -9.72 1.00 × 106 NA

3

Phosphonic acid, [[(phosphonomethyl)imino]bis [2,1-

ethanediylnitrilobis(methylene)]]tetrakis-, sodium salt 22042-96-2 0.07% -9.72 1.00 × 106 NA

4

Phosphonic acid, [[(phosphonomethyl)imino]bis [2,1-

ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt 

(1:x)

70714-66-8 NA -9.72 1.00 × 106 NA

5

Phosphonic acid, (((2-[(2-hydroxyethyl) (phosphonomethyl) 

amino)ethyl)imino]bis(methylene))bis-, compd. with 2-

aminoethanol

129828-36-0 NA -6.73 1.00 × 106 5.29 × 10-42

6

2-Hydroxy-N,N-bis(2-hydroxyethyl)-Nmethylethanaminium chloride 7006-59-9 NA -6.7 1.00 × 106 4.78 × 10-19

7 N-(3-Chloroallyl)hexaminium chloride 4080-31-3 0.02% -5.92 1.00 × 106 1.76 × 10-8

8

3,5,7-Triazatricyclo(3.3.1.1 (superscript 3,7))decane, 1-(3-

chloro-2-propenyl)-, chloride, (Z)-

51229-78-8 NA -5.92 1.00 × 106 1.76 × 10-8

9 (2,3-dihydroxypropyl)trimethylammonium chloride 34004-36-9 NA -5.8 1.00 × 106 9.84 × 10-18
Appendix C – Chemical Mixing Supplemental Information 

C-69

Rank Chemical name CASRN

Percent of 

wells

(U.S. EPA, 

2015c)

a

Estimated 

log Kow

(unitless)b

Estimated 

water 

solubility 

(mg/L @ 

25oC)c

Estimated Henry's 

law constant 

(atm m3/mole @ 

25oC)d

10 Phosphonic acid, [[(phosphonomethyl)imino]bis [6,1-

hexanediylnitrilobis(methylene)]]tetrakis34690-00-1 0.006% -5.79 1.00 × 106 NA

11 [Nitrilotris(methylene)]tris-phosphonic acid pentasodium 

salt 2235-43-0 0.5% -5.45 1.00 × 106 1.65 × 10-34

12 Aminotrimethylene phosphonic acid 6419-19-8 2% -5.45 1.00 × 106 1.65 × 10-34

13 Choline chloride 67-48-1 14% -5.16 1.00 × 106 2.03 × 10-16

14 Choline bicarbonate 78-73-9 0.2% -5.16 1.00 × 106 2.03 × 10-16

15 alpha-Lactose monohydrate 5989-81-1 NA -5.12 1.00 × 106 4.47 × 10-22

16 Lactose 63-42-3 NA -5.12 1.00 × 106 4.47 × 10-22

17 Tetrakis(hydroxymethyl)phosphonium sulfate 55566-30-8 11% -5.03 1.00 × 106 9.17 × 10-13

18 Disodium ethylenediaminediacetate 38011-25-5 0.6% -4.79 1.00 × 106 1.10 × 10-16

19 Nitrilotriacetamide 4862-18-4 NA -4.75 1.00 × 106 1.61 × 10-18

20 1,3,5-Triazine-1,3,5(2H,4H,6H)-triethanol 4719-04-4 0.2% -4.67 1.00 × 106 1.08 × 10-11

a Some of the chemicals in these tables have NA (not available) listed as the number of wells, which means that these chemicals have been used in hydraulic fracturing, but they 

were not reported to disclosures in the EPA FracFocus 1.0 project database for the time period of the study (January 1, 2011, to February 28, 2013) (U.S. EPA, 2015c). 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 our quality assurance 

criteria (3,855) or other, query-specific criteria were excluded from our analysis. 

b Log Kow is estimated using the KOWWINTM model, which uses an atom/fragment contribution method.

c Water solubility is estimated using the WSKOWWINTM model, which estimates a chemical’s solubility from Kow and any applicable correction factors.

d Henry’s law constant is estimated using the HENRYWINTM model using the bond contribution method.
Appendix C – Chemical Mixing Supplemental Information 

C-70

Table C-11. Ranking of the 20 least mobile organic chemicals, as determined by the largest log Kow, with CASRN, percent of wells 

where the chemical is reported from January 1, 2011 to February 28, 2013 (U.S. EPA, 2015c), and physicochemical properties (log 

Kow, solubility, and Henry’s law constant) as estimated by EPI SuiteTM. 

For organic salts, parameters are estimated using the desalted form.

Rank Chemical name CASRN

Percent of 

wells

(U.S. EPA, 

2015c)

a

Estimated log 

Kow (unitless)b

Estimated water 

solubility

(mg/L @ 25oC)c

Estimated Henry's law 

constant 

(atm m3/mole @ 25oC)d

1 Sorbitan, tri-(9Z)-9 octadecenoate 26266-58-0 0.05% 22.56 1.12 × 10-19 4.02 × 10-11

2 Fatty acids, C18-unsatd., dimers 61788-89-4 NA 14.6 2.31 × 10-10 4.12 × 10-08

3 Sorbitan sesquioleate 8007-43-0 0.02% 14.32 2.31 × 10-11 7.55 × 10-12

4

Tri-n-butyltetradecyl-phosphonium 

chloride 81741-28-8 6% 11.22 7.90 × 10-7 2.61 × 10-1

5 Sodium bis(tridecyl) sulfobutanedioate 2673-22-5 NA 11.15 7.46 × 10-9 8.51 × 10-11

6 1-Eicosene 3452-07-1 NA 10.03 1.26 × 10-5 1.89 × 101

7 D&C Red 28 18472-87-2 NA 9.62 1.64 × 10-8 6.37 × 10-21

8 C.I. Solvent Red 26 4477-79-6 NA 9.27 5.68 × 10-5 5.48 × 10-13

9 1-Octadecene 112-88-9 NA 9.04 1.256 × 10-4 1.07 × 101

10 Alkenes, C>10 alpha- 64743-02-8 8% 8.55 3.941 × 10-4 8.09 × 100

11 Dioctyl phthalate 117-84-0 NA 8.54 4.236 × 10-4 1.18 × 10-5

12 Benzene, C10-16-alkyl derivs. 68648-87-3 0.5% 8.43 2.099 × 10-4 1.78 × 10-1

13 Di(2-ethylhexyl) phthalate 117-81-7 NA 8.39 1.132 × 10-3 1.18 × 10-5

14 1-Octadecanamine, N,N-dimethyl- 124-28-7 NA 8.39 8.882 × 10-3 4.51 × 10-3

15 N,N-dimethyloctadecylamine 

hydrochloride 1613-17-8 NA 8.39 8.882 × 10-3 4.51 × 10-3
Appendix C – Chemical Mixing Supplemental Information 

C-71

Rank Chemical name CASRN

Percent of 

wells

(U.S. EPA, 

2015c)

a

Estimated log 

Kow (unitless)b

Estimated water 

solubility

(mg/L @ 25oC)c

Estimated Henry's law 

constant 

(atm m3/mole @ 25oC)d

16 Butyryl trihexyl citrate 82469-79-2 0.03% 8.21 5.56 × 10-5 3.65 × 10-9

17 1-Hexadecene 629-73-2 NA 8.06 1.232 × 10-3 6.10 × 100

18 Benzo(g,h,i)perylene 191-24-2 NA 7.98 7.321 × 10-4 1.26 × 10-2

19 Dodecylbenzene 123-01-3 NA 7.94 1.015 × 10-3 1.34 × 10-1

20 Isopropanolamine dodecylbenzene 42504-46-1 0.02% 7.94 1.015 × 10-3 1.34 × 10-1

a Some of the chemicals in these tables have NA (not available) listed as the number of wells, which means that these chemicals have been used in hydraulic fracturing, but they 

were not reported in disclosures in the EPA FracFocus 1.0 project databases for the time period of the study (January 1, 2011, to February 28, 2013) (U.S. EPA, 2015c). 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 these quality 

assurance criteria (3,855) or other, query-specific criteria were excluded from our analysis. 

b Log Kow is estimated using the KOWWINTM model, which uses an atom/fragment contribution method.

c Water solubility is estimated using the WSKOWWINTM model, which estimates a chemical’s solubility from Kow and any applicable correction factors.

d Henry’s law constant is estimated using the HENRYWINTM model using the bond contribution method.
Appendix C – Chemical Mixing Supplemental Information 

C-72

Figure C-1. Histograms of physicochemical properties organic chemicals claimed as 

confidential by industry that were used in the hydraulic fracturing process. 

Measured values of log Kow (upper left). Estimated physicochemical properties for log Kow (upper right), log 

solubility (lower left), and log Henry’s law constant (lower right) for all chemicals. Physicochemical properties (log 

Kow, solubility, and Henry’s law constant) estimated by EPI SuiteTM. Source: U.S. EPA (2013a). 
Appendix D – Well Injection Supplemental Information 

D-1 

Appendix D. Well Injection Supplemental 

Information 
Appendix D – Well Injection Supplemental Information 

D-2 

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Appendix D – Well Injection Supplemental Information 

D-3 

Appendix D. Well Injection Supplemental Information 

This appendix presents the goals for the design and construction of oil and gas production wells, 

the well components used to achieve those goals, and methods for testing well integrity to help 

verify that the goals for well performance are achieved. This information provides additional 

background for the well component discussions presented in Chapter 6. Information on the 

pathways associated with the well that can cause fluid movement into drinking water resources is 

presented in Chapter 6. 

D.1. Design Goals for Well Construction 

Simply stated, production wells are designed to move oil and gas from the production zone (within 

the oil and gas reservoir) into the well and then through the well to the surface. There are typically 

a variety of goals for well design (Renpu, 2011), but the main purposes are facilitating the flow of 

oil and gas from the hydrocarbon reservoirs to the well (production management) while isolating 

that oil and gas and the hydrocarbon reservoirs from nearby groundwater resources (zonal 

isolation). 

To achieve these goals, operators design and construct wells to have and maintain mechanical 

integrity throughout the life of the well. A properly designed and constructed well has two types of 

mechanical integrity: internal and external. Internal mechanical integrity refers to the absence of 

significant leakage within the production tubing, casing, or packer. External mechanical integrity 

refers to the absence of significant leakage along the well outside of the casing. 

Achieving mechanical integrity involves designing the well components to resist the stresses they 

will encounter. Each well component must be designed to withstand all of the stresses to which the 

well will be subjected, including burst pressure, collapse, tensile, compression (or bending), and 

cyclic stresses (see Section 6.2.1 for additional information on these stresses). Well materials 

should also be compatible with the fluids (including liquids or gases) with which they come into 

contact to prevent leaks caused by corrosion. 

These goals are accomplished by the use of one or more layers of casing, cement, and mechanical 

devices (such as packers), which provide the main barrier preventing migration of fluids from the 

well into drinking water resources. It should be noted that design conditions will change depending 

on the specific geology of the site. Technology in the field of hydraulic fracturing is also rapidly 

evolving with new technologies and techniques being continually developed. Therefore while the 

following sections outline basic design goals and concepts, they cannot anticipate all possible 

design conditions. 

D.2. Well Components 

Casing and cement are used in the design and construction of wells to achieve the goals of 

mechanical integrity and zonal isolation. Several industry-developed specifications and best 

practices for well construction have been established to guide well operators in the construction 
Appendix D – Well Injection Supplemental Information 

D-4 

process; see Text Box D-1.

1 The sections below describe options available for casing, cement, and 

other well components. 

Text Box D-1. Selected Industry-Developed Specifications and Recommended Practices for 

Well Construction in North America. 

American Petroleum Institute (API) 

























API Guidance Document HF1―Hydraulic Fracturing Operations―Well Construction and Integrity 

Guidelines (API, 2009a) 

API RP 10B-2―Recommended Practice for Testing Well Cements (API, 2013) 

API RP 10D-2―Recommended Practice for Centralizer Placement and Stop Collar Testing (API, 2004) 

API RP 5C1―Recommended Practices for Care and Use of Casing and Tubing (API, 1999) 

API RP 65-2―Isolating Potential Flow Zones during Well Construction (API, 2010a) 

API Specification 10A―Specification on Cements and Materials for Well Cementing (API, 2010b) 

API Specification 11D1―Packers and Bridge Plugs (API, 2009b) 

API Specification 5CT―Specification for Casing and Tubing (API, 2011) 

API RP 100-1 – Hydraulic Fracturing Well Integrity and Fracture Containment 1st Edition (API, 2015) 

Canadian Association of Petroleum Producers (CAPP) and Enform 

Hydraulic Fracturing Operating Practices: Wellbore Construction and Quality Assurance (CAPP, 2013) 

Interim Industry Recommended Practice Volume #24―Fracture Stimulation: Inter-wellbore 

Communication (Enform, 2013) 

Marcellus Shale Coalition (MSC) 

Recommended Practices―Drilling and Completions (MSC, 2013) 

D.2.1. Casing 

Casing is steel pipe that is placed into the wellbore (the cylindrical hole drilled through the 

subsurface rock formation) 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. Up to four types of casing may be present in a well, including (from largest to smallestdiameter): conductor casing, surface casing, intermediate casing, and production casing. Each is 

described below. 

D.2.1.1. Types of Casing 

The conductor casing is the largest diameter string of casing. It is typically in the range of 30 in. 

(76 cm) to 42 in. (107 cm) in diameter (Hyne, 2012). Its main purpose is to prevent unconsolidated 

material, such as sand, gravel, and soil, from collapsing into the wellbore. Therefore, the casing is 

 

1 Information is not available to determine how often these practices are used or how well they prevent the development 

of pathways for fluid movement to drinking water resources. 
Appendix D – Well Injection Supplemental Information 

D-5 

typically installed from the surface to the top of the bedrock or other consolidated formations. The 

conductor casing may or may not be cemented in place. 

The next string of casing is the surface casing. A typical surface casing diameter is 13.75 in. (34.93 

cm), but diameter can vary (Hyne, 2012). The surface casing’s main purposes are to isolate any 

groundwater resources that are to be protected by preventing fluid migration along the wellbore 

once the casing is cemented and to provide a sturdy structure to which blow-out prevention 

equipment can be attached. For these reasons, the surface casing most commonly extends from the 

surface to some distance beneath the lowermost geologic formation containing groundwater 

resources to be protected. The specific depth to which the surface casing is set is often governed by 

the depth of the groundwater resource as defined and identified for protection in state regulations. 

Intermediate casing is typically used in wells to control pressure in an intermediate-depth 

formation. It may be used to reduce or prevent exposure of weak formations to pressure from the 

weight of the drilling fluid or cement or to allow better control of over-pressured formations. The 

intermediate casing extends from the surface through the formation of concern. There may be more 

than one string of concentric intermediate casing present or none at all, depending on the 

subsurface geology. Intermediate casing may be cemented, especially through over-pressured 

zones; however, it is not always cemented to the surface. Intermediate casing, when present, is 

often 8.625 in. (21.908 cm) in diameter but can vary (Hyne, 2012). 

Production casing extends from the surface into the production zone. The main purposes of the 

production casing are to isolate the hydrocarbon product from fluids in surrounding formations 

and to transport the product to the surface. It can also be used to inject hydraulic fracturing fluids, 

receive produced water during hydraulic fracturing operations (e.g., if tubing or a temporary 

fracturing string is not present), and prevent other fluids from mixing with and diluting the 

produced hydrocarbons. The production casing is generally cemented to some point above the 

production zone. Production casing is often 5.5 in. (14.0 cm) in diameter but can vary (Hyne, 2012). 

Liners are another type of metal tubular (casing-like) well component that can be used to fulfill the 

same purposes as intermediate and production casing in the production zone. Like casing, they are 

steel pipe, but differ in that they do not extend from the production zone to the surface. Rather, they 

are connected to the next largest string of casing by a hanger that is attached to the casing. A frac 

sleeve is a specialized type of liner that is used during fracturing. It has plugs that can be opened 

and closed by dropping balls from the surface (see the discussion of well completions below for 

additional information on the use of frac sleeves). 

Production tubing is the smallest, innermost steel pipe in the well and is distinguished from casing 

by not being cemented in place. It is used to transport the hydrocarbons to the surface. Fracturing 

may be done through the tubing if present, or through the production casing. Because casing cannot 

be replaced, tubing is often used, especially if the hydrocarbons contain corrosive substances such 

as hydrogen sulfide or carbon dioxide. Tubing may not be used in high-volume production wells. 

Typical tubing diameter is between 1.25 in. (3.18 cm) and 4.5 in. (11.4 cm) (Hyne, 2012). 
Appendix D – Well Injection Supplemental Information 

D-6 

D.2.1.2. Casing Design Considerations 

The stresses that the casing will experience are key factors to consider in designing the casing. If the 

casing is not designed with sufficient resistance to the stresses it will face, it can fail. Stresses that 

may cause failure of casing include: pressure exerted during hydraulic fracturing operations, cyclic 

pressure from multi-stage fracturing, pressure from the formation, and stresses encountered 

during installation of the casing especially around bends (King and Valencia, 2016; Cheremisinoff 

and Davletshin, 2015). Maximum values for each of these stresses can be calculated, and the casing 

can be designed to resist them. Generally, the inner layers such as tubing are designed to collapse 

before the outer casing will burst (King and Valencia, 2016). Casing strength can be improved by 

choosing stronger materials or by increasing casing thickness. 

Another factor to consider in casing design is corrosion. The casing may be exposed to corrosive 

substances such as carbon dioxide, hydrogen sulfide, natural brines, and acids used during 

fracturing. Corrosion resistance may be achieved by using corrosion resistant alloys or by lining the 

casing (King and Valencia, 2016; Syed and Cutler, 2010). Abrasion from proppant during fracturing 

can also lead to casing erosion problems (King and Valencia, 2016). 

Joint design and installation are equally important in casing design as they are a frequent location 

of casing leaks (King and Valencia, 2016). Joint failure can occur due to poor design, installation 

errors, and stress corrosion. 

D.2.2. Cement 

Cement is the main barrier preventing fluid movement along the wellbore outside the casing. It also 

lends mechanical strength to the well and protects the casing from corrosion by naturally occurring 

formation fluids. Cement is placed in the annulus, which is the space between two adjacent casings 

or the space between the outermost casing and the rock formation through which the wellbore was 

drilled. The sections below describe considerations for selecting cement and additives, as well as 

cementing procedures and techniques. 

D.2.2.1. Considerations for Cementing 

The length and location of the casing section to be cemented and the composition of the cement can 

vary based on numerous factors, including the presence and locations of weak formations, over- or 

under-pressured formations, or formations containing fluids; formation permeability; and 

temperature. State requirements for oil and gas production well construction and the relative costs 

of well construction options are also factors. 

Improper cementing can lead to the formation of channels (small connected voids) in the cement, 

which can—if they extend across multiple formations or connect to other existing channels or 

fractures—present pathways for fluid migration. This section describes some of the considerations 

and concerns for proper cement placement and techniques and materials that are available to 

address these concerns. Careful selection of cements (and additives) and design of the cementing 

job can avoid integrity problems related to cement. 
Appendix D – Well Injection Supplemental Information 

D-7 

To select the appropriate cement type, properties, and additives, operators consider the required 

strength needed to withstand downhole conditions and compatibility with subsurface chemistry, as 

described below: 









The cement design needs to achieve the strength required under the measured or 

anticipated downhole conditions. Factors that are taken into account to achieve proper 

strength can include density, thickening time, the presence of free water, compressive 

strength, and formation permeability (Renpu, 2011). Commonly, cement properties are 

varied during the process, with a “weaker” (i.e., less dense) lead cement, followed by a 

“stronger” (denser) tail cement. The lead cement is designed with a lower density to 

reduce pressure on the formation and better displace drilling fluid without a large concern 

for strength. The stronger tail cement provides greater strength for the deeper portions of 

the well the operator considers as requiring greater strength. 

The compatibility of the cement with the chemistry of formation fluids, hydrocarbons, 

and hydraulic fracturing fluids is important for maintaining well integrity through the life 

of the well. Most oil and gas wells are constructed using some form of Portland cement. 

Portland cement is a specific type of cement consisting primarily of calcium silicates with 

additional iron and aluminum. Industry specifications for recommended cements are 

determined by the downhole pressure, temperature, and chemical compatibility required. 

There are a number of considerations in the design and execution of a cement job. Proper 

centralization of the casing within the wellbore is one of the more important considerations. Others 

include the potential for lost cement, gas invasion, cement shrinkage, incomplete removal of drilling 

mud, settling of solids in the wellbore, and water loss into the formation while curing. These 

concerns, and techniques available to address them, include the following: 

Improper centralization of the casing within the wellbore can lead to preferential flow 

of cement on the side of the casing with the larger space and little to no cement on the side 

closer to the formation. If the casing is not centered in the wellbore, cement will flow 

unevenly during the cement job, leading to the formation of cement channels. Kirksey 

(2013) notes that, if the casing is off-center by just 25%, the cement job is almost always 

inadequate. Centralizers are used to keep the casing in the center of the hole and allow an 

even cement job. To ensure proper centralization, centralizers are placed at regular 

intervals along the casing (API, 2010a). Centralizer use is especially key in horizontal wells, 

as the casing will tend to settle (due to gravity) to the bottom of the wellbore if the casing 

is not centered (Sabins, 1990), leading to inadequate cement on the lower side. Although 

some operators have avoided using centralizers on horizontal wells because of problems 

with stuck pipe, improved centralizer designs have allowed increased use of centralizers in 

horizontal wells (Landry et al., 2015). 

Lost cement (sometimes referred to as lost returns) refers to cement that moves out of 

the wellbore and into the formation instead of filling up the annulus between the casing 

and the formation. Lost cement can occur in weak formations that fail (fracture) under 

pressure of the cement or in particularly porous, permeable, or naturally fractured 

formations. Lost cement can result in lack of adequate cement across a water- or brine-
Appendix D – Well Injection Supplemental Information 

D-8 

bearing zone. To avoid inadequate placement of cement due to lost cement, records of 

nearby wells can be examined to determine zones where lost cement returns occur (API, 

2009a). If records from nearby wells are not available, cores and logs may be used to 

identify any high-permeability or mechanically weak formations that might lead to lost 

cement. Steps can then be taken to eliminate or reduce loss of cement to the formation. 

Staged cementing (see below) can reduce the hydrostatic pressure on the formation and 

may avoid fracturing weak formations (Lyons and Pligsa, 2004). Additives such as 

cellulose or polymers are also available that will lessen the flow of cement into highly 

porous formations (API, 2010a; Ali et al., 2009). 





Gas invasion and cement shrinkage during cement setting can also cause channels and 

poor bonding. As cement sets, it begins to lose the ability to transmit pressure to the 

surrounding formation. During the cementing process, the hydrostatic pressure from the 

cement column keeps formation gas from entering the cement. As the cement sets 

(hardens), the hydrostatic pressure decreases; if it becomes less than the formation 

pressure, gas can enter the cement, leading to channels. Cement shrinkage occurs as the 

cement sets under a high pressure; shrinking can be made worse by left over drilling mud 

or too large of a space between the casing and formation (Oyarhossein and Dusseault, 

2015). Such shrinkage can lead to channels or microannuli along the cement column. 

These problems can be avoided by using cement additives that increase setting time or 

expand to offset shrinkage (McDaniel et al., 2014; Wojtanowicz, 2008; Dusseault et al., 

2000). Foamed cement can help alleviate problems with shrinkage, although care needs to 

be taken in cement design to ensure the proper balance of pressure between the cement 

column and formation (API, 2010a). Cement additives such as latex are also available that 

will expand upon contact with certain fluids such as hydrocarbons. These cements, termed 

self-healing cements, are relatively new but have shown early promise in some fields (Ali 

et al., 2009). Self-healing cements have been found to increase the compressive strength of 

the cement by 10%, tensile strength by 48%, Poisson’s ratio by 66%, and Young’s modulus 

by 56% (Shadravan and Amani, 2015). Rotating the casing during cementing will also 

delay cement setting by agitating the cement. Another technique called pulsation, where 

pressure pulses are applied to the cement while it is setting, also can delay cement setting 

and loss of hydrostatic pressure until the cement is strong enough to resist gas penetration 

(Stein et al., 2003). 

Another important issue is removal of drilling mud. Inadequate removal of drilling mud 

can prevent cement from filling the entire space between the casing and the formation, 

resulting in channels in the cement after the mud is eroded away by formation fluids 

(Jackson and Dussealt, 2014). If drilling mud is not completely removed, it can gather on 

one side of the wellbore and prevent that portion of the wellbore from being adequately 

cemented. The drilling mud can then be eroded away after the cement sets, leaving a 

channel. Drilling mud can be removed by circulating a denser fluid (spacer fluid) to flush 

the drilling mud out (Kirksey, 2013; Brufatto et al., 2003). Mechanical devices called 

scratchers can also be attached to the casing, and the casing rotated or reciprocated to 

scrape drilling mud from the wellbore (Hyne, 2012; Crook, 2008). The spacer fluid, which 

is circulated prior to the cement to wash the drilling fluid out of the wellbore, must be 
Appendix D – Well Injection Supplemental Information 

D-9 

designed with the appropriate properties and pumped in such a way that it displaces the 

drilling fluid without mixing with the cement (Kirksey, 2013; API, 2010a; Brufatto et al., 

2003). 







Also of concern in horizontal wells is the possibility of solids settling at the bottom of the 

wellbore and free water collecting at the top of the wellbore. This can lead to channels and 

poor cement bonding. The cement slurry must be properly designed for horizontal wells to 

minimize free water and solids settling. 

If there is free water in the cement, pressure can cause water loss into the formation,

leaving behind poor cement or channels (Jiang et al., 2012). In horizontal wells, free water 

can also accumulate at the top of the wellbore, forming a channel (Sabins, 1990). 

Minimizing free water in the cement design and using fluid loss control additives can help 

control the loss of water (Ross and King, 2007). 

Fracturing in stages can lead to cyclic stresses being exerted on the cement (King and 

Valencia, 2016). During fracturing, the cooler temperature fluids are injected into the well 

at high pressure, resulting in temperature and pressure changes downhole. When 

injection stops, the temperature returns to the higher reservoir temperatures and 

pressure returns to normal. One study has found such cycling can lead to temperature 

changes of as much as 176°F (80°C) (Tian et al., 2015). Exposing cement to several cycles 

of temperature and pressure variation can lead to a number of problems. Stress may cause 

cracks in the cement, especially at locations of existing defects in the cement (De Andrade 

et al., 2015; Syed and Cutler, 2010). Differences between the rates at which steel and 

cement expand can lead to debonding between the cement and casing. Contraction of 

fluids at lower temperatures can also create vacuums in some situations, which can stress 

the casing and cement (Tian et al., 2015). Using cement with lower anelastic strength and 

higher tensile and impact strength may help alleviate problems caused by cyclic stresses 

(McDaniel et al., 2014). Self-sealing cements, as described above, may also seal cracks that 

are initiated during cycling. Some studies have found the ability of such cements to seal 

flow through cracks in as little as 30 minutes (Cavanagh et al., 2007). Foamed cements 

have also been found to hold up better to pressure cycles than standard cement slurries 

(Spaulding, 2015). 

D.2.2.2. Cement Placement Techniques 

The primary cement job is most commonly conducted by pumping the cement down the inside of 

the casing, then out the bottom of the casing where it is then forced up the space between the 

outside of the casing and the formation. (The cement can also be placed in the space between two 

casings.) If continuous cement (i.e., a sheath of cement placed along the entire wellbore) is 

desired, cement is circulated through the annulus until cement that is pumped down the central 

casing flows out of the annulus at the surface. A spacer fluid is often pumped ahead of cement to 

remove any excess drilling fluid left in the wellbore; even if the operator does not plan to circulate 

cement to the surface, the spacer fluid will still return to the surface, as this is necessary to remove 

the drilling mud from the annulus. If neither the spacer fluid nor the cement returns to the surface, 

this indicates that fluids are being lost into the formation. 
Appendix D – Well Injection Supplemental Information 

D-10

Staged cementing is a technique that reduces pressure on the formation by decreasing the height 

(and therefore the weight) of the cement column. This may be necessary if the estimated weight 

and pressure associated with standard cement emplacement could damage zones where the 

formation intersected is weak. The reduced hydrostatic pressure at the bottom of the cement 

column can also reduce the loss of water to permeable formations, improving the quality of the 

cement job. In multiple-stage cementing, cement is circulated to just below a cement collar placed 

between two sections of casing. A cement collar will have been placed between two sections of 

casing, just above, with ports that can be opened by dropping a weighted tool. Two plugs—which 

are often referred to as bombs or darts because of their shape—are then dropped. The first plug is 

dropped once the desired cement for the first stage has been pushed out of the casing by a spacer 

fluid. It closes the section of the well below the cement collar and stops cement from flowing into 

the lower portion of the well. The second plug (or opening bomb) opens the cement ports in the 

collar, allowing cement to flow into the annulus between the casing and formation. Cement is then 

circulated down the wellbore, out the cement ports, into the annulus, and up to the surface. Once 

cementing is complete, a third plug is dropped to close the cement ports, preventing the newly 

pumped cement from flowing back into the well (Lyons and Pligsa, 2004); see Figure D-1. 

Another less commonly used primary cementing technique is reverse circulation cementing. This 

technique has been developed to decrease the force exerted on weak formations. In reverse 

circulation cementing, the cement is pumped down the annulus directly between the outside of the 

outermost casing and the formation. This essentially allows use of lower density cement and lower 

pumping pressures. With reverse circulation cementing, greater care must be taken in calculating 

the required cement, ensuring proper cement circulation, and locating the beginning and end of the 

cemented portion. 

Another method used to cement specific portions of the well without circulating cement along the 

entire wellbore length is to use a cement basket. A cement basket is a device that attaches to the 

well casing. It is made of flexible material such as canvas or rubber that can conform to the shape of 

the wellbore. The cement basket acts as a one-way barrier to cement flow. Cement can be circulated 

up the wellbore past the cement basket, but when circulation stops the basket prevents the cement 

from falling back down the wellbore. Cement baskets can be used to isolate weak formations or 

formations with voids. They can also be placed above large voids such as mines or caverns with 

staged cementing used to cement the casing above the void. 

If any deficiencies are identified, remedial cementing may be performed. The techniques available 

to address deficiencies in the primary cement job including cement squeezes or top-job cementing. 

A cement squeeze injects cement under high pressure to fill in voids or spaces in the primary 

cement job caused by high pressure, failed formations, or improper removal of drilling mud. 

Although cement squeezes can be used to fix deficiencies in the primary cement job, they require 

the well to be perforated, which can weaken the well and make it susceptible to degradation by 

pressure and temperature cycling as would occur during fracturing (Crescent, 2011). Another 

method of secondary cementing is the top job. In a top job, cement is pumped down the annulus 

directly to fill the remaining uncemented space when cement fails to circulate to the surface. 
Appendix D – Well Injection Supplemental Information 

D-11

Figure D-1. A typical staged cementing process. 
Appendix D – Well Injection Supplemental Information 

D-12

D.3. Well Completions 

Completion refers to how the well is prepared for production and how flow is established between 

the formation and the surface. Figure D-2 presents examples of well completion types, including 

cased, formation packer, and open hole completion. 

Figure D-2. Examples of well completion types. 

Configurations shown include cased, formation packer, and open hole completion. From U.S. EPA (2015k). 

A cased completion, where the casing extends to the end of the wellbore and is cemented in place, 

is the most common configuration of the well in the production zone (U.S. EPA, 2015k). 

Perforations are made through the casing and cement and into the formation using tools called 

“perf guns” that deliver small explosive charges or other devices, such as sand jets. Hydraulic 

fracturing then is conducted through the perforations. This is a common technique in wells that 

produce from several different depths and in low-permeability formations that are fractured 

(Renpu, 2011). While perforations do control the initiation point of the fracture, this can be a 

disadvantage if the perforations are not properly aligned with the local stress field. If the 

perforations are not aligned, the fractures will twist to align with the stress field, leading to 

tortuosity in the fractures and making fluid movement through them more difficult (Cramer, 2008). 

Fracturing stages can be isolated from each other using various mechanisms such as plugs or baffle 

rings, which close off a section of the well when a ball of the correct size is dropped down the well. 

A packer is a mechanical device used to selectively seal off certain sections of the wellbore. Packers 

can be used to seal the space between the tubing and casing, between two casings, or between the 

production casing and formation. The packer has one or more rubber elements that can be 

manipulated downhole to increase in diameter and make contact with the inner wall of the next-
Appendix D – Well Injection Supplemental Information 

D-13

largest casing or the formation, effectively sealing the annulus created between the outside of the 

tubing and the inside of the casing. Packers vary in how they are constructed and how they are set, 

based on the downhole conditions in which they are used. There are two types of packers: internal 

packers and formation packers. Internal packers are used to seal the space between the casing and 

tubing or between two different casings. They prevent fluid movement into the annulus by isolating 

the outer casing layers from produced or formation fluids. Formation packers seal the space 

between the casing and the formation and are often used to isolate fracture stages; they can be used 

to separate an open hole completion into separate fracture stages. Packers can seal an annulus by 

several different mechanisms. Mechanical packers expand mechanically against the formation and 

can exert a significant force on the formation (McDaniel and Rispler, 2009). They are typically less 

than 5 ft (1.5 m) long and can be used in wells with tighter doglegs (Senters et al., 2016). Swellable 

packers have elastomer sealing elements that swell when they come into contact with a triggering 

fluid such as water or hydrocarbons. They exert less force on the formation and can seal larger 

spaces but take some time to fully swell (McDaniel and Rispler, 2009). Swellable packers are longer 

and can be affected by thermal changes during fracturing. Cyclic stresses during fracturing can also 

cause packer failure (Senters et al., 2016). Internal mechanical integrity tests such as pressure tests 

can verify that the packer is functioning as designed and has not corroded or deteriorated. 

In an open hole completion, the production casing extends just into the production zone and the 

entire length of the wellbore through the production zone is left uncased. This is only an option in 

formations where the wellbore is stable enough to not collapse into the wellbore. In formations that 

are unstable, a slotted liner may be used in open hole completions to control sand production 

(Renpu, 2011). Perforations are not needed in an open hole completion, since the production zone 

is not cased. An open hole completion can be fractured in a single stage or in multiple stages. 

If formations are to be fractured in stages, additional completion methods are needed to separate 

the stages from each other and control the location of the fractures. One possibility is use of a liner 

with formation packers to isolate each stage. The liner is equipped with sliding sleeves that can be 

opened by dropping balls down the casing to open each stage. Fracturing typically occurs from the 

end of the well and continues toward the beginning of the production zone. 

D.4. Mechanical Integrity Testing 

While proper design and construction of the well’s casing and cement are important, it is also 

important to verify the well was constructed and is performing as designed. Mechanical integrity 

tests (MITs) can verify that the well was constructed as planned and can detect damage to the 

production well that occurs during operations, including hydraulic fracturing activities. Verifying 

that a well has mechanical integrity can prevent potential impacts to drinking water resources or 

loss of hydrocarbon products by providing early warning of a problem with the well or cement and 

allowing repairs. 

It is important to note that if a well fails an MIT, this does not mean the well has failed or that an 

impact on drinking water resources has occurred. An MIT failure is a warning that one or more 

components of the well are not performing as designed and is an indication that corrective actions 
Appendix D – Well Injection Supplemental Information 

D-14

are necessary. If well remediation is not performed, a loss of well integrity could occur, which could 

result in fluid movement from the well. 

D.4.1. Internal Mechanical Integrity 

Internal mechanical integrity is an absence of significant leakage in the tubing, casing, or packers 

within the well system. Loss of internal mechanical integrity is usually due to corrosion or 

mechanical failure of the well’s tubular and mechanical components. 

Internal mechanical integrity can be tested by the use of pressure testing, annulus pressure 

monitoring, ultrasonic monitoring, and casing inspection logs or caliper logs: 





Pressure testing involves raising the pressure in the wellbore to a set level and shutting 

in the well. If the well has internal mechanical integrity, the pressure should remain 

constant with only small changes due to temperature fluctuation. Typically, the well is 

shut in (i.e., production is stopped and the wellhead valves closed) for a time prescribed by 

regulation, and if the pressure remains within a given percent of the original reading, the 

well is considered to have passed the test. Usually, the well is pressure tested to the 

maximum expected pressure; for a well to be used for hydraulic fracturing, this would be 

the pressure applied during hydraulic fracturing. Performing a pressure test on each 

casing before the next casing is drilled ensures the casing can withstand subsequent 

stresses and allows repairs if necessary before problems can develop (Cheremisinoff and 

Davletshin, 2015). Pressure tests, however, can cause debonding of the cement from the 

casing, so test length is often limited to reduce this effect (API, 2010a). 

If the annulus between the tubing and casing is sealed by a packer, annulus pressure 

monitoring can give an indication of the integrity of the tubing and casing. If the tubing, 

casing, and packer all have mechanical integrity, the pressure in the annulus should not 

change except for small changes in response to temperature fluctuations. The annulus can 

be filled with a non-corrosive liquid and the level of the liquid can be used as another 

indication of the integrity of the casing, tubing, and packer. The advantage of monitoring 

the tubing/production casing annulus is that it can give a continuous, real-time indication 

of the internal integrity of the well. This is the only MIT test likely to detect problems 

during normal well operations. Even if the annulus is not filled with a fluid, monitoring its 

pressure can indicate leaks. If pressure builds up in the annulus and then recovers quickly 

after having bled off, that condition is referred to as sustained casing pressure or surface 

casing vent flow and is a sign of a leak in the tubing or casing (Watson and Bachu, 2009). 

Monitoring of annuli between other sets of casings can also provide information on the 

integrity of those casings. It can also provide information on external mechanical integrity 

for annuli open to the formation (see Section D.4.2 for additional information on external 

MITs). Jackson et al. (2013b) also note that monitoring annular pressure allows the 

operator to vent gas before it accumulates enough pressure to cause migration into 

drinking water resources. Measuring annulus flow rate also allows detection of gas 

flowing into the annulus (Arthur, 2012). 
Appendix D – Well Injection Supplemental Information 

D-15







A newer tool uses ultrasonic monitors to detect leaks in casing and other equipment. It 

measures the attenuation of an ultrasonic signal as it is transmitted through the wellbore. 

The tool measures transmitted ultrasonic signals as it is lowered down the wellbore. The 

tool can pick up ultrasonic signals created by a leak, similar to noise logs. The tool only has 

a range of a few feet but is claimed to detect leaks as small as half a cup per minute (Julian 

et al., 2007). 

Caliper logs have mechanical fingers that extend from a central tool and measure the 

distance from the center of the wellbore to the side of the casing. Running a caliper log can 

identify areas where corrosion has altered the diameter of the casing or where holes have 

formed in the casing. Caliper logs may also detect debris or obstructions in the well. Casing 

inspection and caliper logs are primarily used to determine the condition of the casing. 

Regular use of them may identify problems such as corrosion and allow mitigation before 

they cause a loss of integrity to the casing. To run these logs in a producing well, the tubing 

must first be pulled. 

Casing inspection logs are instruments lowered into the casing to inspect the casing for 

signs of wear or corrosion. One type of casing log uses video equipment to detect 

corrosion or holes. Another type uses electromagnetic pulses to detect variations in metal 

thickness. Running these logs in a producing well requires the tubing to be pulled. 

If an internal mechanical integrity problem is detected, the location of the problem must be found. 

Caliper or casing inspection logs can detect locations of holes in casing. Locations of leaks can also 

be detected by sealing off different sections of the well using packers and performing pressure tests 

on each section until the faulty section is located. If the leaks are in the tubing or a packer, the 

problem may be remedied by replacing the well component. Casing leaks may be remedied by 

performing a cement squeeze (Section D.2.2). 

D.4.2. External Mechanical Integrity 

External well mechanical integrity is demonstrated by establishing the absence of significant fluid 

movement along the outside of the casing, either between the outer casing and cement or between 

the cement and the wellbore. Failure of an external MIT can indicate improper cementing or 

degradation of the cement emplaced in the annular space between the outside of the casing and the 

wellbore. This type of failure can lead to movement of fluids out of intended production zones and 

toward drinking water resources. 

Several types of logs are available to evaluate external mechanical integrity, including temperature 

logs, noise logs, oxygen activation logs, radioactive tracer logs, and cement evaluation logs. 

 Temperature logs measure the temperature in the wellbore, and are capable of 

measuring small changes in temperature. They can be performed using instruments that 

are lowered down the well on a wireline, or they can be done using fiber optic sensors 

permanently installed in the well. When performed immediately after cementing, they can 

detect the heat from the cement setting and determine the location of the top of cement. 

After the cement has set, temperature logs can sense the difference in temperatures 
Appendix D – Well Injection Supplemental Information 

D-16

between formation fluids and injected or produced fluids. They may also detect 

temperature changes due to cooling or warming caused by flow. In this way, temperature 

logs may detect movement of fluid outside the casing in the wellbore (Arthur, 2012). 

Temperature logs require interpretation of the causes of temperature changes and are 

therefore subject to varying results among different users. 









Noise logs are sensitive microphones that are lowered down the well on a wireline. They 

are capable of detecting small noises caused by flowing fluids, such as fluids flowing 

through channels in the cement (Arthur, 2012). They are most effective at detecting fastmoving gas leaks and less successful with more slowly moving liquid migration. 

Oxygen activation logs consist of a neutron source and one or more detectors that are 

lowered on a wireline. The neutron source bombards oxygen molecules surrounding the 

wellbore and converts them into unstable nitrogen molecules that rapidly decay back to 

oxygen, emitting gamma radiation in the process. Gamma radiation detectors above or 

below the neutron source measure how quickly the oxygen molecules are moving away 

from the source, thereby determining flow associated with water. 

Radioactive tracer logs involve release of a radioactive tracer and then passing a 

detector up or down the wellbore to measure the path the tracers have taken. They can be 

used to determine if fluid is flowing up the wellbore. Tracer logs can be very sensitive but 

may be limited in the range over which leaks can be detected. 

Cement evaluation logs (also known as cement bond logs) are acoustic logs consisting of 

an instrument that sends out acoustic signals along with receivers, separated by some 

distance, that record the acoustic signals. As the acoustic signals pass through the casing, 

they will be attenuated to an extent, depending on whether the pipe is free or is bonded to 

cement. By analyzing the return acoustic signal, the degree of cement bonding with the 

casing can be determined. The cement evaluation log measures the sound attenuation as 

sound waves passing through the cement and casing. There are different types of cement 

evaluation logs available. Some instruments can only return an average value over the 

entire wellbore. Other instruments are capable of measuring the cement bond radially. 

Newer acoustic logging techniques with features such as flexural attenuation and acoustic 

impedance maps can identify channels as small as an inch (2.5 cm) in diameter (Landry et 

al., 2015). Cement logs do not actually determine whether fluid movement through the 

annulus is occurring. They only can determine whether cement is present in the annulus 

and in some cases can give a qualitative assessment of the quality of the cement in the 

annulus. Cement evaluation 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. It 

should be noted that these type of tests cannot detect whether or not fluid migration is 

occurring. They only indicate whether cement is present and give a qualitative indication 

of the degree of bonding of any cement present. Because interpretation of these logs are 

qualitative, there is also a great deal of subjectivity in their results. 

If the well fails an external MIT, damaged or missing cement may be repaired using a cement 

squeeze (Wojtanowicz, 2008). A cement squeeze involves injection of cement slurry into voids 
Appendix D – Well Injection Supplemental Information 

D-17

behind the casing or into permeable formations. Different types of cement squeezes are available 

depending on the location of the void needing to be filled and well conditions (Kirksey, 2013). 

Cement squeezes are not always successful, however, and may need to be repeated to successfully 

seal off flow (Wojtanowicz, 2008).
Appendix D – Well Injection Supplemental Information 

D-18

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Appendix E – Produced Water Handling Supplemental Information 

E-1 

Appendix E. Produced Water Handling 

Supplemental Information 
Appendix E – Produced Water Handling Supplemental Information 

E-2 

This page is intentionally left blank. 
Appendix E – Produced Water Handling Supplemental Information 

E-3 

Appendix E. Produced Water Handling Supplemental 

Information 

E.1. Specific Definitions of the Terms “Produced Water” and “Flowback”

Various organizations have used different definitions of the terms “produced water” and 

“flowback.” Several examples follow:

E.1.1. Produced Water

The American Petroleum Institute (API): “Produced water is any of the many types of water 

produced from oil and gas wells” (API, 2010c). 

The U.S. Department of Energy (DOE): “Produced water is water trapped in underground 

formations that is brought to the surface along with oil or gas” (Veil et al., 2004). 

The American Water Works Association (AWWA): “Produced water is the combination of flowback 

and formation water that returns to the surface along with the oil and natural gas” (AWWA, 2013). 

E.1.2. Flowback 

API: “The fracture fluids that return to the surface after a hydraulic fracture is completed” (API, 

2010c). 

AWWA: “Fracturing fluids that return to the surface through the wellbore after hydraulic fracturing 

is complete” (AWWA, 2013). 

Other definitions include production of hydrocarbons from the well (Barbot et al., 2013; U.S. EPA, 

2012e), or specify a time period (USGS, 2014; Haluszczak et al., 2013; Warner et al., 2013b; Hayes 

and Severin, 2012a; Hayes, 2009). 

E.2. Produced Water Volumes 

The EPA (U.S. EPA, 2015m) estimates of flowback volumes and long-term produced water volumes 

used to generate the summaries appearing in Table 7-3 of Chapter 7 appear below in Table E-1.
Appendix E – Produced Water Handling Supplemental Information 

E-4 

Table E-1. Produced water characteristics for wells by basin, formation, and resource type. 

Source: U.S. EPA (2016b). 

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Anadarko Caney Shale H 8.1 4.4 – 12 11 - - 0 - - 0

Cleveland

Tight H 1.7 0.2 – 4 928 - 12 – 40 2 410 59 – 2,000 1,160

V 0.18 0.033 – 3 15 50 50 – 50 1 66 56 – 400 130

Granite Wash Tight H 4.9 0.2 – 8.3 924 - 6.5 – 22 2 980 10 – 2,400 762

V 0.53 0.085 – 3 72 50 50 – 50 1 520 330 – 790 1,397

D - - 0 - - 0 480 160 – 940 83

Mississippi

Lime Tight H 2 1.3 – 5 3,301 50 50 – 50 1 -

37,000 –

120,000 4

V 0.34 0.016 –

0.71 59 - - 0 10 0.71 – 38 16

Woodford Shale H 5.2 1 – 12 3,243 34 20 – 50 3 5,500 3,200 –

6,400 198

V 0.36 0.015 –

1.6 11 - - 0 - - 0

D 1.6 0.21 –

1.9 10 - - 0 - - 0

ClintonMedina Tight V - - 0 - - 0 7.9 7.3 – 11 551
Appendix E – Produced Water Handling Supplemental Information 

E-5 

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Appalachian Devonian Shale V - - 0 - - 0 13 4.8 – 19 197

Marcellus Shale H 4.6 0.9 – 11 17,316 7.1 4 – 47 4,374 820 54 –

13,000 6,494

Shale V 0.25 0.11 –

5.4 116 40 21 – 60 7 200 94 – 1,000 741

D 0.16 0.092 –

0.17 6 - - 0 - - 0

Utica Shale H 6.8 1 – 13 1,108 2.5 0.66 –

27 684 800 420 –1,700 764

Arkoma Fayetteville Shale H 5 1.7 – 11 3,014 - 10 – 20 2 430 150 –

2,300 2,305

DenverJulesburg Codell Tight H 3.5 2.4 – 7.1 234 16 - 36 400 110 –

1,100 179

V 0.23 0.11 –

0.46 97 0 0 – 4 13 59 47 – 120 158

D 0.26 0.14 –

0.5 362 0 0 – 3 8 46 18 – 71 667

CodellNiobrara Tight H 2.8 2.7 – 5.4 65 7.2 7.2 – 7.2 32 75 19 – 560 38

V 0.3 0.15 –

0.4 490 2.8 - 21 33 13 – 65 2,113

D 0.4 0.2 –

0.46 806 0 0 – 5 11 45 28 – 70 1,853
Appendix E – Produced Water Handling Supplemental Information 

E-6 

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Denver 

Julesburg, 

cont.

Muddy J. Tight H 1.4 0.44 –

2.6 6 - - 0 860 220 –1,100 6

V 0.27 0.12 –

0.45 139 0.09 - 15 120 52 – 550 340

D 0.42 0.17 –

0.62 758 0 0 – 0 11 63 39 – 110 1,106

Niobrara Shale H 2.9 1.9 – 5.1 1,435 16 1.8 –

100 173 760 120 –1,300 1,213

V 0.24 0.015 –

0.31 455 33 1.6 – 90 29 330 15 – 600 5,808

D 0.36 0.13 –

2.9 25 - - 0 41 8.1 – 590 38

Fort Worth Barnett Shale H 3.7 1 – 7.3 26,495 30 21 – 40 11 530 240 –

4,200 11,957

V 1.3 0.38 –

1.9 3,773 - - 0 230 140 – 390 2,416

D 1.2 0.48 –

1.6 96 - - 0 210 79 – 410 481

Green River HilliardBaxterMancos

Shale H 1.7 1 – 5.6 2 - - 0 - - 0

Lance Tight H - - 0 - - 0 730 350 –

1,100 6
Appendix E – Produced Water Handling Supplemental Information 

E-7 

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Green River, 

cont.

Lance Tight V 1.5 0.82 –

3.9 37 3.3 0.88 –50 38 610 410 – 840 61

D .97 0.65 –

2.1 881 12 1.8 – 40 187 650 420 –1,100 2,787

Mancos Shale H 15 1.8 – 24 24 3.1 0.063 –

17 8 770 - 26

D 5.4 0.12 – 20 10 - - 0 140 0.83 –

1,400 36

Mesaverde Tight H - - 0 - - 0 220 130 – 480 5

V 0.16 0.13 –

0.22 21 18 6.3 – 43 15 440 120 – 780 33

D 0.19 0.11 –

0.3 448 9.3 0.7 – 36 94 380 150 – 610 856

Illinois New Albany Shale H - - 0 - - 0 2,940 2,940 –

2,940 1

Michigan Antrim Shale V 0.05 0.05 –

0.05 1 - 25 – 75 2 1,300 530 –4,600 7

Permian Avalon & 

Bone Spring Shale H 2.3 1.2 – 5.7 965 19 4.9 – 40 48 2,700 2,100 –5,700 1,171

V 0.4 0.07 –

1.3 21 - - 0 2,000 1,000 –4,800 68

D 1.8 1.2 – 3.4 40 33 12 – 57 36 1,300 800 –

3,300 94
Appendix E – Produced Water Handling Supplemental Information 

E-8 

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Permian, 

cont.

BarnettWoodford Shale H 2.1 0.5 – 4.5 2 - - 0 - - 0

Delaware Shale H 1.3 0.42 – 3 85 79 9.7 –

230 20 9,400 5,000 –29,000 232

V 0.19 0.044 –

0.38 141 210 84 – 580 19 1,600 1,100 –3,800 412

D 0.26 0.15 –

0.4 47 - - 0 4,500 2,400 –5,700 90

Devonian 

(TX) Shale H 0.47 0.091 –5.5 43 - - 0 1,700 630 –2,700 325

V 0.14 0.075 – 1 187 - - 0 3,700 1,400 –

5,400 306

D 0.11 0.037 –

0.13 11 - - 0 2,400 250 –12,000 40

Morrow Tight V - - 0 - - 0 130 41 – 290 7

D - - 0 - - 0 140 34 – 2,200 66

Spraberry Tight H 1.3 0.069 –

6.5 29 - - 0 1,000 420 –3,800 41

V 0.91 0.071 –

1.6 449 - - 0 1,000 670 –1,500 936

D 1

0.06 –

1.5 16 - - 0 1,200 660 –2,500 42
Appendix E – Produced Water Handling Supplemental Information 

E-9 

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Permian, 

cont.

Trend Area Tight H 8.3 2.4 – 12 991 - - 0 890 530 –

3,900 457

V 1.1 0.58 –

1.9 8,733 - - 0 780 690 – 920 15,494

D 1 0.4 – 1.7 41 - - 0 620 370 –

1,500 50

Wolfcamp

Shale H 6.7 1.4 – 12 1,775 16 12 – 23 12 3,500 450 –

15,000 1,237

V 1.6 0.18 –

2.3 383 - - 0 780 460 –1,400 1,142

D 1.8 0.17 – 3 12 - - 0 1,700 750 –

3,600 170

Piceance & 

Uinta Mesaverde Tight D -- -- 0 -- -- 0 510 130 – 700 52

Hermosa Shale D -- -- 0 -- -- 0 47 27 – 260 21

Powder River Mowry Shale H 2.5 0.76 –

7.4 15 15 4.3 –580 14 450 61 – 2,100 16

San Juan Dakota Tight V 0.16 0.061 –

0.34 85 1.6 - 22 75 35 – 490 81

D 0.12 0.063 –

0.32 136 4.1 1.1 – 60 29 230 53 – 950 511

Mesaverde Tight V -- -- 0 -- -- 0 43 14 – 560 5

D -- -- 0 -- -- 0 21 15 – 180 49
Appendix E – Produced Water Handling Supplemental Information 

E-10

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

San Juan, 

cont.

Pictured Cliffs Tight H -- -- 0 -- -- 0 370 190 – 720 7

D -- -- 0 -- -- 0 4,700 1,200 –

8,200 6

TX-LA-MS Bossier

Shale H 3.8 2.6 – 5.4 12 -- -- 0 37 5.6 – 370 47

V 0.61 0.22 –

1.7 82 -- -- 0 230 4.8 – 480 1,143

D 0.55 0.18 –

1.1 48 -- -- 0 150 1.2 – 300 304

Cotton Valley Tight H 4.4 0.25 –

8.5 433 60 60 – 60 1 710 410 –2,600 689

V 0.27 0.018 –

1.4 355 60 60 – 60 1 700 490 – 890 9,267

D 0.45 0.046 – 4 79 60 60 – 60 1 620 240 – 980 1,912

Haynesville Shale H 5.7 0.95 – 15 3,855 5.2 5.2 – 30 3 910 84 – 1,200 2,575

V 0.9 0.2 – 2.5 2 -- -- 0 330 210 – 560 230

D 3.9 1.9 – 7.3 35 -- -- 0 660 130 –

1,200 204

Travis Peak Tight H 3 0.25 – 6 2 -- -- 0 710 110 –

4,200 7

V 0.17 0.032 – 4 36 -- -- 0 630 270 – 930 1,046

D -- -- 0 -- -- 0 520 140 – 800 134
Appendix E – Produced Water Handling Supplemental Information 

E-11

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

TX-LA-MS, 

cont.

Tuscaloosa Shale H 11 6.1 – 14 28 -- -- 0 - - 0

V 13 4.7 – 19 11 -- -- 0 7,400 220 –

51,000 64

Western Gulf Austin Chalk Tight H 1.7 0.83 –

5.4 134 -- -- 0 2,200 980 –5,100 752

V -- -- 0 -- -- 0 97 21 – 1,500 51

Eagle Ford Shale H 4.8 1 – 14 12,810 4.2 2.1 – 8.4 1,800 1,900 88 – 6,200 7,971

V 0.94 0.23 – 2 8 -- -- 0 1,200 510 –

2,300 12

D -- -- 0 -- -- 0 4,300 3,000 –

5,600 5

Edwards Tight H -- -- 0 -- -- 0 2,300 1,000 –

24,000 266

V -- -- 0 -- -- 0 560 150 –

2,100 32

D -- -- 0 -- -- 0 160 69 – 290 6

Olmos Tight H 1.9 0.37 – 6 246 -- -- 0 180 13 – 700 229

V 0.11 0.078 –

0.21 50 -- -- 0 78 52 – 370 1,120

D -- -- -- -- -- 0 51 15 – 470 16

Pearsall Shale H 3.5 1.6 – 5.6 47 -- -- 0 160 53 – 1,500 51
Appendix E – Produced Water Handling Supplemental Information 

E-12

Fracturing fluid 

(Mgal)

Flowback (% of fracturing 

fluid returned)

Long-term produced 

water rates (gpd)

Basin Formation

Resource

type Well type

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangeb

Data 

pointsc

Weighted 

averagea Rangea

Data 

pointsc

Western 

Gulf, cont. Vicksburg Tight V 0.21 0.072 –0.61 158 -- -- 0 700 330 – 990 702

D 0.23 0.11 –

0.63 40 -- -- 0 830 390 –1,400 193

Wilcox Lobo Tight H 0.33 0.082 –

2.4 8 -- -- 0 370 250 – 610 84

V 0.1 0.042 –

0.6 56 -- -- 0 650 400 – 940 1,084

D 0.094 0.058 –

0.16 14 -- -- 0 500 300 –4,200 395

Williston Bakken Shale H 2.4 0.35 – 10 8,103 19 5 – 47 225 910 500 –

3,800 7,309

V 0.16 0.04 –

2.7 6 -- -- 0 2,400 150 –5,100 5

“--“ indicates no data; H, horizontal well; D, directional well; V, vertical well.

a For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a median value.

b For some formations, the number of data points was not reported in the data source. In these instances, the EPA reported the number of data points as equal to one, even if 

the source reported a range and median value.

C For some formations, the number of data points was not reported in the data source. In these instances, this table reports that number as 1, except if the source reported a 

range in which case this table reports the number of data points as 2.
Appendix E – Produced Water Handling Supplemental Information 

E-13

E.2.1. Summary of Results from Produced Water Studies 

Data were collected from six vertical and eight horizontal wells in the Marcellus Shale of 

Pennsylvania and West Virginia (Hayes, 2009). The author collected samples of flowback after one, 

five, and 14 days after hydraulic fracturing was completed, as well as a produced water sample 90 

days after completion of the wells. Both the vertical and horizontal wells showed their largest 

volume of flowback between one and five days after fracturing, as shown in Figure E-1. 

Figure E-1. Fraction of injected hydraulic fracturing fluid recovered from six vertical (top) and 

eight horizontal (bottom) wells completed in the Marcellus Shale. 

Data used with permission from Hayes (2009). 
Appendix E – Produced Water Handling Supplemental Information 

E-14

The wells continued to produce water, and at 90 days, samples were available from four each of the 

horizontal and vertical wells. The vertical wells produced on average 7,600 gal/day (29,000 L/day) 

and the horizontal wells a similar 8,400 gal/day (32,000 L/day). Results from one Marcellus Shale 

study were fitted to a power curve (Ziemkiewicz et al., 2014) (Figure E-2). These and the Hayes 

(2009) data show decreasing rates of flowback with time. In West Virginia, water recovered at the 

surface within 30 days following injection or before 50% of the hydraulic fracturing fluid volume is 

returned to the surface is reported as flowback. Data from wells in the Marcellus Shale in West 

Virginia (Hansen et al., 2013) reveal the variability of recovery from wells in the same formation 

and that the amount of hydraulic fracturing fluid recovered was estimated to be less than 15% from 

over 80% of the wells (Figure E-3).

Figure E-2. Example of flowback and produced water from the Marcellus Shale, illustrating 

rapid decline in water production and cumulative return of approximately 30% of the volume 

of hydraulic fracturing fluid. 

Source: Ziemkiewicz et al. (2014). Ziemkiewicz, P; Quaranta, JD; McCawley, M. (2014). Practical measures for 

reducing the risk of environmental contamination in shale energy production. Environ. Sci.: Processes & Impacts 

16: 1692-1699. Reproduced with permission from The Royal Society of Chemistry. 

http:// dx.doi.org/10.1039/C3EM00510K.
Appendix E – Produced Water Handling Supplemental Information 

E-15

Figure E-3. Percent of hydraulic fracturing fluid recovered for Marcellus Shale wells in West 

Virginia (2010 − 2012). 

One data point showing 98% recovery omitted. Source: Hansen et al. (2013). Reprinted with permission from 

Downstream Strategies, San Jose State University, and Earthworks Oil & Gas Accountability Project. 

Nicot et al. (2014) show a counter-example where the produced water exceeded the amount of 

hydraulic fracturing fluid injected. When the produced water data were presented as the 

percentage of hydraulic fracturing fluid, the median exceeded 100% at around 36 months (Figure 

E-4 and Figure E-5). This means that roughly 50% of the wells were producing more water than 

was used in stimulating production. Nicot et al. (2014) did not identify the source or mechanism for 

the excess water. Systematic breaching of the underlying karstic Ellenburger Formation was not 

believed likely; nor was operator efficiency or skill. A number of geologic factors that could impact 

water migration were identified by DOE (2011) in the Barnett Shale, including fracture height, 

aperture size, and density, fracture mineralization, the presence of karst chimneys underlying parts 

of the Barnett Shale, and others, but the impact of these on water migration was not determined. 
Appendix E – Produced Water Handling Supplemental Information 

E-16

Figure E-4. Barnett Shale monthly water-production percentiles (5th, 30th, 50th, 70th, and 90th) 

and number of wells with data (dashed line). 

FP is the amount of water that flows back to the surface, commingled with water from the formation. Reprinted 

with permission from Nicot, JP; Scanlon, BR; Reedy, RC; Costley, RA. (2014). Source and fate of hydraulic fracturing 

water in the Barnett Shale: A historical perspective [Supplemental Information]. Environ Sci Technol 48: 2464-

2471. Copyright 2014 American Chemical Society. 

Figure E-5. Barnett Shale production data for approximately 72 months. 

Flowback and produced water are reported as the percentage of hydraulic fracturing fluid. The dashed line shows 

the number of horizontal wells included. Data for each percentile show declining production with time, but the 

median production exceeds 100% of the hydraulic fracturing fluid. FP is the amount of water that flows back to the 

surface, commingled with water from the formation. Reprinted with permission from Nicot, JP; Scanlon, BR; 

Reedy, RC; Costley, RA. (2014). Source and fate of hydraulic fracturing water in the Barnett Shale: A historical 

perspective. Environ Sci Technol 48: 2464-2471. Copyright 2014 American Chemical Society. 
Appendix E – Produced Water Handling Supplemental Information 

E-17

E.3. Chemical Content of Produced Water 

In the main text of Chapter 7, we describe aspects of flowback and produced water composition, 

including temporal changes in water quality parameters of flowback (Section 7.3.3) and major 

classes of compounds in produced water (Section 7.3.4). In Section 7.3.4.2, we describe variability 

as occurring on three levels: between different rock types (e.g., coal vs. sandstone), between 

formations composed of the same rock types (e.g., Barnett Shale vs. Bakken Shale), and within 

formations of the same rock type (e.g., northeastern vs. southwestern Marcellus Shale). In this 

appendix, we present data from the literature that illustrate the differences among these three. 

E.3.1. General Water Quality Parameters 

As noted in Section 7.3.4.3, the EPA identified data characterizing the content of flowback and 

produced water from unconventional reservoirs including 12 shale and tight formations and 

coalbed methane (CBM) basins. These formations and basins span 18 states. Note that in this 

subsection we treat all fluids as produced water. As a consequence, the variability of reported 

concentrations is likely higher than if the data could be standardized to a specific point on the 

flowback-to-produced water continuum. Table E-2 and Table E-3 provide supporting data on 

general water quality parameters of produced water in shale, tight formations, and coal seams for 

12 formations.
Appendix E – Produced Water Handling Supplemental Information 

E-18

Table E-2. Reported concentrations of general water quality parameters in produced water for unconventional shale and tight 

formations, presented as: average (minimum-maximum) or median (minimum-maximum). 

Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians. 

Shales Tight formations

Parameter Units Bakkena BarnettbFayettevillec Marcellus

Cotton 

Valley 

Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States n/a MT, ND TX AR PAd PA, WVeLA, TX PA CO, NM, UT, WY OK

Acidity mg/L -

NC 

(ND − ND) -

NC 

(<5 − 473)

162

(5 – 925)

- - - -

Alkalinity mg/L -

725 

(215 –

1,240)

1,347 

(811 – 1,896)

165 

(8 – 577)

99.8

(7.5 – 577)

-

99 

(43 – 194) -

582 

(207 –

1,220)

Ammonium mg/L - - - - -

89 

(40 – 131) - - -

Bicarbonate mg/L 291 (122

– 610) - - - - -

524 (ND –

8,440)

2,230 (1,281 –

13,650) -

Biochemical 

oxygen 

demand (BOD)

mg/L -

582 

(101 –

2,120)

- -

141

(2.8 –

12,400)

- - - -

Carbonate mg/L - - - - - - -

227 

(ND−1,680) -

Chloride mg/L

119,000 

(90,000 –

133,000)

34,700 

(9,600 –

60,800)

9,156 

(5,507 –

12,287)

57,447 

(64 –

196,000)

49,000

(64.2 –

196,000)

101,332 

(3,167 –

221,498.7)

132,567 

(58,900 –

207,000)

4,260 

(8 – 75,000)

44,567 

(23,000 –

75,000)

Chemical 

oxygen 

demand

mg/L -

2,945

(927 –

3,150)

-

15,358 

(195 –

36,600)

4,670

(195 –

36,600)

- - - -
Appendix E – Produced Water Handling Supplemental Information 

E-19

Shales Tight formations

Parameter Units Bakkena BarnettbFayettevillec Marcellus

Cotton 

Valley 

Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States n/a MT, ND TX AR PAd PA, WVeLA, TX PA CO, NM, UT, WY OK

DO mg/L - - - - - -

0.8 

(0.2 – 2.5) - -

DOC mg/L -

11.2

(5.5 – 65.3) - -

117

(3.3 – 5,960)

- - - -

Hardness as 

CaCO3

mg/L -

5,800

(3,500 –

21,000)

-

34,000 

(630 –

95,000)

25,000

(156 –

106,000)

- - - -

Oil and grease mg/L -

163.5

(88.2 –

1,430)

-

74 

(5 – 802)

16.85

(4.7 – 802) - - - -

pH U

5.87 (5.47

– 6.53)

7.05

(6.5 – 7.2) -

6.6 

(5.1 – 8.4)

6.5

(4.9 – 7.9) -

6.3 

(5.5 – 6.8)

8 

(5.8 – 11.62)

6.3 

(6.1 – 6.4)

Specific 

conductivity μS/cm

213,000 

(205,000

–

220,800)

111,500

(34,800 –

179,000)

- -

183,000

(479 –

763,000)

-

184,800 

(118,000 –

211,000)

- -

Specific gravity --

1.13 

(1.0961 –

1.155)

- - - - - - - -

TDS mg/L

196,000 

(150,000

–

219,000)

50,550

(16,400 –

97,800)

13,290 

(9,972 –

15,721)

106,390 

(680 –

345,000)

87,800

(680 –

345,000)

164,683 

(5,241 –

356,666)

235,125 

(106,000 –

354,000)

15,802 

(1,032 – 125,304)

73,082 

(56,541 –

108,813)
Appendix E – Produced Water Handling Supplemental Information 

E-20

Shales Tight formations

Parameter Units Bakkena BarnettbFayettevillec Marcellus

Cotton 

Valley 

Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States n/a MT, ND TX AR PAd PA, WVeLA, TX PA CO, NM, UT, WY OK

Total Kjeldahl 

nitrogen mg/L -

171

(26 – 298) - -

94.9

(5.6 – 312)

- - - -

TOC mg/L -

9.75

(6.2 – 36.2) -

160 

(1.2 –

1,530)

89.2

(1.2 – 5,680)

198 

(184 – 212) - - -

Total 

suspended 

solids

mg/L -

242

(120 – 535) -

352 

(4 – 7,600)

127

(6.8 – 3,220) - - - -

Turbidity NTU -

239

(144 – 314) - -

126

(2.3 – 1,540)

- - - -

n/a, not applicable; -, no value available; NC, not calculated; ND, not detected; SU= standard units; bolded italic numbers are medians 

a Stepan et al. (2010). n = 3. Concentrations were calculated based on Stepan et al.'s raw data. Samples had charge balance errors of 1.74, -0.752, and -0.220% 

b Hayes and Severin (2012a). n = 16. This data source reported concentrations without direct presentation of raw data. 

c Warner et al. (2013a).c n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included. 

d Barbot et al. (2013). n = 134 − 159. This data source reported concentrations without direct presentation of raw data.

e Hayes (2009). n = 31 – -67. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks 

omitted. 

f Blondes et al. (2014). Cotton Valley Group, n=2; Mesa Verde, n = 1 − 407; Oswego, n = 4 − 30. Concentrations were calculated based on raw data presented in the U.S. 

Geological Survey (USGS) National Produced Water Database v2.0. 

g Dresel and Rose (2010). n = 3 − 15. Concentrations were calculated based on Dresel and Rose's raw data.
Appendix E – Produced Water Handling Supplemental Information 

E-21

Table E-3. Reported concentrations of general water quality parameters in produced water 

for coalbed basins, presented as: average (minimum-maximum). 

Parameter Units Black Warriora Powder Riverb RatonbSan Juanb

States n/a AL, MS MT, WY CO, NM AZ, CO, NM, UT

Alkalinity mg/L 355 (3 – 1,600) 1,384 (653 – 2,672) 1,107 (130 – 2,160) 3,181 (51 – 11,400)

Ammonium mg/L 3.60 (0.16 – 8.91) - - -

Bicarbonate mg/L 427 (2 – 1,922) 1,080 (236 – 3,080) 1,124 (127 – 2,640) 3,380 (117 – 13,900)

Carbonate mg/L 3 (0 – 64) 2.17 (0.00 – 139.0) 51.30 (1.30 –

316.33) 40.17 (0.00 – 1,178)

Chloride mg/L 9,078 (11 – 42,800) 21 (BDL – 282) 787 (4.8 – 8,310) 624 (BDL – 20,100)

Chemical oxygen 

demand mg/L 830 (0 – 10,500) - - -

Dissolved oxygen mg/L - 1.07 (0.11 – 3.48) 0.39 (0.01 – 3.52) 0.51 (0.04 – 1.69)

DOC mg/L 3.37 (0.53 – 61.41) 3.18 (1.09 – 8.04) 1.26 (0.30 – 8.54) 3.21 (0.89 – 11.41)

Hardness as 

CaCO3

mg/L 871 (3 – 6,150) - - -

Hydrogen sulfide mg/L - - 4.41 (BDL – 190.0) 23.00 

(23.00 – 23.00)

Oil and grease mg/L - - 9.10 (0.60 – 17.6) -

pH SU 7.5 (5.3 – 9.0) 7.71 (6.86 – 9.16) 8.19 (6.90 – 9.31) 7.82 (5.40 – 9.26)

Phosphate mg/L 0.435 (0.026 –

3.570) BDL (BDL – BDL) 0.04 (BDL – 1.00) 1.89 (BDL – 9.42)

Specific 

conductivity μS/cm 20,631 (718 – 97,700)

1,598 

(413 – 4,420)

3,199 

(742 – 11,550)

5,308 

(232 – 18,066)

TDS mg/L 14,319 

(589 – 61,733)

997 

(252 – 2,768)

2,512 

(244 – 14,800)

4,693 

(150 – 39,260)

Total Kjeldahl 

nitrogen mg/L 6.08 (0.15 – 38.40) 0.48 (BDL – 4.70) 2.61 (BDL – 26.10) 0.46 (BDL – 3.76)

TOC mg/L 6.03 (0.00 – 103.00) 3.52 (2.07 – 6.57) 1.74 (0.25 – 13.00) 2.91 (0.95 – 9.36)

Total suspended 

solids mg/L 78 (0 – 2,290) 11.0 (1.4 – 72.7) 32.3 (1.0 – 580.0) 47.2 (1.4 – 236.0)

Turbidity NTU 74 (0 – 539) 8.2 (0.7 – 57.0) 4.5 (0.3 – 25.0) 61.6 (0.8 – 810.0)

n/a, not applicable; -, no value available; BDL, below detection limit.

a DOE (2014). n = 206. Concentrations were calculated based on raw data presented in the reference. 

b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without 

presentation of raw data. 
Appendix E – Produced Water Handling Supplemental Information 

E-22

E.3.2. Salinity and Inorganics

Table E-4 and Table E-5 provide supporting data on salinity and inorganic constituents of produced 

water for 12 formations. 

E.3.2.1. Processes Controlling Salinity and Inorganics Concentrations

Multiple mechanisms likely control elevated salt concentrations in flowback and produced water 

and are largely dependent upon post-injection fluid interactions and the formation’s stratigraphic 

and hydrogeologic environment (Barbot et al., 2013). High inorganic ionic loads observed in 

flowback and produced water are expressed as TDS. 

Subsurface brines or formation waters are saline fluids associated with the targeted formation. 

Shale and sandstone brines are typically much more saline than coalbed waters. After hydraulic 

fracturing fluids are injected into the subsurface, the hydraulic fracturing fluids (which are typically 

not sources of high TDS) contact in-situ brines, which typically contain high ionic loads (Haluszczak 

et al., 2013). 

Deep brines, present in over- or underlying strata, may naturally migrate into targeted formations 

over geologic time or artificially intrude if a saline aquifer is breached during hydraulic fracturing 

(Chapman et al., 2012; Maxwell, 2011; Blauch et al., 2009). Whether it is through natural or induced 

intrusion, saline fluids may contact the producing formation and introduce novel salinity sources to 

the produced water (Chapman et al., 2012). Despite the general use of fresh water for hydraulic 

fracturing fluid, some elevated salts in produced water may result from the use of reused saline 

flowback or produced water as a hydraulic fracturing base fluid (Hayes, 2009). 
Appendix E – Produced Water Handling Supplemental Information 

E-23

Table E-4. Reported concentrations (mg/L) of inorganic constituents contributing to salinity in produced water from 

unconventional reservoirs (including shale and tight formations), presented as: average (minimum-maximum) or median 

(minimum-maximum). 

Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians. 

Shale Tight Formations

Parameter Bakkena BarnettbFayettevillec Marcellus 

Cotton 

Valley 

Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States MT, ND TX AR PAd PA, WVeLA, TX PA

CO, NM, UT, 

WY OK

Bromide -

589

(117 – 798)

111 

(96 – 144)

511 (0.2 –

1,990)

512 

(15.8 – 1,990)

498 

(32 – 1,338)

1,048 

(349 – 1,350) - -

Calcium 9,680 (7,540

– 13,500)

1,600 (1,110 –

6,730)

317 

(221 – 386)

7,220 (38 –

41,000)

7,465

(173 – 33,000)

19,998 (181 –

51,400)

20,262 (8,930

– 34,400)

212

(1.01 – 4,580)

5,903 (3,609 –

8,662)

Chloride

119,000 

(90,000 –

133,000)

34,700 (9,600

– 60,800)

9,156 (5,507 –

12,287)

57,447 

(64 –

196,000)

49,000

(64.2 –

196,000)

101,332 

(3,167 –

221,498.7)

132,567 

(58,900 –

207,000)

4,260

(8 – 75,000)

44,567 (23,000 –

75,000)

Fluoride -

3.8

(3.5 – 12.8) - -

0.975

(0.077 – 32.9)

- - - -

Iodine - - - - -

20 

(1 – 36)

39 

(11 – 56)

1.01 

(1.01 – 1.01) -

Nitrate as N - -

NC 

(ND – ND) -

1.7

(0.65 – 15.9)

- -

0.6 

(0.6 – 0.6) -

Nitrite as N -

4.7 

(3.5 – 38.1) - -

11.8

(1.1 – 146)

- - - -

Phosphorus NC 

(ND − 0.03)

0.395 

(0.19 – 0.7) - -

0.3 (0.08 –

21.8) - - - -

Potassium 2,970 

(0 – 5,770)

316

(80 – 750) - -

337

(38 – 3,950)

1,975 

(8 – 7,099)

858 

(126 – 3,890)

160 

(4 – 2,621) -
Appendix E – Produced Water Handling Supplemental Information 

E-24

Shale Tight Formations

Parameter Bakkena BarnettbFayettevillec Marcellus 

Cotton 

Valley 

Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States MT, ND TX AR PAd PA, WVeLA, TX PA

CO, NM, UT, 

WY OK

Silica 7 

(6.41 – 7) -

52 

(13 – 160) - -

4 

(4 – 4) - - -

Sodium

61,500

(47,100 –

74,600)

18,850 (4,370

– 28,200)

3,758 (3,152 –

4,607)

21,123 

(69 –

117,000)

21,650

(63.8 – 95,500)

39,836 (1,320

– 85,623.24)

58,160 

(24,400 –

83,300)

5,828 (132 –

48,817)

19,460 (13,484 –

31,328)

Sulfate 660 

(300 – 1,000)

709 

(120 – 1,260)

NC 

(ND – 3)

71 

(0 – 763)

58.9

(2.4 – 348)

407 

(ND –

2,200.46)

20 

(1 – 140)

837

(ND – 14,612)

183 

(120 – 271)

Sulfide -

NC 

(ND – ND) - -

3.2

(1.6 – 5.6)

-

0.7 

(0.1 – 2.5) - -

Sulfite - - - -

12.4

(5.2 – 73.6)

- - - -

TDS

196,000 

(150,000 –

219,000)

50,550 

(16,400 –

97,800)

13,290 

(9,972 –

15,721)

106,390 

(680 –

345,000)

87,800

(680 –

345,000)

164,683 

(5,241 –

356,666)

235,125 

(106,000 –

354,000)

15,802 

(1,032 –

125,304)

73,082 

(56,541 –

108,813)

-, no value available; NC, not calculated; ND, not detected. Bolded italic numbers are medians. 

a Stepan et al. (2010). n = 3. Concentrations were calculated based on Stepan et al.'s raw data. Samples had charge balance errors of 1.74, -0.752, and -0.220% 

b Hayes and Severin (2012a). n = 16. This data source reported concentrations without presentation of raw data.

c Warner et al. (2013b). n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included. 

d Barbot et al. (2013). n = 95 − 159. This data source reported concentrations without presentation of raw data. 

e Hayes (2009). n = 8-65. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks 

omitted. 

f Blondes et al. (2014) Cotton Valley Group, n = 2; Mesa Verde, n = 1 − 407; Oswego, n = 4 − 30. Concentrations were calculated based on raw data presented in the USGS 

National Produced Water Database v2.0. 

g Dresel and Rose (2010). n = 3 − 15. Concentrations were calculated based on Dresel and Rose's raw data.
Appendix E – Produced Water Handling Supplemental Information 

E-25

Table E-5. Reported concentrations (mg/L) of inorganic constituents contributing to salinity 

in produced water for coalbed methane basins, presented as: average (minimum-maximum).

Parameter Black Warriora Powder Riverb RatonbSan Juanb

State AL, MS MT, WY CO, NM AZ, CO, NM, UT

Barium 45.540 (0.136 – 352) 0.61 (0.14 – 2.47) 1.67 (BDL – 27.40) 10.80 (BDL – 74.0)

Boron 0.185 (0 – 0.541) 0.17 (BDL – 0.39) 0.36 (BDL – 4.70) 1.30 (0.21 – 3.45)

Bromide - 0.09 (BDL – 0.26) 4.86 (0.04 – 69.60) 9.77 (BDL – 43.48)

Calcium 218 (0 – 1,640) 32.09 (2.00 – 154.0) 14.47 (0.81 – 269.0) 53.29 (1.00 – 5,530)

Chloride 9,078 (11 – 42,800) 21 (BDL – 282) 787 (4.8 – 8,310) 624 (BDL – 20,100)

Fluoride 6.13 (0.00 – 22.60) 1.57 (0.40 – 4.00) 4.27 (0.59 – 20.00) 1.76 (0.58 – 10.00)

Magnesium 68.12 (0.18 – 414.00) 14.66 (BDL – 95.00) 3.31 (0.10 – 56.10) 15.45 (BDL – 511.0)

Nitrate 8.70 (0.00 – 127.50) - - -

Nitrite 0.03 (0.00 – 2.08) - - -

Phosphorus 0.32 (0.00 – 5.76) - - -

Potassium 12.02 (0.46 – 74.00) 11.95 (BDL – 44.00) 6.37 (BDL – 29.40) 26.99 (BDL – 970.0)

Silica 8.66 (1.04 – 18.10) 6.46 (4.40 – 12.79) 7.05 (4.86 – 10.56) 12.37 (3.62 – 37.75)

Sodium 4,353 (126 – 16,700) 356 (12 – 1,170) 989 (95 – 5,260) 1,610 (36 – 7,834)

Strontium 11.354 (0.015 – 142.000) 0.60 (0.10 – 1.83) 5.87 (BDL – 47.90) 5.36 (BDL – 27.00)

Sulfate 5.83 (0.00 – 302.00) 5.64 (BDL – 300.0) 14.75 (BDL – 253.00) 25.73 (BDL – 1,800)

TDS 14,319 (589 – 61,733) 997 (252 – 2,768) 2,512 (244 – 14,800) 4,693 (150 – 39,260)

-, no value available; BDL, below detection limit.

a DOE (2014). n = 206. Concentrations were calculated based on the authors’ raw data.

b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without 

presentation of raw data. 

E.3.3. Metals and Metalloids

Table E-6 and Table E-7 provide supporting data on metal constituents of produced water for 12

formations. 

E.3.3.1. Processes Controlling Mineral Precipitation and Dissolution

Hydraulic fracturing treatments introduce fluids into the subsurface that are not in equilibrium 

with respect to formation mineralogy. Subsurface geochemical equilibrium modeling and 

saturation indices are therefore used to assess the solution chemistry of produced water from 

unconventional reservoirs and the subsequent likelihood of precipitation and dissolution reactions 

(Engle and Rowan, 2014; Barbot et al., 2013). Dissolution and precipitation reactions between 
Appendix E – Produced Water Handling Supplemental Information 

E-26

fracturing fluids, formation solids, and formation water contribute to the chemistry of flowback and 

produced water. 

Depending upon the formation chemistry and composition of the hydraulic fracturing fluid, the 

hydraulic fracturing fluid may initially have a lower ionic strength than existing formation fluids. 

Consequently, salts, carbonate, sulfate, and silicate minerals may undergo dissolution or 

precipitation. Proppants may also undergo dissolution or serve as nucleation sites for precipitation 

(McLin et al., 2011). 

Currently, relatively little literature quantitatively explores subsurface dissolution and 

precipitation reactions between hydraulic fracturing fluids and formation solids and water. 

However, the processes that take place will likely be a function of the solubilities of the minerals, 

the chemistry of the fluid, pH, redox conditions, and temperature. 

Documented dissolution processes in unconventional reservoirs include the dissolution of feldspar 

followed by sodium enrichment in coalbed produced water (Rice et al., 2008). Dissolution of 

barium-rich minerals (barite (BaSO4) and witherite (BaCO3)), and strontium-rich minerals (celestite 

(SrSO4) and strontianite (SrCO3)) are known to enrich shale produced waters in barium and 

strontium (Chapman et al., 2012). 

Known precipitation processes in unconventional reservoirs include the precipitation of carbonate 

and subsequent reduction of calcium and magnesium concentrations in coalbed produced water 

(Rice et al., 2008). Additionally, calcium carbonate precipitation is suspected to cause declines in pH 

and alkalinity levels in shale produced water (Barbot et al., 2013). 

The subsurface processes associated with fluid-rock interactions take place over a scale of weeks to 

months through the generation of flowback and produced water. Note that the types and extent of 

subsurface dissolution and precipitation reactions change with time, from injection through 

flowback and production. For instance, Engle and Rowan (2014) found that early Marcellus Shale 

flowback was under-saturated with respect to gypsum (CaSO4·2H2O), halite (NaCl), celestite, 

strontianite, and witherite, indicating that these minerals would dissolve in the subsurface. Fluids 

were oversaturated with respect to barite. Saturation indices for gypsum, halite, celestite, and 

barite all increased during production. Knowing when dissolution and precipitation will likely 

occur is important, because dissolution and precipitation of minerals change formation 

permeability and porosity, which can affect production (André et al., 2006).
Appendix E – Produced Water Handling Supplemental Information 

E-27

Table E-6. Reported concentrations (mg/L) of metals and metalloids from produced water from unconventional reservoirs 

(including shale and tight formations), presented as: average (minimum-maximum) or median (minimum-maximum). 

Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians. Note 

that calcium, potassium, and sodium appear in Table E-4.

Shale Tight Formation

Parameter Bakkena BarnettbFayettevillec Marcellus

Cotton 

Valley Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States MT, ND TX AR PAd PA, WVeLA, TX PA

CO, NM, UT, 

WY OK

Aluminum -

0.43 (0.37 –

2.21) - -

2.57

(0.22 – 47.2)

- - - -

Antimony -

NC 

(ND – ND) - -

0.028

(0.018 –

0.038)

- - - -

Arsenic -

NC 

(ND – ND) - -

0.101

(0.013 –

0.124)

- - - -

Barium 10 

(0 − 24.6)

3.6 (0.93 –

17.9)

4 

(3 – 5)

2,224 (0.24

– 13,800)

542.5

(2.590 –

13,900)

160 (ND –

400.52)

1,488 (7 –

4,370)

139 

(4 – 257)

Beryllium - NC (ND – ND) - - - - - - -

Boron 116 

(39.9 – 192)

30.3 (7.0 –

31.9)

4.800 

(2.395 –

21.102)

-

12.2

(0.808 – 145)

37 

(2 – 100) -

10 

(1 – 14.2) -

Cadmium -

NC 

(ND – ND) - - - - - - -

Chromium -

0.03 (0.01 –

0.12) - -

0.079

(0.011 –

0.567)

- - - -

Cobalt -

0.01 (0.01 –

0.01) - - - - - - -
Appendix E – Produced Water Handling Supplemental Information 

E-28

Shale Tight Formation

Parameter Bakkena BarnettbFayettevillec Marcellus

Cotton 

Valley Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States MT, ND TX AR PAd PA, WVeLA, TX PA

CO, NM, UT, 

WY OK

Copper NC 

(ND – 0.21)

0.29 (0.06 –

0.52) - -

0.506

(0.253 –

4.150)

0.7 

(0.48 – 1)

0.04 (0.01 –

0.13) - -

Iron 96 

(ND – 120)

24.9 (12.1 –

93.8)

7 

(1 – 13) -

53.65

(2.68 – 574)

-

188 

(90 – 458)

9 

(1 – 29)

61 

(41 – 78)

Lead -

0.02 (0.01 –

0.02) - -

0.066

(0.003 –

0.970)

-

0.02 (0.01 –

0.04) - -

Lithium -

19.0 (2.56 –

37.4)

9.825 

(2.777 –

28.145)

-

53.85

(3.410 – 323)

23 

(1 – 53)

97.8 (20.2 –

315)

3 

(1 – 33) -

Magnesium 1,270 (630 –

1,750)

255

(149 – 755)

61 

(47 – 75)

632 

(17 – 2,550)

678

(40.8 – 2,020)

1,363 (27 –

3,712.98)

2,334 (797 –

3,140)

74

(1 – 2,394)

753 

(486 –

1,264)

Manganese 7 

(4 – 10.2)

0.86 (0.25 –

2.20)

2 

(2 – 3) -

2.825

(0.369 –

18.600)

30.33 (30.33 –

30.33)

19 

(5.6 – 68) - -

Mercury -

NC 

(ND – ND) - - 0.00024 - - - -

Molybdenum NC 

(ND – <0.2)

0.02 (0.02 –

0.03) - - - - - - -

Nickel -

0.04 (0.03 –

0.05) -

0.419

(0.068 –

0.769)

- - - -

Selenium -

0.03 (0.03 –

0.04) - - 0.004 - - - -
Appendix E – Produced Water Handling Supplemental Information 

E-29

Shale Tight Formation

Parameter Bakkena BarnettbFayettevillec Marcellus

Cotton 

Valley Groupf

Devonian 

Sandstoneg Mesaverdef Oswegof

States MT, ND TX AR PAd PA, WVeLA, TX PA

CO, NM, UT, 

WY OK

Silver - - - -

4 

(3 – 6) - - - -

Strontium 764 

(518 – 1,010)

529 (48 –

1,550)

27 

(14 – 49)

1,695 (0.6 –

8,460)

1,240

(0.580 –

8,020)

2,312 (39 –

9,770)

3,890 (404 –

13,100) - -

Thallium -

NC 

(ND – 0.14) - - 0.168 - - - -

Tin -

NC 

(ND – ND) - - - - - - -

Titanium -

0.02 (0.02 –

0.03) - - - - - - -

Zinc 7 

(2 – 11.3)

0.15 (0.10 –

0.36) - -

0.391

(0.087 – 247)

-

0.20 (0.03 –

1.26) - -

-, no value available; NC, not calculated; ND, not detected; BDL, below detection limit. Bolded italic numbers are medians. 

a Stepan et al. (2010). n = 3. Concentrations were calculated based on Stepan et al.'s raw data. 

b Hayes and Severin (2012a). n = 16. This data source reported concentrations without presentation of raw data. 

c Warner et al. (2013a). n = 6. Concentrations were calculated based on Warner et al.'s raw data. Both flowback and produced water included. 

d Barbot et al. (2013). n = 151 − 159. This data source reported concentrations without presentation of data. 

e Hayes (2009). n = 48. Concentrations were calculated based on Hayes's raw data. Both flowback and produced water included. Non-detects and contaminated blanks omitted. 

f Blondes et al. (2014). Cotton Valley Group, n = 2; Mesa Verde, n = 1 − 407; Oswego, n = 4 − 30. Concentrations were calculated based on raw data presented in the USGS 

National Produced Water Database v2.0. 

g Dresel and Rose (2010). n = 3 − 15. Concentrations were calculated based on Dresel and Rose's raw data.
Appendix E – Produced Water Handling Supplemental Information 

E-30

Table E-7. Reported concentrations (mg/L) of metals and metalloids from produced water 

from coalbed methane, presented as: average (minimum-maximum). 

Parameter Black Warriora Powder Riverb RatonbSan Juanb

States AL, MS MT, WY CO, NM AZ, CO, NM, UT

Aluminum 0.037 (0 – 0.099) 0.018 (BDL – 0.124) 0.193 (BDL – 2,900) 0.069 (BDL – 0.546)

Antimony 0.006 (0.00 – 0.022) BDL (BDL – BDL) BDL (BDL – BDL) BDL (BDL – BDL)

Arsenic 0.002 (0.0 – 0.085) 0.001 (BDL – 0.004) 0.010 (BD – 0.060) 0.001 (BDL – 0.020)

Barium 45.540 (0.136 – 352) 0.61 (0.14 – 2.47) 1.67 (BDL – 27.40) 10.80 (BDL – 74.0)

Beryllium 0.0 (0.0 – 0.008) BDL (BDL – BDL) BDL (BDL – BDL) BDL (BDL – BDL)

Boron 0.185 (0 – 0.541) 0.17 (BDL – 0.39) 0.36 (BDL – 4.70) 1.30 (0.21 – 3.45)

Cadmium 0.001 (0.00 – 0.015) BDL (BDL – 0.002) 0.002 (BDL – 0.003) 0.002 (BDL – 0.006)

Calcium 218 (0 – 1,640) 32.09 (2.00 – 154.0) 14.47 (0.81 – 269.0) 53.29 (1.00 – 5,530)

Cesium 0.011 (0.0 – 0.072) - - -

Chromium 0.002 (0.0 – 0.351) 0.012 (BDL – 0.250) 0.105 (BDL – 3.710) 0.002 (BDL – 0.023)

Cobalt 0.023 (0.00 – 0.162) BDL (BDL – BDL) 0.001 (BDL – 0.018) 0.001 (BDL – 0.017)

Copper 0.001 (0.0 – 0.098) 0.078 (BDL – 1.505) 0.091 (BDL – 4.600) 0.058 (BDL – 0.706)

Iron 8.956 (0.045 – 93.100) 1.55 (BDL – 190.0) 7.18 (0.09 – 95.90) 6.20 (BDL – 258.0)

Lead 0.008 (0.00 – 0.250) BDL (BDL – BDL) 0.023 (BDL – 0.233) 0.023 (BDL – 0.390)

Lithium 1.157 (0 – 8.940) 0.13 (BDL – 0.34) 0.32 (0.01 – 1.00) 1.61 (0.21 – 4.73)

Magnesium 68.12 (0.18 – 414.00) 14.66 (BDL – 95.00) 3.31 (0.10 – 56.10) 15.45 (BDL – 511.0)

Manganese 0.245 (0.006 – 4.840) 0.02 (BDL – 0.16) 0.11 (0.01 – 2.00) 0.19 (BDL – 1.34)

Mercury 0.000 (0.000 – 0.000) - - -

Molybdenum 0.002 (0 – 0.083) 0.005 (BDL – 0.029) 0.002 (BDL – 0.035) 0.020 (BDL – 0.040)

Nickel 0.015 (0.0 – 0.358) 0.141 (BDL – 2.61) 0.015 (0.004 – 0.11) 0.020 (BDL – 0.13)

Potassium 12.02 (0.46 – 74.00) 11.95 (BDL – 44.00) 6.37 (BDL – 29.40) 26.99 (BDL – 970.0)

Rubidium 0.013 (0.0 – 0.114) - - -

Selenium 0.002 (0.00 – 0.063) 0.006 (BDL – 0.046) 0.017 (BDL – 0.100) 0.018 (BDL – 0.067)

Silver 0.015 (0.0 – 0.565) 0.003 (0.003 – 0.003) 0.015 (BDL – 0.140) BDL (BDL – BDL)

Sodium 4,353 (126 – 16,700) 356 (12 – 1,170) 989 (95 – 5,260) 1,610 (36 – 7,834)

Strontium 11.354 (0.015 –

142.000) 0.60 (0.10 – 1.83) 5.87 (BDL – 47.90) 5.36 (BDL – 27.00)

Thallium - - - -
Appendix E – Produced Water Handling Supplemental Information 

E-31

Parameter Black Warriora Powder Riverb RatonbSan Juanb

States AL, MS MT, WY CO, NM AZ, CO, NM, UT

Tin 0.00 (0.00 – 0.009) 0.006 (BDL – 0.028) 0.008 (BDL – 0.021) 0.017 (BDL – 0.039)

Titanium 0.003 (0.0 – 0.045) BDL (BDL – 0.002) BDL (BDL – 0.002) 0.004 (BDL – 0.020)

Vanadium 0.001 (0.0 – 0.039) BDL (BDL – BDL) 0.001 (BDL – 0.013) BDL (BDL – BDL)

Zinc 0.024 (0.0 – 0.278) 0.063 (BDL – 0.390) 0.083 (0.010 – 3.900) 0.047 (0.005 –

0.263)

-, no value available; BDL, below detection limit.

a DOE (2014). n = 206. Concentrations were calculated based on the authors’ raw data.

b Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without 

presentation of raw data. 

E.3.4. Naturally Occurring Radioactive Material (NORM) and Technically Enhanced Naturally 

Occurring Radioactive Material (TENORM) 

E.3.4.1. Produced Water Levels of TENORM 

Background data on TENORM in the Marcellus Shale and Devonian sandstones are given in Table 

E-8. 

E.3.4.2. Mobilization of Naturally Occurring Radioactive Material 

In oil and gas production in both conventional and unconventional reservoirs, radionuclides native 

to the targeted formation return to the surface with produced water. The principal radionuclides 

found in oil and gas produced waters include radium-226 of the uranium-238 decay series and 

radium-228 of the thorium-232 decay series (White, 1992). Levels of TENORM in produced water 

are controlled by geologic and geochemical interactions between injected and formation fluids, and 

the targeted formation (Bank, 2011). Mechanisms controlling NORM mobilization into produced 

water include (1) the TENORM content of the targeted formation; (2) factors governing the release 

of radionuclides, particularly radium, from the reservoir matrix; and (3) the geochemistry of the 

produced water (Choppin, 2007, 2006; Fisher, 1998). 

Elevated uranium levels in formation solids have been used to identify potential areas of natural 

gas production for decades (Fertl and Chilingar, 1988). Marine black shales are estimated to contain 

3 − 250 ppm uranium depending on depositional conditions (USGS, 1961). Shales that bear 

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). 

Bank et al. (2012) identified Marcellus samples with uranium ranging from 4 − 72 ppm, with an 

average of 30 ppm. Chermak and Schreiber (2014) compiled mineralogy and trace element data 

available in the literature for nine U.S. hydrocarbon-producing shales. In this combined data set, 

uranium levels among different shale plays were found to vary over three orders of magnitude, 

with samples of the Utica Shale containing approximately 0 − 5 ppm uranium and samples of the 

Woodford Shale containing uranium in the several-hundred-ppm range. 
Appendix E – Produced Water Handling Supplemental Information 

E-32

Table E-8. Reported concentrations (in pCi/L) of radioactive constituents in produced water in unconventional reservoirs 

(including shale and tight sandstones), presented as: average (minimum-maximum) or median (minimum-maximum). 

Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians. 

Parameter Marcellus

Devonian 

Sandstonea

PA NORM Study (PA DEP, 2015)

States NY, PAbFracturing FluidcFlowbackd

Produced Water, 

Conventional 

Reservoirse

Produced Water, 

Unconventional 

Reservoirsf WVg PA

Gross alpha

6,845

(ND – 123,000)

5,020 

(0.695 – 54,100)

10,700

(288 – 71,000) 1,835 (465 – 2,570)

11,300

(2,400 – 41,700)

5,866 

(1.84 – 20,920) -

Gross beta

1,170

(ND – 12,000)

1,010 

(0.815 – 14,900)

2,400

(742 – 21,300) 909 (402 – 1,140) 3,445 (1,500 – 7,600)

1,172 

(9.6 – 4,664) -

Radium-226

1,869

(ND – 16,920)

2,160 

(64.0 – 21,000)

4,500

(551 – 25,500) 243 (81 – 819) 6,300 (1,700 – 26,600)

358 

(15.4 – 1,194)

2,367

(200 – 5,000)

Radium-228 557 (ND – 2,589)

218 

(4.5 – 1,640) 633 (248 – 1,740) 128 (26 – 896) 941 (366 – 1,900) 94.6 (4.99 – 216) -

Total Radium

2,530

(0.192 – 18,045) - 371 (107 – 1,715) 7,180 (2,336 – 28,500) -

Potassium40

283

(10.5 – 456) 461 (88.5 – 2,630) 62.44 (nd – 221)

Thorium230 2.13 (0 – 9.37)

Thorium232 0.07 (0 – 0.38)

Uranium235 1 (ND – 20) - - - -

Uranium238 42 (ND – 497) - - - 0.34 -

n/a, not applicable; -, no value available; BDL, below detection limit. Bolded italic numbers are medians. 

a Dresel and Rose (2010). n = 3. Concentrations presented were calculated based on Dresel and Rose's raw data. 

b Rowan et al. (2011). n = 51 total radium; n = 30 gross beta. Concentrations presented were calculated based on Rowan et al.'s raw data for Marcellus samples. Uranium data 

from Barbot et al. (2013) n = 14. 

c PA DEP (2015). n = 11. Data reported in Table 3-13 of the referenced paper. 

d PA DEP (2015). n = 9. Data reported in Table 3-14 of the referenced paper. 

e PA DEP (2015). n = 9. Values calculated from Table 3-15 for unfiltered samples of the referenced paper. 

f PA DEP (2015). n = 4. Values calculated from Table 3-15 for unfiltered samples of the referenced paper. 

g Ziemkiewicz and He (2015). n = 5. Data reported in Table 1 of the referenced paper.
Appendix E – Produced Water Handling Supplemental Information 

E-33

Vine (1956) reported that the principal uranium-bearing coal deposits of the United States are 

found in Cretaceous and Tertiary formations in the northern Great Plains and Rocky Mountains; in 

some areas of the West, coal deposits have been found with uranium concentrations in the range of 

thousands of ppm or greater. In contrast, most Mississippian, Pennsylvanian, and Permian coals in 

the north-central and eastern United States contain less than 10 ppm uranium, rarely containing 

50 ppm or more. 

Organic-rich shales and coals are enriched in uranium, thorium, and other trace metals in 

concentrations above those seen in typical shales or sedimentary rocks (Diehl et al., 2004; USGS, 

1997; Wignall and Myers, 1988; Tourtelot, 1979; Vine and Tourtelot, 1970). Unlike shales and coals, 

sandstones are generally not organic-rich source rocks themselves. Instead, hydrocarbons migrate 

into these formations over long periods of time (Clark and Veil, 2009). Since TENORM and organic 

contents are typically positively correlated due to the original, reduced depositional environment 

(Fertl and Chilingar, 1988), it is unlikely that sandstones would be enriched in TENORM to the same 

extent as oil- and gas-bearing shales and coals. Therefore, concern related to TENORM within 

produced water is focused on operations targeting shales and coalbeds. 

Radium is most soluble and mobile in chloride-rich, high-TDS, reducing environments (Sturchio et 

al., 2001; Zapecza and Szabo, 1988; Langmuir and Riese, 1985). In formation fluids with high TDS, 

calcium, potassium, magnesium, and sodium compete with dissolved radium for sorption sites, 

limiting radium sorption onto solids and allowing it to accumulate in solution at higher 

concentrations (Fisher, 1998; Webster et al., 1995). The positive correlation between TDS and 

radium is well established and TDS is a useful indicator of radium and TENORM activity within 

produced water, especially in lithologically homogenous reservoirs (Rowan et al., 2011; Sturchio et 

al., 2001; Fisher, 1998; Kraemer and Reid, 1984). 

Uranium and thorium are poorly soluble under reducing conditions and are therefore more 

concentrated in formation solids than in solution (Fisher, 1998; Kraemer and Reid, 1984; Langmuir 

and Herman, 1980). However, because uranium becomes more soluble in oxidizing environments, 

the introduction of relatively oxygen-rich fracturing fluids may promote the temporary 

mobilization of uranium during hydraulic fracturing and early flowback. In addition, the physical 

act of hydraulic fracturing creates fresh fractures and exposes organic-rich and highly reduced 

surfaces from which radionuclides could be released from the rock into formation fluids. 

Produced water geochemistry determines, in part, the fate of subsurface radionuclides, particularly 

radium. Radium may remain in the host mineral or it may be released into formation fluids, where 

it can remain in solution as the dissolved Ra2+ ion, be adsorbed onto oxide grain coatings or clay 

particles by ion exchange, substitute for other cations during the precipitation of minerals, or form 

complexes with chloride, sulfate, and carbonate ions (Rowan et al., 2011; Sturchio et al., 2001; 

Langmuir and Riese, 1985). Uranium- and thorium-containing materials with a small grain size, a 

large surface-to-volume ratio, and the presence of uranium and thorium near grain surfaces 

promote the escape of radium into formation fluids. Vinson et al. (2009) point to alpha decay along 

fracture surfaces as a primary control on radium mobilization in crystalline bedrock aquifers. 
Appendix E – Produced Water Handling Supplemental Information 

E-34

Radium may also occur in formation fluids due to other processes, such as the decay of dissolved 

parent isotopes and adsorption-desorption reactions on formation surfaces (Sturchio et al., 2001). 

Preliminary results from fluid-rock interaction studies (Bank, 2011) indicate that a significant 

percentage of uranium in the Marcellus Shale may be subject to mobilization by hydrochloric acid, 

which is used as a fracturing fluid additive. More complete understanding these processes will 

determine the extent to which such processes might influence the TENORM content of flowback 

and produced water. 

E.3.5. Organics 

Background data on organics in seven formations is given in Table E-9. Classes of organic 

compounds identified in produced water are given in Table E-10. Tables H-4 and H-5 give the entire 

list of chemicals identified as components of produced water. Along with the organic chemicals 

appearing in Table E-9, Table E-10a presents additional organic chemicals with measured 

concentrations in produced water. Table E-11 presents data from two studies of the Marcellus 

Shale. Table E-12 presents data from CBM produced water, while Table E-13 presents data on 

organics identified in shale and CBM water. 

Several classes of naturally occurring organic chemicals are present in produced waters in 

conventional and unconventional reservoirs, with large concentration ranges (Lee and Neff, 2011). 

These organic classes include total organic carbon (TOC); saturated hydrocarbons; BTEX (benzene, 

toluene, ethylbenzene, and xylenes); and polyaromatic hydrocarbons (PAHs) (Table E-10). While 

TOC concentrations in produced water are detected at the milligrams to grams per liter level, 

concentrations of individual organic compounds are typically detected at the micrograms to 

milligrams per liter level. 

TOC indicates the level of dissolved and undissolved organics in produced water, including nonvolatile and volatile organics (Acharya et al., 2011). TOC concentrations in conventional produced 

water vary widely from less than 0.1 mg/L to more than 11,000 mg/L. Average TOC concentrations 

in produced water in unconventional reservoirs range from less than 2.00 mg/L in the Raton CBM 

basin to approximately 200 mg/L in the Cotton Valley Group sandstones, although individual 

measurements have exceeded 5,000 mg/L in the Marcellus Shale (Table E-9).

Dissolved organic carbon (DOC) is a general indicator of organic loading and is the fraction of 

organic carbon available for complexing with metals and supporting microbial growth. DOC values 

in produced water in unconventional reservoirs range from less than 1.50 mg/L (average) in the 

Raton Basin to more than 115 mg/L (median) in the Marcellus Shale (Table E-9). Individual DOC 

concentrations in the Marcellus Shale produced water approach 6,000 mg/L. For comparison, DOC 

levels in fresh water systems are typically below 5 mg/L. 

Biochemical oxygen demand (BOD) is a conventional pollutant under the U.S. Clean Water Act. It is 

an indirect measure of biodegradable organics in produced water and an estimate of the oxygen 

demand on a receiving water. Median BOD levels for Barnett and Marcellus Shales produced water 

exceed 30 mg/L, and both reported maximum concentrations exceeding 12,000 mg/L (Table E-9). 
Appendix E – Produced Water Handling Supplemental Information 

E-35

In some circumstances wide variation in produced water median BOD levels may be reflective of 

flowback reuse in fracturing fluids (Hayes, 2009). 

Lastly, BTEX is associated with petroleum. Benzene was found in produced water from several 

basins: average produced water benzene concentration from the Barnett Shale was 680 μg/L, from 

the Marcellus Shale was 220 μg/L (median), and from the San Juan Basin was 150 μg/L (Table E-9). 

Total BTEX concentrations for conventional produced water vary widely from less than 100 μg/L to 

nearly 580,000 μg/L. For comparison, average total BTEX concentrations in produced water in

unconventional reservoirs range from 20 μg/L in the Raton Basin to nearly 3,000 μg/L in the 

Marcellus (Table E-9). From these data, average total BTEX levels in shale produced water are one 

to two orders of magnitude higher than those in CBM produced water. 

In addition to BTEX, a variety of volatile and semi-volatile organic compounds have been detected 

in shale and coalbed produced water. Shale produced water contains naphthalene, alkylated 

toluenes, and methylated aromatics in the form of several benzene and phenol compounds, as 

shown in Table E-11. Like BTEX, naphthalene, methylated phenols, and acetophenone are 

associated with petroleum. Detected shale produced water organics such as acetone, 2-butanone, 

carbon disulfide, and pyridine are potential remnants of additives used as friction reducers or 

industrial solvents (Hayes, 2009). 

Hayes (2009) characterized the content of Marcellus Shale produced water including organics 

(Table E-11). The author tested for the majority of VOCs and SVOCs, pesticides and PCBs, based on 

the recommendation of the Pennsylvania and West Virginia Departments of Environmental 

Protection. Less than 0.5% of VOCs and 0.03% of SVOCs in the produced water were detected above 

1 mg/L. More than 96% of VOCs, 98% of SVOCs, and virtually all pesticides and PCBs were at 

nondetectable levels. 

Orem et al. (2014) provided a list of classes of organic compounds in coalbed methane and gas shale 

produced and formation water (Table E-10). As described in the main text of Chapter 7, these 

included aromatics, polyaromatic hydrocarbons, heterocyclic compounds, aromatic amines, 

phenols, phthalates, aliphatic alcohols, fatty acids and nonaromatic compounds. Many of these are 

naturally occurring components of petroleum hydrocarbons, but the list also contains chemicals 

that have been used as hydraulic fracturing fluid additives, namely, hexahydro-1,3,5-trimethyl1,3,5-triazine-2-thione (a biocide), ethylene glycol, dibutyl phthalate, quinoline, and naphthalene, to 

list a few. See Table H-2.

The organic profile of CBM produced water is characterized by high levels of aromatic and 

halogenated compounds compared to other produced water in unconventional reservoirs 

(Sirivedhin and Dallbauman, 2004). PAHs and phenols are the most common organic compounds 

found in coalbed produced water. Produced water from coalbeds in the Black Warrior Basin mainly 

contains phenols, multiple naphthalic PAHs, and various decanoic and decenoic fatty acids (Table 

E-12). CBM-associated organics are also known to include biphenyls, alkyl aromatics,

hydroxypyridines, aromatic amines, and nitrogen-, oxygen-, and sulfur-bearing heterocyclics (Orem

et al., 2014; Pashin et al., 2014; Benko and Drewes, 2008; Orem et al., 2007; Fisher and Santamaria,

2002).
Appendix E – Produced Water Handling Supplemental Information 

E-36

Table E-9. Concentrations of select organic parameters in produced water from unconventional reservoirs (including shale, a tight 

formation, and coalbed methane), presented as: average (minimum-maximum) or median (minimum-maximum). 

Both averages and medians are reported because this table summarizes published information and authors differed in their use of averages or medians. 

Shale

Tight 

Formation Coal

Parameter Unit Barnetta Marcellus

Cotton Valley 

Groupd

Powder 

Rivere RatoneSan Juane Black Warriorf

States n/a TX PAb PA, WVcLA, TX MT, WY CO, NM

AZ, CO, NM, 

UT AL, MS

TOC mg/L 9.75

(6.2 – 36.2)

160 

(1.2 –

1,530)

89.2

(1.2 – 5680)

198

(184 – 212)

3.52 (2.07 –

6.57)

1.74 (0.25 –

13.00)

2.91 (0.95 –

9.36)

6.03 (0.00 –

103.00)

DOC mg/L 11.2

(5.5 – 65.3)

117

(3.3 –

5,960)

-

3.18 (1.09 –

8.04)

1.26 (0.30 –

8.54)

3.21 (0.89 –

11.41)

3.37 (0.53 –

61.41)

BOD mg/L 582

(101 – 2,120)

-

141

(2.8 –

12,400)

- - - - -

Oil and grease mg/L 163.5

(88.2 – 1,430)

74

(5 – 802)

16.9

(4.7 – 802)

- -

9.10 (0.60 –

17.6) - -

Benzene μg/L 680 

(49 – 5,300) -

220

(5.8 –

2,000)

- -

4.7 (BDL –

220.0)

149.7 (BDL –

500.0) -

Toluene μg/L 760 

(79 – 8,100) -

540

(5.1 –

6,200)

- - 4.7 (BDL – 78.0) 1.7 

(BDL – 6.2) -

Ethylbenzene μg/L 29 

(2.2 – 670) -

42

(7.6 – 650) - - 0.8 (BDL – 18.0) 10.5 (BDL –24.0) -

Xylenes μg/L 360 

(43 – 1,400) -

300 (15 –

6,500) - -

9.9 (BDL –

190.0)

121.2 (BDL –

327.0) -
Appendix E – Produced Water Handling Supplemental Information 

E-37

Shale

Tight 

Formation Coal

Parameter Unit Barnetta Marcellus

Cotton Valley 

Groupd

Powder 

Rivere RatoneSan Juane Black Warriorf

States n/a TX PAb PA, WVcLA, TX MT, WY CO, NM

AZ, CO, NM, 

UT AL, MS

Average total 

BTEXg μg/L 1,829 2,910 1,102 - - 20.1 283.1 -

n/a, not applicable; -, no value available; BDL, below detection limit. Bolded italic numbers are medians. 

a Hayes and Severin (2012a). n = 16. This data source reported concentrations without presentation of raw data. 

b Barbot et al. (2013). n = 55 for TOC; n = 62 for oil and grease; no presentation of raw data. 

c Hayes (2009). n = 13-67. Concentrations were calculated based on Hayes’ raw data. Both flowback and produced water included. Non-detects and contaminated blanks 

omitted. 

d Blondes et al. (2014). n = 2. Concentrations were calculated based on raw data presented in the USGS National Produced Water Database v2.0. 

e Dahm et al. (2011). Powder River, n = 31; Raton, n = 40; San Juan, n = 20. This data source reported concentrations without presentation of raw data. 

fDOE (2014). n = 206. Concentrations were calculated based on the authors’ raw data.

g Average total BTEX was calculated by summing the average/median concentrations of benzene, toluene, ethylbenzene, and xylenes for a unique formation or basin. Minimum 

to maximum ranges were not calculated due to inaccessible raw data.
Appendix E – Produced Water Handling Supplemental Information 

E-38

Table E-10. Classes of organic compounds and representative example compounds found in 

coal bed methane and gas shale formations (Orem et al., 2014). 

Compounds also identified as having been used in hydraulic fracturing fluids (Table H-2) are given in bold and italic 

type. 

Extractable hydrocarbons identified in CBM and shale produced and formation water

Type Location Compound classes Representative example compounds

CBM Powder River Basin

Wyoming

PAHs Dimethylnaphthalene 

tetramethylphenanthrene 

phenanthrenone 

pyrene

Heterocyclic 

compounds

Benzisothiazole 

3,4-dihydro1,9(2H,10H)Acridinedione 

2(3H)-Benzothiazolone

Aromatic amines Dioctyldiphenylamine 

diphenylamine 

2-methyl-N-phenyl Benzenamine

Phenols Nonylphenols 

4,40-(1-methylethylidene)bis-phenol 

methoxy-methylphenol

Other aromatics Trimethyl benzene 

2,4-dimethyl-1-(1-methylpropyl)-benzene

Phthalates Diethylphthalate 

dibutyl phthalate 

benzyl butyl phthalate 

didecyl phthalate

Fatty acids Dodecanoic acid 

n-hexadecanoic acid 

tetradecanoic acid

Nonaromatic 

compounds

Kaur-16-ene (a diterpene) 

2-[2-[4-(1,1,3,3-

tetramethylbutyl)phenoxy]ethoxy]-ethanol

Tongue River Basin

Montana

PAHs 1-Methyl-7-(1-methylethyl)phenanthrene 

1-methylnaphthalene 

2-methylnaphthalene

Heterocyclic 

compounds

Benzothiazole

Aromatic amines Diethyltoluamide

Phenols 2,4-Bis(1,1-dimethylethyl)phenol

p-tert-butyl-phenol

Other aromatics 1-Ethyl-2,4-dimethyl-benzene
Appendix E – Produced Water Handling Supplemental Information 

E-39

Extractable hydrocarbons identified in CBM and shale produced and formation water

Type Location Compound classes Representative example compounds

CBM, cont. Tongue River Basin

Montana, cont.

Phthalates Alkyl phthalates

Fatty acids Tetradecanoic acid 

octadecanoic acid

Nonaromatic 

compounds

Pentadecane 

pentacosane

Black Warrior 

Basin Alabama 

PAHs Methylnaphthalene 

dimethylnaphthalene

Heterocyclic 

compounds

Benzothiazole 

dibenzothiophene 

caprolactam 

quinoline 

isoquinoline

Phenols Dimethylphenol 

4-(1,1,3,3-tetramethylbutyl)-phenol 

2,4-bis(1,1-dimethylethyl)-phenol

Other aromatics Acetophenone 

biphenyl 

methylbiphenyl

Phthalates Dioctyl phthalate 

dibutyl phthalate

Fatty acids Hexadecanoic acid

Nonaromatic 

compounds

Alkyl phosphates

Illinois Basin

Illinois

PAHs Naphthalene 

methylnaphthalene 

methylphenanthrene

Heterocyclic 

compounds

Benzothiazole

Phenols 2,4-Bis(1,1-dimethylethyl)-phenol 

Other aromatics 1-(3-Methylbutyl)-2,3,4-trimethyl-benzene

Phthalates Alkyl phthalates

Fatty acids Hexadecanoic acid 

octadecanoic acid

Nonaromatic 

compounds

C23–C36 alkanes 

2,6-di(tert-butyl)-4-hydroxy-4-methyl-2,5-

cyclohexadien-1-on
Appendix E – Produced Water Handling Supplemental Information 

E-40

Extractable hydrocarbons identified in CBM and shale produced and formation water

Type Location Compound classes Representative example compounds

CBM, cont. Williston Basin

North Dakota

PAHs Naphthalene 

methylnaphthalene 

methylphenanthrene

Heterocyclic 

compounds 

Benzothiazole

Phenols Bis(1,1-dimethylethyl)-phenol 

trichlorophenol 

4,4′-(1-methylethylidene)bis-phenol

Other aromatics Benzophenone

Phthalates Alkyl phthalates 

benzyl butyl phthalate

Fatty acids C12, C14, C16, C18 fatty acids

Nonaromatic 

compounds 

C23–C35 alkanes 

alkyl phosphates 

2,6-bis(1,1-dimthylethyl)-2,5-cyclohexadiene-1,4-

dione

Shale gas Marcellus Shale

Pennsylvania

PAHs Decahydro-4,4,8,9,10-pentamethylnaphthalene

Heterocyclic 

compounds 

Hexahydro-1,3,5-trimethyl-1,3,5-triazine-2-thione

(a biocide)

Aliphatic alcohols Ethylene glycol 

diethylene glycol monododecyl ether 

triethylene glycol monodocecyl ether

Other aromatics (1-Methoxyethyl)-benzene

Phthalates Di-n-octyl phthalate

Fatty acids C12, C14, C16, C18 fatty acids

Nonaromatic 

compounds 

C11–C37 alkanes/alkenes

2,2,4-trimethyl-1,3-pentanediol 

tetramethylbutanedinitrile

New Albany Shale

Indiana and Kentucky

PAHs 1,2,3,4-Tetrahydro-naphthalene 

naphthalene 

methylphenanthrene 

pyrene 

perylene

Heterocyclic 

compounds 

Benzothiazole 

trimethyl-piperdine 

quinoline 

quinindoline
Appendix E – Produced Water Handling Supplemental Information 

E-41

Extractable hydrocarbons identified in CBM and shale produced and formation water

Type Location Compound classes Representative example compounds

Shale gas, cont. New Albany Shale

Indiana and 

Kentucky, cont.

Aromatic amines 3,3′-5,5′-Tetramethyl-[1,1′-biphenyl]-4,4′-diamine

Phenols Bis(1,1-dimethylethyl)-phenol 

tert-butyl-phenol 

bis-(1,1-dimethylethyl)-phenol

Other aromatics Triphenyl phosphate

methylbiphenyl 

octylphenyl ethoxylate

Phthalates Alkyl phthalates

Fatty acids Dodecanoic acid 

tetradecanoic acid 

octadecanoic acid

Nonaromatic 

compounds

2-(2-Butoxyethoxy)ethanol
Appendix E – Produced Water Handling Supplemental Information 

E-42

Table E-11. Reported concentrations (μg/L) of organic constituents in produced water for two 

shale formations, presented as: average (minimum-maximum) or median (minimummaximum). 

Both averages and medians are reported because this table summarizes published information and authors 

differed in their use of averages or medians. 

Parameter Barnetta Marcellusb

States TX MD, NY, OH, PA, VA, WY

Acetone 145 (27 – 540) 83 (14 – 5,800)

Carbon disulfide - 400 (19 – 7,300)

Chloroform - 28

Isopropylbenzene 35 (0.8 – 69) 120 (86 – 160)

Naphthalene 238 (4.8 – 3,100) 195 (14 – 1,400)

Phenolic compounds 119.65 (9.3 – 230) -

1,2,4-Trimethylbenzene 173 (6.9 – 1,200) 66.5 (7.7 – 4,000)

1,3,5-Trimethylbenzene 59 (6.4 – 300) 33 (5.2 – 1,900)

1,2-Diphenylhydrazine 4.2 (0.5 – 7.8) -

1,4-Dioxane 6.5 (3.1 – 12) -

2-Methylnaphthalene 1,362 (5.4 – 20,000) 3.4 (2 – 120)

2-Methylphenol 28.3 (5.8 – 76) 13 (11 – 15)

2,4-Dichlorophenol (ND – 15) -

2,4-Dimethylphenol 14.5 (8.3 – 21) 12

3-Methylphenol and 

4-Methylphenol 41 (7.8 – 100) 11.5 (0.35 – 16)

Acetophenone (ND – 4.6) 13 (10 – 22)

Benzidine (ND – 35) -

Benzo(a)anthracene (ND – 17.0) -

Benzo(a)pyrene (ND – 130.0) 6.7

Benzo(b)fluoranthene 42.2 (0.5 – 84.0) 10

Benzo(g,h,i)perylene 42.3 (0.7 – 84.0) 6.9

Benzo(k)fluoranthene 32.8 (0.6 – 65.0) 5.9

Benzyl alcohol 81.5 (14.0 – 200) 41 (17 – 750)

Bis(2-Ethylhexyl) phthalate 210 (4.8 – 490) 20 (9.6 – 870)

Butyl benzyl phthalate 34.3 (1.9 – 110) -
Appendix E – Produced Water Handling Supplemental Information 

E-43

Parameter Barnetta Marcellusb

States TX MD, NY, OH, PA, VA, WY

Chrysene 120 (0.57 – 240) -

Di-n-octyl phthalate (ND – 70) 15

Di-n-butyl phthalate 41 (1.5 – 120) 14 (11 – 130)

Dibenz(a,h)anthracene 77 (3.2 – 150) 3.2 (2.3 – 11)

Diphenylamine 5.3 (0.6 – 10.0) -

Fluoranthene (ND – 0.18) 6.1

Fluorene 0.8 (0.46 – 1.3) 8.4

Indeno(1,2,3-cd)pyrene 71 (2.9 – 140) 3.1 (2.4 – 9.5)

N-Nitrosodiphenylamine 8.9 (7.8 – 10) 2.7

N-Nitrosomethylethylamine (ND – 410) -

Phenanthrene 107 (0.52 – 1,400) 9.75 (3 – 22)

Phenol 63 (17 – 93) 10 (2.4 – 21)

Pyrene 0.2 (ND – 0.18) 13

Pyridine 413 (100 – 670) 250 (10 – 2,600)

-, no value available; ND, not detected.

a Hayes and Severin (2012a). n = 16. Data from days 1 – 23 of flowback. This data source reported concentrations without 

presentation of raw data. 

b Hayes (2009). n = 1 – 35. Data from days 1 – 90 of flowback. Concentrations were calculated from Hayes’ raw data. Nondetects and contaminated blanks omitted. 
Appendix E – Produced Water Handling Supplemental Information 

E-44

Table E-12. Reported concentrations of organic constituents in 65 samples of produced water 

from the Black Warrior CBM Basin (Alabama and Mississippi), presented as: average 

(minimum-maximum). 

Parameter Number of observations Concentration (μg/L)a

Benzothiazole 45 0.25 (0.01 – 3.04)

Caprolactam 10 0.75 (0.02 – 2.39)

Cyclic octaatomic sulfur 29 1.06 (0.10 – 9.63)

Dimethyl-naphthalene 39 0.79 (0.01 – 9.51)

Dioctyl phthalate 57 0.21 (0.01 – 2.30)

Dodecanoic acid 30 1.13 (0.67 – 2.52)

Hexadecanoic acid 50 1.58 (1.17 – 3.02)

Hexadecenoic acid 25 1.69 (1.13 – 8.37)

Methyl-biphenyl 18 0.25 (0.01 – 2.13)

Methyl-naphthalene 52 0.77 (0.01 – 15.55)

Methyl-quinoline 31 0.96 (0.03 – 3.75)

Naphthalene 49 0.41 (0.01 – 6.57)

Octadecanoic acid 32 1.95 (1.62 – 3.73)

Octadecenoic acid 29 1.87 (1.60 – 3.47)

Phenol, 2,4-bis(1,1-dimethyl) 21 0.45 (0.01 – 4.94)

Phenol, 4-(1,1,3,3-tetramethyl) 17 1.65 (0.01 – 18.34)

Phenolic compounds - 19.06 (ND – 192.00)

Tetradecanoic acid 53 1.51 (0.94 – 5.32)

Tributyl phosphate 23 0.26 (0.01 – 2.66)

Trimethyl-naphthalene 23 0.65 (0.01 – 4.49)

Triphenyl phosphate 6 1.18 (0.01 – 6.77)

-, no value available.

a DOE (2014). Concentrations were calculated based on the authors’ raw data. 
Appendix E – Produced Water Handling Supplemental Information 

E-45

Table E-13. Organic chemical concentrations reported from three specific studies of produced water (Khan et al., 2016; Lester et 

al., 2015; Orem et al., 2007). 

The complete list of chemicals which were identified in produced water are listed in Tables H-4 and H-5.

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

(Z)-9-Tricosene 0.98 C Orem et al. (2007)

1-(2-Hydroxy-5-methylphenyl)-

2-hexen-1-one

0.29 C Orem et al. (2007)

1,1-Dimethyl-1,2,3,4-

tetrahydro-7-isopropyl 

phenanthrene

0.19 0.68 C Orem et al. (2007)

1,2-Di-but-2-enyl-cyclohexane 0.77 C Orem et al. (2007)

1,2-Di-but-2-enylcyclohexanone0.09 C Orem et al. (2007)

1,4-[13C]-1,2,3,4-Tetrahydro-5-

naphthaleneamine

0.33 C Orem et al. (2007)

1,4-dioxane 60 C Lester et al. (2015)

1,6-Dimethyl-4(1-

methylethyl)naphthalene

0.01 0.32 C Orem et al. (2007)

1,7,11-

Trimethylcyclotetradecane

1.06 C Orem et al. (2007)

1,7,11-Trimethylcyclotetradecane0.47 C Orem et al. (2007)

1-1Methylenebis(4-methyl)-

benzene

0.09 0.11 C Orem et al. (2007)

15-Isobutyl-(13.α.H)-

isocopalane

1.75 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-46

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

17-Pentatriacontene 1 C Orem et al. (2007)

1-Allyl-3-methylindole-2-

carbaldehyde

0.49 C Orem et al. (2007)

1-Allyl-3-methylindole-2-

carbaldehyde

1.49 C Orem et al. (2007)

1-Butyl-2-ethyloctahydro-4,7-

epoxy

0.9 C Orem et al. (2007)

1-Chloro-octadecane 2.12 C Orem et al. (2007)

1-Docosene 2.33 C Orem et al. (2007)

1-Ethyl-9,10-anthracenedione 0.04 0.12 C Orem et al. (2007)

1-Hexacosene 2.04 C Orem et al. (2007)

1-Methyl-7-(1-

methylethyl)phenanthrene

0.02 3.19 C Orem et al. (2007)

1-Methyl-9H-fluorene 0.51 C Orem et al. (2007)

1-Nonadecene 2.15 C Orem et al. (2007)

2-(2-Butoxyethoxy)-ethanol 0.45 C Orem et al. (2007)

2(3H)-Benzothiazolone 0.04 3.9 C Orem et al. (2007)

2-(Methylthio)-benzothiazole 0.05 0.54 C Orem et al. (2007)

2,3',5-

Trimethyldiphenylmethane

0.04 0.05 C Orem et al. (2007)

2,3-Dihydro-1,1,2,3,3-

pentamethyl-1H-indene

0.45 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-47

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

2,4,6-Trimethyl-azulene 0.49 C Orem et al. (2007)

2,4-dimethylphenol 790 C Lester et al. (2015)

2,5-Cyclohexadiene-1,4-dione 0.01 0.08 C Orem et al. (2007)

2,6,10,14-Tetramethylhexadecane1.65 C Orem et al. (2007)

2,6,10-Trimethyl-dodecane 0.96 C Orem et al. (2007)

2,6-Bis(dimethylethyl)-2,5-

cyclohexadiene-1,4-dione

0.04 0.28 C Orem et al. (2007)

2,6-Bis(dimethylethyl)-phenol 0.31 C Orem et al. (2007)

2-[2-[4-(1,1,3,3-

Tetramethylbutyl)phenoxy]eth

oxy]-ethanol

0.08 1.34 C Orem et al. (2007)

22-Tricosenoic acid 0.43 C Orem et al. (2007)

28-Nor-17.α.(H)-hopane 1.26 C Orem et al. (2007)

28-Nor-17.α.(H)-hopane 0.84 C Orem et al. (2007)

2a,7a-(Epoxymethano)-2Hcyclobutyl0.33 C Orem et al. (2007)

2-Butanone 240 C Orem et al. (2007)

2-Dodecen-1-yl(-)succinic 

anhydride

1.16 C Orem et al. (2007)

2-Ethylhexyl diphenyl 

phosphate (Octicizer)

0.1 0.75 C Orem et al. (2007)

2-Mercaptobenzothiazole 0.89 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-48

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

2-Methyl-8-propyl-dodecane 0.52 C Orem et al. (2007)

2-methylnaphthalene 4 C Lester et al. (2015)

2-Methyl-nonadecane 2.58 C Orem et al. (2007)

2-Methyl-N-phenylbenzenamine0.41 3.53 C Orem et al. (2007)

2-methylphenol 150 C Lester et al. (2015)

2-Octadecyl-propane-1,3-diol 0.42 C Orem et al. (2007)

3&4 methylphenol 170 C Lester et al. (2015)

3-(4-Methoxyphenyl)-2-

ethylhexylester-2-propenoic 

acid

0.01 2.78 C Orem et al. (2007)

3-(4-Methoxyphenyl)-2-

propenoic acid

0.06 0.16 C Orem et al. (2007)

3-(Hexahydro-1H-azepin-1-yl)-

1,1-dioxide-1,2-benzisothiazole

0.66 C Orem et al. (2007)

3,4-Dihydro1,9(2H,10H)acridinedione0.02 1.35 C Orem et al. (2007)

3,5-Di-tetra-butyl-4-

hydroxybenzaldehyde

0.42 C Orem et al. (2007)

4-(1-Methyl-phenylethyl)-

phenol

1.18 C Orem et al. (2007)

4-(4-Ethylcyclohexyl)-

cyclohexene

1.66 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-49

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

4,40-(1-Methylethylidene)bisphenol<=16.17 C Orem et al. (2007)

4,4-Diacetyldiphenylmethane 0.37 C Orem et al. (2007)

4,6,8-Trimethyl-2-

propylazulene

0.4 C Orem et al. (2007)

4-Hydroxy-3-methoxybenzaldehyde4.31 C Orem et al. (2007)

4-Propyl-xanthen-9-one 0.03 0.07 C Orem et al. (2007)

5-(1,1-Dimethylethyl)-1Hindene0.03 0.1 C Orem et al. (2007)

5,6-

Azulenedimethanol,1,2,3,3a,8,

0.4 C Orem et al. (2007)

7-Bromomethyl-pentadec-7-

ene

2.77 C Orem et al. (2007)

7-Bromomethyl-pentadec-7-

ene

0.92 C Orem et al. (2007)

7-Ethenylphenanthrene 0.04 0.22 C Orem et al. (2007)

7-Tetradecyne 0.38 C Orem et al. (2007)

8-Hexadecyne 0.28 C Orem et al. (2007)

8-Isopropyl-2,5-dimethylterralin0.36 C Orem et al. (2007)

9,10-Dimethoxy-2,3-

dihydroanthracene

0.04 0.34 C Orem et al. (2007)

9H-Fluoren-9-ol 0.07 0.32 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-50

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

9-Methoxyfluorene 0.06 0.18 C Orem et al. (2007)

9-Methoxyfluorene 0.54 C Orem et al. (2007)

9-Phenyl-tetrahydro-1Hbenz[f]isoindol-1-one0.24 C Orem et al. (2007)

9-Phenyl-tetrahydro-1Hbenz[f]isoindol-1-one0.24 C Orem et al. (2007)

Acetone 16,000 S Lester et al. (2015)

Alkyl benzene 74,630 1,119,350 5,092,600 1,698,910 S Khan et al. (2016)

Alkyl naphthalene 380 1,460 4,200 1,180 S Khan et al. (2016)

Alkyl propo-benzene 9,340 61,900 209,150 67,220 S Khan et al. (2016)

Benzene 1,500 107,320 778,510 271,570 S Khan et al. (2016)

Benzenemethanol 0.33 C Orem et al. (2007)

Benzisothiazole derivative 0.06 0.32 C Orem et al. (2007)

Benzothiazole 0.51 14.27 C Orem et al. (2007)

Benzyl butyl phthalate 0.04 0.33 C Orem et al. (2007)

Biphenyl 0.16 0.3 C Orem et al. (2007)

Bis(2-ethylhexyl) phthalate 29 S Lester et al. (2015)

Bis(2-ethylhexyl)-hexanedioic 

acid

0.13 0.7 C Orem et al. (2007)

Bis-(octylphenyl)-amine 0.05 0.19 C Orem et al. (2007)

Butanoic acid, butyl ester 0.44 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-51

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

butyl benzyl phthalate 4.2 S Lester et al. (2015)

Caffeine 0.09 0.5 C Orem et al. (2007)

Chloro-benzene 20 100 350 110 S Khan et al. (2016)

Cholesterol 0.26 C Orem et al. (2007)

Cyclotriacontane 1.08 C Orem et al. (2007)

Dibutyl phthalate <=1.27 C Orem et al. (2007)

Didecyl phthalate <=7.23 C Orem et al. (2007)

Diethyl phthalate <=14.9 C Orem et al. (2007)

Dihydro-(-)-neocloven-(II) 0.1 1.04 C Orem et al. (2007)

Dihydro-1-methylphenanthrene 1.06 C Orem et al. (2007)

Dihydrophenanthrene 0.03 0.48 C Orem et al. (2007)

Dimethyl phthalate 0.11 0.28 C Orem et al. (2007)

15 S Lester et al. (2015)

Dimethyl-biphenyl 0.07 2.01 C Orem et al. (2007)

Dimethyl-ethylindene 0.02 0.07 C Orem et al. (2007)

Dimethylnaphthalene 0.01 1.44 C Orem et al. (2007)

Dimethylphenanthrene 0.62 1.49 C Orem et al. (2007)

Dimethylphenol 1.38 C Orem et al. (2007)

Dimethyltetracyclo[5.2.1.0(2,6)-

0(3,5)]decane

0.27 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-52

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

Di-n-octyl phthalate 0.58 4.63 C Orem et al. (2007)

Dioctyldiphenylamine 0.03 0.18 C Orem et al. (2007)

Diphenylamine 0.04 3.73 C Orem et al. (2007)

Diphenylmethane 0.01 0.43 C Orem et al. (2007)

Di-tetra-butyl-4-

hydroxbenzaldehyde

0.16 0.53 C Orem et al. (2007)

Docosane 1.94 C Orem et al. (2007)

Dodecanoic acid 1.33 1.7 C Orem et al. (2007)

Drometrizole 0.91 C Orem et al. (2007)

Ethylbenzene 2,010 72,610 399,840 134,630 S Khan et al. (2016)

Ethyl dimethyl azulene 0.46 C Orem et al. (2007)

Ethyl phenylmethyl benzene 0.1 C Orem et al. (2007)

Ethyl-cyclodocosane 1.54 C Orem et al. (2007)

Ethyl-cyclodocosane 0.65 C Orem et al. (2007)

Ethyl-tetrahydronaphthalene 0.46 C Orem et al. (2007)

Fluorene 0.05 0.24 C Orem et al. (2007)

Heptacosane 0.95 C Orem et al. (2007)

Hexacosane 1.73 C Orem et al. (2007)

Isopropyl myristate 1.79 C Orem et al. (2007)

Kaur-16-ene 0.06 1.36 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-53

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

Methoxyanthracene 0.04 0.22 C Orem et al. (2007)

Methoxynaphthalene 

derivative

0.04 0.25 C Orem et al. (2007)

Methyl-(2,5-dimethoxyphenol)-

methanoate

0.31 C Orem et al. (2007)

Methyl(Z)-3,3-diphenyl-4-

hexenoate

2 C Orem et al. (2007)

Methyl-2-octylcyclopropene-1-

octane

0.38 C Orem et al. (2007)

Methyl-2-quinolinecarboxylic 

acid

6.65 C Orem et al. (2007)

Methyl-9H-fluorene 0.52 1.16 C Orem et al. (2007)

Methylanthracene 0.07 0.48 C Orem et al. (2007)

Methyl-biphenyl 0.15 1 C Orem et al. (2007)

Methylethylnaphthalene 0.55 C Orem et al. (2007)

Methylnaphthalene 0.14 0.48 C Orem et al. (2007)

Methylphenanthrene 0.03 1.37 C Orem et al. (2007)

Methylpyrene 0.01 0.02 C Orem et al. (2007)

Naphthalene 0.26 0.66 C Orem et al. (2007)

Naphthalenone derivative 0.11 1.38 C Orem et al. (2007)

n-Hexadecanoic acid 0.63 2.56 C Orem et al. (2007)

Nonyl-phenol 0.09 7.91 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-54

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

Octahydroanthracene 0.54 C Orem et al. (2007)

Other alkyl phenols <=5.89 C Orem et al. (2007)

Other aromatic compounds 0.01 0.42 C Orem et al. (2007)

Other benzenamines 0.06 0.25 C Orem et al. (2007)

Other benzene alkyl 

compounds

0.02 0.62 C Orem et al. (2007)

Other heterocyclics <=17.87 C Orem et al. (2007)

Other indene derivatives 0.09 0.16 C Orem et al. (2007)

Other naphthalene alkyl 

compounds

0.04 0.82 C Orem et al. (2007)

Other phthalates <=18.68 C Orem et al. (2007)

Other terpenoid compounds 0.12 0.37 C Orem et al. (2007)

Pentacosane 1.54 C Orem et al. (2007)

Pentadecanoic acid 0.84 C Orem et al. (2007)

Phenanthrene 0.06 0.52 C Orem et al. (2007)

3 S Lester et al. (2015)

Phenanthrene derivative 0.07 C Orem et al. (2007)

Phenanthrene-1-carboxlic acid 0.02 0.12 C Orem et al. (2007)

Phenanthrenone 0.05 0.09 C Orem et al. (2007)

Phenol 830 S Lester et al. (2015)

Phosphoric acid, tributyl ester 0.1 18.96 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-55

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

Propane-diphenyl 0.03 0.22 C Orem et al. (2007)

p-Tert-butylphenol 0.07 0.19 C Orem et al. (2007)

p-Xylene 10 150 460 160 S Khan et al. (2016)

Pyrene 0.01 0.04 C Orem et al. (2007)

0.9 S Lester et al. (2015)

Pyreno[4,5-c]furan 1.83 C Orem et al. (2007)

Quinolo-furazan derivative 0.82 C Orem et al. (2007)

Squalene <=0.24 C Orem et al. (2007)

Sterane 0.51 C Orem et al. (2007)

Tetracosane 1.86 C Orem et al. (2007)

Tetradecane 0.54 C Orem et al. (2007)

Tetradecanoic acid 0.15 0.54 C Orem et al. (2007)

Tetrahydrodimethylnaphthalene0.19 3.25 C Orem et al. (2007)

Tetrahydromethylnaphthalene 0.01 0.69 C Orem et al. (2007)

Tetrahydronaphthalene 0.06 0.82 C Orem et al. (2007)

Tetrahydrophenanthrene 0.03 0.42 C Orem et al. (2007)

Tetrahydrotrimethylnaphthalene0.5 C Orem et al. (2007)

Tetramethylacenaphthylene 0.03 0.07 C Orem et al. (2007)

Tetramethylnaphthalene 0.43 0.79 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-56

Chemical

Minimum or 

only value 

(μg/L)

Average

(μg/L)

Maximum

(μg/L)

Standard 

deviation

(μg/L)

Formation type

(S for shale, 

C for coalbed) Reference

Tetramethylphenanthrene 0.01 0.68 C Orem et al. (2007)

Toluene 100 1,560 5,610 1,940 S Khan et al. (2016)

Total xylenes 30 S Lester et al. (2015)

Tricosane 1.7 C Orem et al. (2007)

Tricyclo[4.4.0.0(3,9)]decane 0.26 C Orem et al. (2007)

Tridecanedial 0.86 C Orem et al. (2007)

Trimethoxy-benzaldehyde 0.39 C Orem et al. (2007)

Trimethylnaphthalene 0.04 2.6 C Orem et al. (2007)

Trimethylphenanthrene 0.04 0.12 C Orem et al. (2007)

Triphenyl phosphate 0.07 0.21 C Orem et al. (2007)
Appendix E – Produced Water Handling Supplemental Information 

E-57

E.3.6. Chemical Reactions 

Section 7.3.4.9 describes general aspects of subsurface chemical reactions that might occur during 

hydraulic fracturing operations. Here we augment the discussion by describing subsurface chemical 

processes. 

E.3.6.1. Injected Chemical Processes 

Hydraulic fracturing injects relatively oxygenated fluids into a reducing environment, which may 

mobilize trace or major constituents into solution. Injection of oxygenated fluids may lead to 

short-term changes in the subsurface redox state, as conditions may shift from reducing to 

oxidizing. The chemical environment in hydrocarbon-rich unconventional reservoirs, such as black 

shales, is generally reducing, as evidenced by the presence of pyrite and methane (Engle and 

Rowan, 2014; Dresel and Rose, 2010). For black shales, reducing conditions are a product of 

original accumulations of organic matter whose decay depleted oxygen to create rich organic 

sediments within oil- and gas-producing formations (Tourtelot, 1979; Vine and Tourtelot, 1970). 

Yet reactions resulting from temporary redox shifts are likely to be less important than those 

resulting from other longer-term physical and geochemical processes. Temporary subsurface redox 

shifts may be due to the short timeframe for fluid injection (a few days to a few weeks). 

Hydraulic fracturing fluid injection introduces novel chemicals into the subsurface.1 As such, the 

geochemistry of injected and native fluids will not be in equilibrium. Over the course of days to 

months, a complex series of reactions will equilibrate disparate fluid chemistries. The evolution of 

flowback and produced water geochemistry are dependent upon the exposure of formation solids 

and fluids to novel chemicals within hydraulic fracturing fluid. Additives interact with reservoir 

solids and either mobilize constituents or themselves become adsorbed to solids. Such additives 

include metallic salts, elemental complexes, salts of organic acids, organometallics, and other metal 

compounds (Montgomery, 2013; House of Representatives, 2011). 

The salts, elemental complexes, organic acids, organometallics, and other metal-containing 

compounds may interact with metals and metalloids in the target formation through processes 

such as ion exchange, adsorption, desorption, chelation, and complexation. For instance, natural 

organic ligands (e.g., citrate) are molecules that can form coordination compounds with heavy 

metals such as cadmium, copper, and lead (Martinez and McBride, 2001; Stumm and Morgan, 1981; 

Bloomfield et al., 1976). Citrate-bearing compounds are used in hydraulic fracturing fluids as 

surfactants, iron control agents, and biocides. Studies of the additives’ interactions with formation 

solids at concentrations representative of hydraulic fracturing fluids are lacking. 

Furthermore, pH will likely play a role in the nature and extent of these processes, as the low pH of 

hydraulic fracturing fluids may mobilize trace constituents. The pH of hydraulic fracturing fluids 

may differ from existing subsurface conditions due to the use of dilute acids (e.g., hydrochloric or 

acetic) used for cleaning perforations and fractures during hydraulic fracturing treatments 

(Montgomery, 2013; GWPC and ALL Consulting, 2009). Metals within formation solids may be 

1 For more information on additive usage, refer to Chapter 5 (Chemical Mixing). 
Appendix E – Produced Water Handling Supplemental Information 

E-58

released through the dissolution of acid-soluble phases such as iron and manganese oxides or 

hydroxides (Yang et al., 2009; Kashem et al., 2007; Filgueiras et al., 2002). Thus, the pH of hydraulic 

fracturing fluids, or changes in system pH that may occur as fluid recovery begins, may influence 

which metals and metalloids are likely to be retained within the formation and which may be 

recovered in flowback. Ultimately, more research is needed to fully understand how the injection of 

hydraulic fracturing fluids affects subsurface geochemistry and resultant flowback and produced 

water chemistry. 

E.3.7. Microbial Community Processes and Content 

By design, hydraulic fracturing releases hydrocarbons and other reduced mineral species from 

freshly fractured shale, sandstone, and coal, resulting in saltier in situ fluids, the release of 

formation solids, and increased interconnected fracture networks with rich colonization surfaces 

that are ideal for microbial growth (Wuchter et al., 2013; Curtis, 2002). The use of biocides, in 

contrast, is intended to inhibit microbial growth. Recent work by Kahrilas et al. (In Press)

performed laboratory experiments to simulate downhole chemistry of the biocide glutaraldehyde 

at 200 oC temperature, 10 MPa pressure, and high salinity. The laboratory results suggested that in 

hot, alkaline shales, the effectiveness of glutaraldehyde as a biocide is limited by contact time; and 

is not so limited in cooler, more acidic, saline formations like the Marcellus. 

Depending upon the formation, microorganisms may be native to the subsurface and/or introduced 

from non-sterile equipment and fracturing fluids. Additionally, microorganisms compete for novel 

organics in the form of additives (Wuchter et al., 2013; Arthur et al., 2009). Since large portions of 

hydraulic fracturing fluid can remain emplaced in the targeted formation, long-term microbial 

activity is supported through these novel carbon and energy resources (Orem et al., 2014; Murali 

Mohan et al., 2013a; Struchtemeyer and Elshahed, 2012; Bottero et al., 2010). Such physical and 

chemical changes to the environment at depth stimulate microbial activity and influence flowback 

and produced water content in important ways. 

Several studies characterizing produced water from unconventional reservoirs (i.e., the Barnett, 

Marcellus, Utica, and Antrim Shales) indicate that taxa with recurring physiologies compose shale 

flowback and produced water microbial communities (Murali Mohan et al., 2013b; Wuchter et al., 

2013). Such physiologies include sulfur cyclers (e.g., sulfidogens: sulfur , sulfate , and thiosulfate 

reducers); fermenters; acetogens; hydrocarbon oxidizers; methanogens; and iron, manganese, and 

nitrate reducers (Davis et al., 2012). 

Based on their physiologies, microorganisms cycle substrates at depth by mobilizing or 

sequestering constituents in and out of solution. Mobilization can occur through biomethylation, 

complexation, and leaching. Sequestration can occur through intracellular sequestration, 

precipitation, and sorption to biomass. 

The extent to which constituents are mobilized or sequestered depends upon the prevailing 

geochemical environment after hydraulic fracturing and through production. Significant 

environmental factors that influence the extent of microbially mediated reactions are increases in 

ionic content (i.e., salinity, conductivity, total nitrogen, bromide, iron, and potassium); decreases in 
Appendix E – Produced Water Handling Supplemental Information 

E-59

acidity, and organic and inorganic carbon; the availability of diverse electron acceptors and donors; 

and the availability of sulfur-containing compounds (Cluff et al., 2014; Murali Mohan et al., 2013b; 

Davis et al., 2012). Examples follow that illustrate how subsurface microbial activity influences the 

content of produced water. 

Under prevailing anaerobic and reducing conditions, microorganisms can mobilize or sequester 

metals found in produced water from unconventional reservoirs (Gadd, 2004). Microbial enzymatic 

reduction carried out by chromium-, iron-, manganese-, and uranium-reducing bacteria can both 

mobilize and sequester metals (Vanengelen et al., 2008; García et al., 2004; Mata et al., 2002; 

Gauthier et al., 1992; Myers and Nealson, 1988; Lovley and Phillips, 1986). For instance, iron and 

manganese species go into solution when reduced, while chromium and uranium species 

precipitate when reduced (Gadd, 2004; Newman, 2001; Ahmann et al., 1994). 

Metals can also be microbially solubilized by complexing with extracellular metabolites, 

siderophores (metal-chelating compounds), and microbially generated bioligands (e.g., organic 

acids) (Glorius et al., 2008; Francis, 2007; Gadd, 2004; Hernlem et al., 1999). For example, 

Pseudomonas spp. secrete acids that act as bioligands to form complexes with uranium(VI) (Glorius 

et al., 2008). 

Many sulfur-cycling taxa have been found in hydraulic fracturing flowback and produced water 

communities (Murali Mohan et al., 2013b; Mohan et al., 2011). Immediately following injection, 

microbial sulfate reduction is stimulated by diluting high-salinity formation waters with fresh 

water (high salinities inhibit sulfate reduction). Microbial sulfate reduction oxidizes organic matter 

and decreases aqueous sulfate concentrations, thereby increasing the solubility of barium (Cheung 

et al., 2010; Lovley and Chapelle, 1995). 

Sulfidogens also reduce sulfate, as well as elemental sulfur and other sulfur species (e.g., 

thiosulfate) prevalent in the subsurface, contributing to biogenic sulfide or hydrogen sulfide gas in 

produced water (Alain et al., 2002; Ravot et al., 1997). Sulfide can also sequester metals in sulfide 

phases (Ravot et al., 1997; Lovley and Chapelle, 1995). Sources of sulfide also include formation 

solids (e.g., pyrite in shale) and remnants of drilling muds (e.g., barite and sulfonates), or other 

electron donor sources (Davis et al., 2012; Kim et al., 2010; Collado et al., 2009; Grabowski et al., 

2005). 

Additionally, anaerobic hydrocarbon oxidizers associated with shale produced water can readily 

degrade simple and complex carbon compounds across a considerable salinity and redox range 

(Murali Mohan et al., 2013b; Fichter et al., 2012; Timmis, 2010; Lalucat et al., 2006; Yakimov et al., 

2005; McGowan et al., 2004; Hedlund et al., 2001; Cayol et al., 1994; Gauthier et al., 1992; Zeikus et 

al., 1983). 

Lastly, microbial fermentation produces organic acids, alcohols, and gases under anaerobic 

conditions, as is the case during methanogenesis. Some nitrogen-cycling genera have been 

identified in shale gas systems. These include genera involved in nitrate reduction and 

denitrification (Kim et al., 2010; Yoshizawa et al., 2010; Yoshizawa et al., 2009; Lalucat et al., 2006). 
Appendix E – Produced Water Handling Supplemental Information 

E-60

These genera likely couple sugar, organic carbon, and sulfur species oxidation to nitrate reduction 

and denitrification processes. 

Consequently, using a variety of recurring physiologies, microorganisms mobilize and sequester 

constituents in and out of solution to influence the content of produced water. 

E.4. Produced Water Content Spatial Trends 

E.4.1. Variability between Plays of the Same Rock Type 

E.4.1.1. Shale Formation Variability 

The content of shale produced water varies geographically, as shown by data from four formations 

(the Bakken, Barnett, Fayetteville, and Marcellus Shales; see Table E-2, Table E-4, Table E-6, Table 

E-8, Table E-9, and Table E-11). For several constituents, variability between shale formations is 

common. The average/median TDS concentrations in the Marcellus (87,800 to 106,390 mg/L ) and 

Bakken (196,000 mg/L) Shales are one order of magnitude greater than the average TDS 

concentrations reported for the Barnett and Fayetteville Shales (Table E-2). As Fayetteville 

produced water contains the lowest reported average TDS concentration (13,290 mg/L), average 

concentrations for many inorganics (i.e., bromide, calcium, chloride, magnesium, sodium, and 

strontium) that contribute to dissolved solids loads are the lowest compared to average 

concentrations for the same inorganics in Bakken, Barnett, and Marcellus produced water (Table 

E-4 and Table E-6). Average concentrations for metals reported within Bakken and Marcellus 

produced water are also higher than those within the Barnett or Fayetteville formations (Table 

E-6).

Additionally, Marcellus produced water is enriched in barium (average concentration of 2,224 mg/l 

in Barbot et al. (2013) or median calculated from Hayes (2009) of 542.5 mg/L) and strontium 

(average concentration of 1,695 mg/L (Barbot et al., 2013) or median calculated from Hayes (2009)

of 1,240 mg/L) by one to three orders of magnitude compared to Bakken, Barnett, and Fayetteville 

produced water (Table E-6). Subsequently, radionuclide variability expressed as isotopic ratios 

(e.g., radium-228/radium-226, strontium-87/strontium-86) are being used to determine the 

reservoir source for produced water (Chapman et al., 2012; Rowan et al., 2011; Blauch et al., 2009). 

Lastly, Barnett and Bakken produced waters are enriched in sulfate. 

Although organic data are limited, average BTEX concentrations are higher in Marcellus compared 

to Barnett produced water by one order of magnitude, whereas concentrations of benzene alone 

are marginally higher in Barnett compared to Marcellus produced water (Table E-9 and Table 

E-11).

E.4.1.2. Tight Formation Variability 

The average concentrations for various constituents in tight formation produced water vary 

geographically between sandstone formations (the Cotton Valley Group, Devonian sandstone, and 

the Mesaverde and Oswego), as shown in Table E-2, Table E-4, Table E-6, Table E-8, and Table E-9. 

The average TDS concentrations in the Devonian sandstone (235,125 mg/L) and Cotton Valley 
Appendix E – Produced Water Handling Supplemental Information 

E-61

Group (164,683 mg/L) are one to two orders of magnitude greater than the average TDS 

concentrations reported for the Mesaverde (15,802 mg/L) and Oswego Formations (73,082 mg/L) 

(Table E-2). Mesaverde produced water also contained the lowest average concentrations for many 

of the inorganic components of TDS (i.e., calcium, chloride, iron, magnesium, and sodium) (Table 

E-4 and Table E-6).

Little variability was reported in pH between these four tight formations (E-2). Mesaverde 

produced water was enriched in sulfate, with an average concentration of 837 mg/L (Table E-4), 

whereas Devonian produced water was enriched in barium, which had an average concentration of 

1,488 mg/L (Table E-6).

E.4.1.3. Coalbed Variability 

Geochemical analysis showed that the Powder River Basin is predominately characterized by 

bicarbonate water types with a large intrusion of sodium-type waters across a large range of 

magnesium and calcium concentrations (Dahm et al., 2011).1 In contrast, the Raton Basin is typified 

by sodium-type waters with low calcium and magnesium concentrations. A combination of Powder 

River and Raton produced water compositional characteristics typifies the San Juan Basin (Dahm et 

al., 2011). Lastly, Black Warrior Basin produced water is differentiated based upon its sodium 

bicarbonate- or sodium chloride-type waters (DOE, 2014; Pashin et al., 2014). 

Regional variability is observed in average produced water concentrations for various constituents 

of four CBM basins (Powder River, Raton, San Juan, and Black Warrior (Table E-3, Table E-5, Table 

E-7, Table E-9, and Table E-12), but particularly between produced water of the Black Warrior 

Basin and the others. As the average TDS concentration in Black Warrior Basin produced water 

(14,319 mg/L) is one to two orders of magnitude higher than that of the other three presented in 

Table E-5, average concentrations for TDS contributing ions (i.e., calcium, chloride, and sodium) 

were also higher than in the Powder River, Raton, and San Juan Basins. These high levels follow 

from the marine depositional environment of the Black Warrior Basin (Horsey, 1981). 

Powder River Basin produced water has the lowest average TDS concentration (997 mg/L), which 

is consistent with Dahm et al. (2011) reporting that nearly a quarter of all the produced water 

sampled from the Powder River Basin meets the U.S. drinking water secondary standard for TDS 

(less than 500 mg/L).2 In addition, the Black Warrior Basin appears to be slightly enriched in 

barium, compared to the other three CBM basins (Table E-5). Lastly, the three western CBM basins 

1Water is classified as a “type” if the dominant dissolved ion is greater than 50% of the total. A sodium-type water 

contains more that 50% of the cation milliequivalents (mEq) as sodium. Similarly, a sodium-bicarbonate water contains 

50% of the cation mEq as sodium, and 50% of the anion mEq as bicarbonate (USGS, 2002). 

2 MCL refers to the highest level of a contaminant that is allowed in drinking water. MCLs are enforceable standards. These 

include primary MCLs for barium, cadmium, chromium, lead, mercury, and selenium. National Secondary Drinking Water 

Regulations (NSDWRs or secondary standards) are non-enforceable guidelines regulating contaminants that may cause 

cosmetic effects (such as skin or tooth discoloration) or aesthetic effects (such as taste, odor, or color) in drinking water. 

Secondary MCLs are recommended for aluminum, chloride, copper, iron, manganese, pH, silver, sulfate, TDS, and others. 

See http://water.epa.gov/drink/contaminants/index.cfm#Primary for more information. 
Appendix E – Produced Water Handling Supplemental Information 

E-62

(Powder River, Raton, and San Juan) are much more alkaline and enriched in bicarbonate than their 

eastern counterpart (the Black Warrior Basin; Table E-3).

Average concentrations of benzene, ethylbenzene, and xylenes are higher in San Juan compared to 

Raton produced water by two orders of magnitude, whereas concentrations of toluene are 

marginally higher in Raton compared to San Juan produced water (Table E-9).

E.4.2. Local Variability 

Spatial variability of produced water content frequently exists within a single producing formation. 

For instance, Marcellus Shale barium levels increase along a southwest to northeast transect 

(Barbot et al., 2013). Additionally, produced water from the northern and southern portions of the 

San Juan Basin differ in TDS, due to groundwater recharge in the northern basin leading to higher 

chloride concentrations than in the southern portion (Dahm et al., 2011; Van Voast, 2003). 

Spatial variability of produced water content also exists at a local level due to the stratigraphy 

surrounding the producing formation. For example, deep saline aquifers, if present in the over- or 

underlying strata, may over geologic time encroach upon shales, coals, and sandstones via fluid 

intrusion processes (Blauch et al., 2009). Evidence of deep brine migration from adjacent strata into 

shallow aquifers via natural faults and fractures has been noted previously in the Michigan Basin 

and the Marcellus Shale (Vengosh et al., 2014; Warner et al., 2012; Weaver et al., 1995). By 

extension, in situ hydraulic connectivity, which is stimulated by design during hydraulic fracturing, 

may lead to the migration of brine-associated constituents in under- and overlying strata into 

producing formations, as discussed in Chapter 6. 

E.5. North Dakota Spill Analysis 

E.5.1. Materials and Methods 

Incidents were reported to the North Dakota Department of Health from across the Bakken Gas 

Shale, Late Devonian to Early Mississippian in age. We reviewed incidents occurring during the 

years 2001-2015, and categorized them by release type: salt water (SW), oil, and other.1 First, two 

years (2014 and 2015) of Oil Field dataset was retrieved from the North Dakota Spills Database 

Website operated by the North Dakota Department of Health, Division of Water Quality 

(http://www.ndhealth.gov/EHS/Spills/). The entire public dataset to date was later (March 15, 

2016) obtained directly from the ND Department of Health for our analysis of the years 2001 to 

2015. The data from 2014 and 2105 were used to summarize causes of spills. 

Our method of data-cleaning involved eliminating data with empty cells (NA), or reports of “0” 

values. If data were presented as “0” bbl or gal for SW, oil, and other spills, we omitted those values 

from the dataset (n= 434). Additionally, cells containing “0” or “NA” for SW, oil, and other reported 

spills were omitted from the dataset (n= 98). A single spill with unit “lbs”, referring to dust used in 

1The “other” category also includes spills categorized as: freshwater, condensate, drilling mud, injection fluid, emulsion, 

injection chemical, petroleum, product, misc, uncharacterized, oil and water, freshwater and brine, and drill cuttings. 

Some incidents did not release a liquid as, for example, the release could have only been gas. 
Appendix E – Produced Water Handling Supplemental Information 

E-63 

processing of drill cuttings, was omitted (n=1). All values were converted to barrels (bbl when 

necessary). 

The dataset containing SW, oil, and other, was further divided into three datasets based on spill 

type. The compiled statistics only included releases with volumes above (SW: n=6238, oil: n=4882, 

and other: n=9863). Unlike the Oklahoma study reported in the main text (Fisher and Sublette, 

2005), we are not able to identify salt water spills whose volume was not estimated. 

The spill rates were determined by dividing the spill counts and volumes by the number of active 

production wells. The latter data were obtained from the North Dakota Oil and Gas Division web 

site (https://www.dmr.nd.gov/oilgas/stats/statisticsvw.asp). Monthly well counts are available for 

the years of interest, and we used the active well count for December of each year in our 

calculations. Alternatively different months or the average for the entire year could be used. 

Through testing, we found no meaningful differences in the estimates. The median (or middle) 

volume of produced water (SW) spills was consistently about 340 gal (1,300 L) for the period 2001 

to 2015 (Figure 7-13).1 The data are represented by box plots in the main text (Figure E-6).

Figure E-6. Illustration of a "box" or "box and whisker" plot. 

1 50% of spill volumes were below and 50% above the median value. Medians are less sensitive to extreme values than 

means (averages). Means above the median indicate that the distribution is skewed by a relatively small number of 

incidents with high spill volumes. 
Appendix E – Produced Water Handling Supplemental Information 

E-64

E.5.2. Results

For comparison with the other types of spilled liquids, after 2009 the median volume for oil spills 

tended toward 130 gal (480 L) for oil (Figure E-7) and 210 gal (790 L) for all other spills (Figure 

E-8). In each case, however, the mean numbers of spills were higher than the medians, indicating

that although the majority of SW spills were 340 gal (1,300 L) or less, larger volume spills occurred

and increased the mean value. For SW spills, the largest spill recorded was 2,900,000 gal

(11,000,000 L) occurring in January 2015. Although most of the SW spills contained 340 gal (1,300

L) or less, large spills (400,000 gal (11,000,000 L) or more) occurred in 2013, 2014, and 2015

(Figure 7-13).

Figure E-7. Median, mean, and maximum volume of oil spills in North Dakota for 2001 to 

2015. 
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E-65

Figure E-8. Median, mean, and maximum volume of “other” spills in North Dakota for 2002 to 

2015. 

The number of spills increased with increasing numbers of active wells (Figure E-9). Each type of 

spill decreased from 2014 to 2015 (Figure E-9). From 2001 to 2007 the rate of oil and produced 

water spills were roughly the same (Figure E-9), afterwards there were fewer produced water 

spills. From 2010 to 2015, the rate of produced water spills ranged from 4.7 to 7.2 per hundred 

active wells; oil spills from 6.1 to 10.0 per hundred active wells and other spills from 1.7 to 3.7 per 

hundred active wells. By the end of 2015 there were over 13,000 active production wells in North 

Dakota, and these fractions corresponded to 613 produced water, 825 oil, and 369 other spills 

(Figure E-9). Although there were more oil than produced water spills, the median and maximum 

produced water spills were larger than the median oil spills. 
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E-66

Figure E-9. Count of spills and active wells in North Dakota for the years 2001 to 2015. 

North Dakota distinguishes between spills that are and are not contained within the boundaries of 

the production or exploration facility (http://www.ndhealth.gov/ehs/spills/). For each type of spill, 

more were contained than not contained (Figure E-10). The maximum spill sizes were generally 

higher in the not contained category (Figure E-12).
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E-67

Figure E-10. Number of spills in North Dakota from 2001 to 2015 separated by type and by 

“contained” versus “not contained.”
Appendix E – Produced Water Handling Supplemental Information 

E-68

Figure E-11. Median volume (gal) of spills in North Dakota from 2001 to 2015 separated by 

type and by “contained” versus “not contained.”
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E-69

Figure E-12. Yearly sum of spill volume (gal) of spills in North Dakota from 2001 to 2015 

separated by type and by “contained” versus “not contained.”

The distribution of spills of each type is skewed. For 2015, the medians range from 8 to 80 gal (300 

to 3,000 L) (considering contained and not contained of each type) but the maximums are much 

higher ranging from 50,000 to 2,900,000 gal (190,000 to 11,000,000 L) (Table E-14 and Table 

E-15). Further, the maximums are much higher than the 75th percentiles, indicating a relatively 

small number of large spills. Only a very few spills occur that are greater than 20,000 gal (80,000 L) 

(Table E-16). In the case of produced water, there were 12 spills over 20,000 gal (80,000 L), five 

over 40,000 gal (160,000 L) , and one greater than 400,000 gal (1,600,000 L) (Table E-16).
Appendix E – Produced Water Handling Supplemental Information 

E-70

Spill causes were discussed for the composited produced water spills in the main text. Although 

small in absolute numbers, proportionately more pipeline leaks, “other,” and stuffing box leaks 

caused produced water spills in 2015 (Figure E-14 and Figure E-15).

Table E-14. Volume distribution in gallons (minimum, 25th percentile, median, 75th percentile 

and maximum) for each type of spill in North Dakota for 2015. 

Type Spills Min 25th Med 75th Max

Oil Contained 1 40 130 420 94,000

Not Contained 1 40 80 290 105,000

All 1 40 130 340 105,000

Other Contained 0.04 80 210 840 50,000

Not Contained 2 80 840 840 105,000

All 0.04 80 210 840 105,000

SW Contained 1 80 340 1,300 340,000

Not Contained 1 130 420 2,100 2,900,000

All 1 80 340 1,300 2,900,000

Table E-15. Numbers of 2015 North Dakota spills in ranges defined by the spill 

volume statistics (Table E-14) for each type. 

Count

Type Status Min ≤ x < 25th 25th ≤ x < Med Med ≤ x < 75th 75th ≤ x ≤ Max

Oil Contained 71 212 188 158

Not 

Contained 59 29 57 51

All 130 257 217 221

Other Contained 55 32 44 35

Not 

Contained 12 9 0 21

All 67 35 50 56

SW Contained 77 184 127 141

Not 

Contained 21 18 21 24

All 94 202 163 154
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Table E-16. Number of 2015 North Dakota spills which exceed thresholds (20,000 gal, 40,000 

gal, and 400,000 gal) for each type of spill. 

Size

Type Status ≥ 20,000 gal ≥ 40,000 gal ≥ 400,000 gal

Oil Contained 3 3 0

Not Contained 2 1 0

All 5 4 0

Other Contained 1 1 0

Not Contained 2 2 0

All 3 3 0

SW Contained 6 2 0

Not Contained 6 3 1

All 12 5 1

Figure E-13. Numbers of contained spills in North Dakota by cause for 2014 and 2015. 
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Figure E-14. Numbers of not contained spills in North Dakota by cause for 2014 and 2015. 

E.5.3. Summary of Additional Studies on Spills 

Gross et al. (2013) analyzed the Colorado Oil and Gas Conservation Commission’s database for 

groundwater BTEX concentrations linked to storage and production facilities between July 2010 

and July 2011 in Weld County, CO. Only spills with an impact on groundwater were included in the 

study. The 77 reported spills accounted for less than 0.5% of nearly 18,000 active wells. Forty-six of 

the 77 spills consisted of produced water and oil. Of the remaining spills, 23 consisted of only oil 

and eight consisted of only produced water. Thus the results that follow include cases with no 

produced water spill. From these composited spills, benzene concentrations in 90% of the 

groundwater samples exceeded 5 μg/L, the U.S. drinking water standard. Additionally, 30% of 

toluene, 12% of ethylbenzene, and 8% of xylene sample concentrations exceeded 1 mg/L, 0.7 mg/L 

and 10 mg/L, respectively (Gross et al., 2013). 

Based on five spills for which volumes were reported, the average volume of a produced water spill 

was 294 gal (1,110 L), ranging from 42 (160 L) to 1,176 gal (4,450 L) (Gross et al., 2013). Spill areas 

averaged 2,120 ft2 (197 m2) with an average depth of 7 ft (2 m). Tank battery systems and 

production facilities were the biggest volume sources of spills with groundwater impacts. 

Equipment failure was the most common cause of spills with groundwater impacts. Of the 77 

reported spills, secondary containment was absent from 51 of them (Gross et al., 2013). 
Appendix E – Produced Water Handling Supplemental Information 

E-73

As noted from the Colorado (Gross et al., 2013) and Oklahoma (Fisher and Sublette, 2005) studies, 

oil releases may occur alongside produced water spills. Review of recent oil field incidents in North 

Dakota (from information on the state’s website at http://www.ndhealth.gov/EHS/Spills/) also 

shows incidents with both produced water and oil releases. Oil releases are characterized by a 

number of features including their unique hydrocarbon composition and physical properties. 

Impacts can include: surface runoff, infiltration into soils, formation of sheens and oil slicks on 

surface waters, evaporation, oxidation, biodegradation, emulsion formation, and particle deposition 

(U.S. EPA, 1999b). 

Brantley et al. (2014) reviewed PA DEP’s online oil and gas compliance database for notices of 

violation issued to companies developing gas resources in unconventional reservoirs. Between May 

2009 and April 2013, eight spills of flowback and produced water ranging from more than 4,000 gal 

(15,000 L) to more than 57,000 gal (220,000 L) reached surface water resources. The spills 

typically resulted in local impacts to environmental receptors and required remediation and 

monitoring. However, the study indicated the likelihood of a leak or spill of hydraulic fracturingrelated fluids was low (less than 1%, based on 32 large spills out of more than 

4,000 complete wells). Due to lack of data, specific impacts to the eight receiving surface waters 

were not discussed, other than noting the produced water had contacted the surface water. 

E.6. Evaluation of Impacts 

As an example of set of criteria for assessing sites potentially contaminated by hydraulic fracturing 

activities, the U.S. EPA (2012e) developed an approach to study sites with suspected impacts from 

hydraulic fracturing activities. The approach was based on a tiered scheme where results from each 

tier are used to refine activities in higher tiers. The four tiers, with some modification, are as 

follows: 

Verify potential issue: 

 Evaluate existing data and information from operators, private citizens, federal, state and 

local agencies, and tribes (as appropriate). Including studies of local groundwater quality 

that might have been conducted by USGS. 

 Conduct site visits. 

 Interview stakeholders and interested parties. 

Determine approach for detailed investigations: 

 Establish sampling locations 

 Conduct initial sampling of water wells, taps, surface water, and soils. 

 Identify potential evidence of drinking water contamination. 

 Develop conceptual site model describing possible sources and pathways of the reported 

or potential contamination. 

 Develop, calibrate, and test fate and transport model(s). 
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Conduct detailed investigations to detect and evaluate potential sources of contamination: 

 Conduct additional sampling of soils, aquifer, surface water, and produced water 

pits/tanks where present. 

 Conduct additional testing, including further water testing with new monitoring points, 

soil gas surveys, geophysical testing, well mechanical integrity testing, and stable isotope 

analyses. 

 Refine conceptual site model and further test exposure scenarios. 

 Refine fate and transport model(s) based on new data. 

Determine the source(s) of any impacts to drinking water resources: 

 Develop multiple lines of evidence to determine the source(s) of impacts to drinking water 

resources. 

 Exclude possible sources and pathways of the reported contamination. 

 Assess uncertainties associated with conclusions regarding the source(s) of impacts. 

This tiered assessment strategy provides an outline for collecting data and evaluating lines of 

evidence to determine whether impacts have occurred. An outline of the quality assurance project 

plan (QAPP) for the EPA’s Retrospective case study in northeastern Pennsylvania: Study of the 

potential impacts of hydraulic fracturing on drinking water resources (U.S. EPA, 2014d, 2012d) is 

given in Table E-17, and a graphical presentation of the relationships among quality assurance 

blanks is shown in Figure E-15. Table E-18 summarizes the lines of evidence used 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, 2015i).

Table E-17. Outline of Northeastern Pennsylvania Retrospective Case Study QAPP. 

Topic Elements

Sampling Process Design Background information on geology, hydrology, and geochemistry

Groundwater and surface water monitoring

Sampling Methods Domestic wells

Surface waters: springs, ponds, and streams

Sampling Handling and Custody Water sample labeling

Water sample packing, shipping, and receipt at laboratories

Analytical Methods Groundwater and surface water

Quality Control Quality metrics for aqueous analysis

Measured and Calculated solute concentration data evaluation

Detection limits

QA/QC calculations
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E-75

Topic Elements

Instrumentation Testing, inspection, and maintenance

Equipment calibration and frequency

Acceptance of supplies and consumables

Non-direct Data Assurance of Quality of 3RD party data (i.e., USGS background water quality 

data, university research publications)

Data Management Recording

Storage

Analysis

Assessment and Oversight Assessments

Assessment Reporting

Data Validation and Usability Data review, verification, and validation

Verification and validation methods

Reconciliation with user requirements

Figure E-15. Quality assurance blanks illustrating giving their purpose, brief procedure, and 

the span of their scope (modified from US EPA Region 3 Quality Control Tools: Blanks, April 

27, 2009). 

For example, the equipment blank spans all aspects of sampling and analysis from field to laboratory, while the 

instrument blank only assess contamination in the instrument itself. Reviewing results from all of these blanks 

could narrow down the source of sample cross-contamination. 
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Table E-18. Source delineation analysis table from the EPA retrospective case study in Wise County, Texas. 

Well Technique Brine Sea Water

Halite/

Road Salt

Landfill 

Leachate

Sewage/

Septic Tank Animal Waste

WISETXGW01 Bromide vs. Boron Yes Yes Yes No No No

Chloride vs. Magnesium Yes Yes No No No No

Chloride vs. Bromide Yes Yes Yes No No Yes

Chloride vs. Bicarbonate Yes Yes Yes No No No

Chloride vs. Calcium Yes Yes Yes No No No

Chloride vs. Potassium Yes Yes Yes No No No

Chloride vs. Sodium Yes Yes Yes No No No

Chloride vs. Sulfate Yes Yes Yes No No No

Cl/Br Yes Yes Yes Yes No No

Cl/I Yes Yes Yes Yes No Yes

K/Rb Yes Yes No Dataa No Dataa No Dataa No Dataa

Sr Isotope Yes No Dataa No Dataa No Dataa No Dataa No Dataa

Percentage Of Yesb 100 100 90 20 0 20

WISETXGW05 Bromide vs. Boron No No No No No No

Chloride vs. Magnesium No No No No Yes Yes

Chloride vs Bromide No No No No No No

Chloride vs. Bicarbonate No No No Yes No Yes

Chloride vs. Calcium No No No No Yes Yes

Chloride vs. Potassium Yes Yes Yes Yes Yes Yes

Chloride vs. Sodium Yes No No Yes Yes Yes
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Well Technique Brine Sea Water

Halite/

Road Salt

Landfill 

Leachate

Sewage/

Septic Tank Animal Waste

WISETXGW05, 

cont.

Chloride vs. Sulfate Yes Yes Yes No No No

Cl/Br No No No No No No

Cl/I No Dataa No Dataa No Dataa No Dataa No Dataa No Dataa

K/Rb Yes Yes No Dataa No Dataa No Dataa No Dataa

Sr Isotope Yes No Dataa No Dataa No Dataa No Dataa No Dataa

Percentage Of Yesb 45 30 22 33 44 46

WISETXGW08 Bromide vs. Boron Yes Yes Yes No No No

Chloride vs. Magnesium Yes Yes No No No No

Chloride vs. Bromide Yes Yes Yes No No Yes

Chloride vs. Bicarbonate Yes Yes Yes No No No

Chloride vs. Calcium Yes Yes Yes No No No

Chloride vs. Potassium Yes Yes Yes No No No

Chloride vs. Sodium Yes Yes Yes No No No

Chloride vs. Sulfate Yes Yes Yes No No No

Cl/Br Yes Yes Yes Yes No No

Cl/I Yes Yes Yes Yes No Yes

K/Rb Yes Yes No Datab No Datab No Datab No Datab

Sr Isotopeb Yes No Datab No Datab No Datab No Datab No Datab

Percentage Of Yesb 100 100 90 20 0 20

a Although there was no data for the other sources, the analysis done for brine sources is consistent with brines as a source of the observed impacts (see Figure 50 and the 

discussion in the “Source Identification” section of this report).

b K/Rb and Sr isotope data were not found in the literature for these sources.
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E.7. Transport Properties 

The identified constituents of flowback and produced water include inorganic chemicals in the form 

of cations and anions (including various types of metals, metalloids, and non-metals, and 

radioactive materials, among others) and organic chemicals, including identified compounds in 

various classes, and unidentified materials measured as TOC and DOC. Environmental transport of 

these chemicals depends on the properties of the chemical and properties of the environment, and 

is extensively discussed in Section 5.8.3. 

Transport of inorganic chemicals depends on the nature of groundwater and vadose zone flow, and 

potential reactions among the inorganic chemical, solid surfaces, and geochemistry of the water. 

Some inorganic anions (i.e., chloride and bromide) move with their carrier liquid and are mostly 

impacted by physical transport mechanisms: flow of water and dispersion. In addition to the flowrelated processes, transport of most inorganics depends upon three mechanisms related to 

partitioning to the solid phase: adsorption, absorption, and precipitation. The effects of these 

mechanisms depend on both chemical and site-specific environmental characteristics, including the 

surface reactivity, solubility, and redox sensitivity of the contaminant; the type and abundance of 

reactive mineral phases, and the ground-water chemistry (U.S. EPA, 2007). Generalized 

characterization of inorganic transport is not possible, but through the use of transport models, the 

effects of physical transport mechanisms and chemical processes can be integrated. Examples of 

transport models for reactive metals include the Geochemist’s Workbench (Bethke, 2014) and 

Hydrus (Šimunek et al., 1998). 

Properties of organic chemicals which tend to affect the likelihood that a chemical will reach and 

impact drinking water resources if spilled include high chemical mobility in water and low 

volatility. Biodegradation, which depends on properties of the chemical, subsurface 

microorganisms, and the environment, governs the fate of these contaminants. 

Using the EPA chemical database EPI SuiteTM, we were able to obtain actual or estimated 

physicochemical properties for 521 of the individual organic chemicals identified in produced 

water and listed in Appendix H. A portion of these, 59, are used in the chemical mixing stage (Table 

C-9). The EPI SuiteTM results are constrained by their applicability to one temperature (25 oC), and 

salinity (low). Temperature changes impact Henry’s law constant, Kow, and solubility, and depend 

on the characteristics of the chemical and ions present (Borrirukwisitsak et al., 2012; 

Schwarzenbach et al., 2002). In some cases, the effect changes exponentially with salinity 

(Schwarzenbach et al., 2002). Therefore, property values that depart from the EPI SuiteTM values 

are expected for produced water at elevated temperature and salinity. Although little is known 

concerning attenuation of hydraulic fracturing fluid constituents, Kekacs et al. (2015) report that 

salinity above 40,000 mg/L initially inhibited aerobic degradation of the organic constituents of a 

synthetic fracturing fluid (for 6.5 days), even though the bacterial communities were preacclimated to the salts. 
Appendix E – Produced Water Handling Supplemental Information 

E-79

E.8. Example Calculation for Roadway Transport 

This section provides background information for the roadway transport calculation appearing in 

Chapter 7. 

An estimate of releases from truck transport of produced water could be made as follows: 

Total number of truckloads =

Produced water volume per well

Produced water volume per truck

Then the total distance traveled by all trucks is given by: 

Total distance traveled = Total number of truckloads × Distance per truck

The number of crashes impacting drinking water resources can be estimated from: 

Fraction of crashes impacting drinking water resources

= Fraction of crashes releasing waste that impacts drinking water resources 

× Fraction of all crashes releasing waste × Crash rate 

× Total distance traveled 

Because the chances of a crash is low, the results are expressed as one truck trip with a crash to 

total truck trips without a crash (Table E-21). Estimates of all but one of the quantities in these 

calculations can be made from various literature sources, which are described in the subsequent 

sections. A key parameter is the number of crashes of trucks per distance traveled. In 2012, the U.S. 

Department of Transportation (DOT) estimated that the number of crashes per 100 million 

highway miles driven of a type of large truck was 110, which is a relatively small number. A key 

parameter that is unknown is the number of crashes which impact drinking water resources, so 

definitive estimates of impacts to drinking water resources cannot be made. Alternatively, as an 

upper bound on drinking water resource impacts, the fraction of crashes which release waste can 

be estimated. 

E.8.1. Estimation of Transport Distance 

In a study of wastewater management for the Marcellus Shale, Rahm et al. (2013) used data 

reported to the Pennsylvania Department of Environmental Protection (PA DEP) to estimate the 

average distance wastewater was transported. For the period from 2008 to 2010, the distance 

transported was approximately 100 km, but it was reduced by 30% for 2011. The reduction was 

attributed to increased treatment infrastructure in Lycoming County, an area of intensive hydraulic 

fracturing operations in northeastern Pennsylvania. For the part of Pennsylvania within the 

Susquehanna River Basin, Gilmore et al. (2013) estimated the likely transport distances for drilling 

waste to landfills (256 km or 159 mi); produced water to disposal wells (388 km or 241 mi); and 

commercial wastewater treatment plants (CWTPs) (158 km or 98 mi). These distances are longer 

than the values from Rahm et al. (2013), in part, because wells in the Susquehanna Basin are 

further to the east of Ohio disposal wells and some CWTPs. 
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E.8.2. Estimation of Wastewater Volumes 

In an example water balance calculation, Gilmore et al. (2013) used 380,000 gal (1.4 million L) of 

flowback as the volume transported to CWTPs, 450,000 gal (1.7 million L) of flowback transported 

to injection wells, and 130,000 gal (490,000 L) of un-reusable treated water also transported to 

injection wells for a total estimated wastewater volume of 960,000 gal (3.6 million L) per well. 

E.8.3. Estimation of Roadway Accidents 

The U.S. Department of Transportation (DOT) published statistics on roadway accidents (U.S. 

Department of Transportation, 2012) which indicate that the combined total of combination truck 

crashes in 2012 was 179,736, or 110 per 100 million vehicle miles (1.77 million km) (Table E-19). 

As an indicator of the uncertainty of these data, DOT reported 122,240 large truck crashes from a 

differing set of databases (Table E-20), with a rate of 75 per 100 million vehicle miles, which is 68% 

of the number of combination truck crashes. 

Table E-19. Combination truck crashes in 2012 for the 2,469,094 registered combination 

trucks, which traveled 163,358 million miles. 

Source: U.S. Department of Transportation (2012). A combination truck is defined as a truck tractor pulling any 

number of trailers.

Type of crash

Combination trucks 

involved in crashes

Rates per 100 million vehicle miles 

traveled by combination trucks

Property damage only 135,000 82.8

Injury 42,000 25.5

Fatal 2,736 1.74

Total 179,736 110

Table E-20. Large truck crashes in 2012.

Source: U.S. Department of Transportation (2012). A large truck is defined as a truck with a gross vehicle weight 

rating greater than 10,000 pounds.

Type of crash Total crashes Large trucks with cargo tanks

Number Percentage

Towaway crashes 72,644 4,364 6.0%

Injury 45,794 3,245 7.1%

Fatal 3,802 360 9.5%

Totals 122,240 7,969 6.5%
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E-81

E.8.4. Estimation of Material Release Rates in Crashes

Estimates ranging from 5.6% to 36% have been made for the probability of material releases from 

crashed trucks. Craft (2004) used data from three databases to estimate the probability of spills in 

fatality accidents at 36%, which may overestimate the probability for all types of accidents (Rozell 

and Reaven, 2012).1 The U.S. Department of Transportation (2012) provides estimates of 

hazardous materials releases from large truck crashes. For all types of hazardous materials carried, 

408 of 2,903 crashes, or 14%, were known to have hazardous materials releases. The occurrence of 

a release was unknown for 18% of the crashes. These crashes were not distinguished by truck type, 

so they likely overestimated the number of tanker crashes. Harwood et al. (1993) used accident 

data from three states (California, Illinois, and Michigan) to develop hazardous materials release 

rate estimates for different types of roadways, accidents, and settings (urban or rural). For 

roadways in rural settings the probability of release ranged from 8.1% to 9.0%, while in urban 

settings the probability ranged from 5.6% to 6.9%. 

E.8.5. Estimation of Volume Released in Accidents

Based on the estimated volumes, disposal distances, truck sizes, and accident rates used by Gilmore 

et al. (2013), Rahm et al. (2013), and King (2012), the total travel distance by trucks ranges from 

9,620 mi (14,900 km) to 22,875 mi (36,814 km) per well (Table E-21).

Based on the varying assumptions of each author (Gilmore et al., 2013; King, 2012; Rahm and Riha, 

2012) the chances of an accident which releases produced water over the lifetime of a well ranges 

from 1:110 to 1:13,000 (Table E-21).2These estimates are dependent on the volumes, transport 

distances, and crash rates chosen for analysis. The results show, however, that the expected 

number of releases is relatively low. 

Several limitations are inherent in this analysis, including differing rural road accident rates and 

highway rates, differing wastewater endpoints, and differing amounts of produced water transport. 

Further, the estimates present an upper bound on impacts, because not all releases of wastewater 

would reach or impact drinking water resources. 

Impacts to groundwater might occur following a spill on land. When the liquid is highly saline, its 

migration is affected by its high density and viscosity compared with that of fresh water. When 

spilled flowback or produced water flows over land, a fraction of the liquid is subject to infiltration. 

The fraction depends on the rate of release, surface cover (i.e., pavement, cracked pavement, 

vegetation, bare soil, etc.), slope of the land surface, subsurface permeability, and the moisture 

content in the subsurface.

1 The three databases were the Trucks Involved in Fatal Accidents developed by the Center for National Truck Statistics at 

the University of Michigan, the National Automotive Sampling System’s General Estimates System (GES) produced by the 

National Highway Transportation Safety Agency, and the Motor Carrier Management Information System (MCMIS) Crash 

File produced by the Federal Motor Carrier Safety Administration. 

2 The chances of a crash releasing produced water are calculated from the material release rate times the crash rate times 

the total miles traveled. The results are expressed as 1 to the reciprocal of this number (i.e., 1:5,900). 
Appendix E – Produced Water Handling Supplemental Information 

E-82

Table E-21. Chances of a crash releasing produced water based on the total produced water volume per well, transport distances, 

crash rates, and material release rates. 

Chances of a Crash Releasing 

Produced Water 

Material release rate boundsb

3.4% 5.6% 36%

Crash rate (per 100 million miles)

Action

Waste per well

(million gal)

Trucks

(20 m3/truck)a

Miles traveled 

per truck

Total miles 

traveled 

(per well) 28 75 110 75 110

Gilmore et al. (2013) distance estimates 

Produced water to CWTP 0.38 72 29.6 2,131 n/a n/a n/a n/a n/a

Produced water to disposal 

well 0.45 85 147 12,495 n/a n/a n/a n/a n/a

CWTP effluent to disposal well 0.13 25 133 3,325 n/a n/a n/a n/a n/a

Total 0.96 182 17,951 1:5,900 1:1,300 1:210 1:910 1:140

Rahm et al. (2013) distance estimates

Transport 100 km 0.96 182 62.1 11,300 1:9,300 1:2,100 1:330 1:1,400 1:220

Transport 70 km 0.96 182 43.5 9,620 1:13,000 1:3,000 1:470 1:2,100 1:320

King (2012) distance estimates

Assumptions of King (2012) 5.0 915 25 22,875 1:4,600 1:1,000 1:162 1:710 1:110

a King (2012) assumed a truck volume of 5,440 gal (20,600 L) versus the assumption of 5,300 gal (20,100 L) for the other rows of the table. 

b King (2012) assumed a release rate of 3.4% from truck crashes and an accident rate of 28 crashes per 100 million mi (160 million km). 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-1 

Appendix F. Wastewater Disposal and Reuse 

Supplemental Information 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-2 

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Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-3 

Appendix F. Wastewater Disposal and Reuse 

Supplemental Information 

This appendix provides additional information for context and background to support the 

discussions of hydraulic fracturing wastewater management and treatment in Chapter 8. 

Information in this appendix includes: estimates of volumes of wastewater generated compiled for 

several states in regions where hydraulic fracturing is occurring; an overview of the technologies 

that can be used to treat hydraulic fracturing wastewater; reported and estimated removal 

efficiencies for specific treatment technologies and contaminants of concern; a description of 

common technologies currently in use at centralized waste treatment plants (CWTs) and their 

discharge options; considerations for water reuse in hydraulic fracturing and the necessary water 

quality; and legacy impacts of hydraulic fracturing on publicly owned treatment works (POTWs). 

Discussion is also provided on disinfection byproduct (DBP) formation concerns related to 

hydraulic fracturing. 

F.1. Estimates of Wastewater Production in Regions where Hydraulic 

Fracturing is Occurring 

Table F-1 presents estimated wastewater volumes for several states in areas with hydraulic 

fracturing activity. These data were compiled from production data available in state databases and 

were tabulated by year. For California, data were compiled for Kern County, where about 95% of 

California’s hydraulic fracturing takes place (CCST, 2015b). Production records from Colorado, 

Utah, and Wyoming include the producing formation for each well reported. Data presented for 

these three states include statewide estimates as well as estimates for selected basins that were 

identified in the literature as targets for hydraulic fracturing. Data from New Mexico are available in 

files for three basins (the Permian, Raton, and San Juan) as well as for the state as a whole. 

Results in Table F-1 illustrate some of the challenges associated with obtaining estimates of 

hydraulic fracturing wastewater volumes, especially using publicly available data. Some of the 

estimates likely include volumes from conventional wells that are not hydraulically fractured. For 

example, the well counts for California, Colorado, Utah, and Wyoming were in the thousands or tens 

of thousands at least as early as 2000, several years before the surge of modern hydraulic fracturing 

began in the mid-2000s. The data used for California were from Kern County where hydraulic 

fracturing is conducted, but are not specific to hydraulic fracturing activity. Where producing 

formations are listed, but there is no indication of whether the well was hydraulically fractured, the 

accuracy of the estimates depends on whether hydraulically fractured formations were correctly 

identified based on other information. If formations (and the associated wells) were inadvertently 

omitted, the volumes will be underestimates.
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-4 

Table F-1. Estimated volumes (millions of gallons) of wastewater based on state data for selected years and numbers of wells 

producing fluid. The wastewater is likely associated with an unknown combination of wells not hydraulically fractured and some 

hydraulically fractured. 

State Basin Principal 

lithologies

Data 

type

2000 2004 2008 2010 2011 2012 2013 2014 Comments

California San 

Joaquina

Shale, 

unconsolidated sands

Produced 

water

46,000 48,000 58,000 65,000 71,000 75,000 74,000 - Data from CA Department of 

Conservation, Oil and Gas 

Division.a Produced water 

data compiled for Kern 

County. Data may also 

represent contributions from 

production without hydraulic 

fracturing. Not specified 

whether flowback is 

included.

-

Wells 33,695 39,088 46,519 49,201 51,031 51,567 52,763 -

-

Colorado All basins 

with hydraulically 

fractured 

formations

- Produced 

water

7,300 11,000 21,000 14,000 12,000 12,000 7,700 - Data from CO Oil and Gas 

Conservation Commission.b

Produced water includes 

flowback. Data filtered for 

formations indicated in 

literature as undergoing 

hydraulic fracturing and 

matched to corresponding 

basins. Example basins

selected for presentation as 

well as estimated state total. 

Wells 11,264 14,934 28,282 33,929 35,999 38,371 37,618 -

Denver Sandstone, 

shale

Produced 

water

140 160 170 160 160 150 110 -

Wells 1,829 1,511 1,277 1,204 1,193 1,131 1,072 -
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-5 

State Basin Principal 

lithologies

Data 

type

2000 2004 2008 2010 2011 2012 2013 2014 Comments

Colorado, 

cont.

Piceance Sandstone Produced 

water

3,500 5,800 9,300 6,900 6,500 6,800 4,300 -

Wells 1,134 2,478 6,486 9,105 10,057 10,868 10,954 -

Raton Coalbed 

methane

Produced 

water

2,400 4,100 8,900 4,300 3,200 2,700 2,100 -

Wells 681 1,634 2,795 2,734 2,778 2,710 2,545 -

San Juan Coalbed 

methane

Produced 

water

1,000 1,100 1,300 2,000 1,200 1,100 650 -

Wells 1,183 1,605 1,975 2,220 2,308 2,328 2,333 -

New Mexico Permian Shale, 

sandstone

Produced 

water 

- - - - - 31,000 31,000 20,000 Data from New Mexico Oil 

Conservation Division.c Data 

provided by the state broken 

out by basin. Unclear how 

much contribution from 

production without hydraulic 

fracturing. Produced water 

includes flowback. 

Wells - - - - - 29,839 30,386 30,287

Raton Coalbed 

methane

Produced 

water

- - - - - 510 540 310

Wells - - - - - 1,495 1,502 1,526

San Juan Coalbed 

methane

Produced 

water

- - - - - 1,700 2,000 1,100

Wells - - - - - 22,492 22,349 22,076
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F-6 

State Basin Principal 

lithologies

Data 

type

2000 2004 2008 2010 2011 2012 2013 2014 Comments

New 

Mexico, 

cont.

Total - Produced 

water

- - - - - 33,000 34,000 22,000

Wells - - - - - 53,826 54,237 53,889

Utah All basins 

with hydraulically 

fractured 

formations

- Produced 

water

1,200 1,200 2,300 2,400 2,700 2,900 3,400 2,800 Data from State of Utah Oil 

and Gas Program.d Produced 

water may or may not 

include flowback. Data 

filtered by formation 

indicated in the literature as 

hydraulically fractured and 

matched to basins. Data 

presented for selected basins 

as well as for all formations 

likely to be hydraulically 

fractured. 

Wells 3,080 4,377 7,409 8,432 9,101 10,075 10,661 10,900

Kaiparowits/ UintaCoalbed 

methane

Produced 

water

860 740 1,300 1,400 1,800 2,000 2,400 1,900

Wells 1,718 2,517 3,761 4,329 4,838 5,538 6,046 6,334

San Juan/ 

Uinta

Coalbed 

methane

Produced 

water

2 49 350 270 240 230 190 120

Wells 62 223 910 933 959 951 867 870

Uinta Shale/sandstoneProduced 

water

350 420 560 680 700 640 830 790

Wells 1,067 1,396 2,282 2,745 2,888 3,115 3,257 3,223
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F-7 

State Basin Principal 

lithologies

Data 

type

2000 2004 2008 2010 2011 2012 2013 2014 Comments

Wyoming All basins 

with hydraulically 

fractured 

formations

- Produced 

water

1,300 1,400 1,300 1,500 1,600 1,700 1,600 1,800 Data from Wyoming Oil and 

Gas Conservation 

Commission.e Produced 

water may include flowback. 

Data filtered by formation 

indicated in the literature as 

hydraulically fractured and 

matched to basins. Data 

presented for selected basins 

as well as for all formations 

likely to be hydraulically 

fractured.

Wells 3,470 3,378 3,585 3,620 3,728 3,843 4,030 4,213

Big Horn Sandstone Produced 

water

380 350 350 380 430 440 420 440

Wells 365 359 387 397 412 414 407 403

Denver Sandstone Produced 

water

54 44 49 59 76 90 97 170

Wells 142 118 124 140 167 204 230 278

Green River Sandstone/

shale

Produced 

water

0 1 2 8 5 5 9 15

Wells 44 44 60 67 67 59 64 67

Powder 

River

Coalbed 

methane

Produced 

water

690 630 620 660 700 840 970 1,100

Wells 1,953 1,900 2,001 2,028 2,119 2,207 2,352 2,565

Wind River/

Powder 

River

Sandstone/

shale

Produced 

water

130 330 330 400 420 290 110 41
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F-8 

State Basin Principal 

lithologies

Data 

type

2000 2004 2008 2010 2011 2012 2013 2014 Comments

Wyoming, 

cont.

Wind River/

Powder 

River, cont.

Sandstone/

shale, cont.

Wells 966 957 1,013 988 963 959 977 900

a California Department of Conservation, Oil and Gas Division. Oil & Gas – Online Data. Monthly Production and Injection Databases: 

ftp://ftp.consrv.ca.gov/pub/oil/new_database_format/. 

b Colorado Oil and Gas Conservation Commission. Data: Downloads: Production Data: http://cogcc.state.co.us/data2.html#/downloads.

c New Mexico Oil Conservation Division. Production Data. Production Summaries: All Wells Data: http://gotech.nmt.edu/gotech/Petroleum_Data/allwells.aspx.

d Utah Department of Natural Resources. Division of Oil, Gas, and Mining. Data Research Center. Database Download Files: 

http://oilgas.ogm.utah.gov/Data_Center/DataCenter.cfm#production.

e Wyoming Oil and Gas Conservation Commission. Production files by county and year: 

http://wogcc.state.wy.us/productioncountyyear.cfm?Oops=#oops#&RequestTimeOut=6500.
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F.2. Overview of Treatment Processes for Treating Hydraulic Fracturing 

Wastewater 

Treatment technologies discussed in this appendix are classified as basic or advanced. Basic 

treatment technologies are ineffective for reducing total dissolved solids (TDS) and are typically not 

labor intensive. Advanced treatment technologies can remove TDS and/or are complex in nature 

(e.g., energy- and labor-intensive). 

F.2.1. Basic Treatment 

Basic treatment technologies include physical separation, coagulation/oxidation, 

electrocoagulation, sedimentation, and disinfection. These technologies are effective at removing 

total suspended solids (TSS), oil and grease, scale-forming compounds, and metals, and they can 

minimize microbial activity. Basic treatment is typically incorporated in a permanent treatment 

facility (i.e., fixed location), but can also be part of a mobile unit for on-site treatment applications. 

F.2.1.1. Physical Separation 

The most basic treatment needed for oil and gas wastewaters, including those from hydraulic 

fracturing operations, is separation to remove suspended solids and oil and grease. The separation 

method largely depends on the type(s) of resource(s) targeted by the hydraulic fracturing 

operation. Down-hole separation techniques, including mechanical blocking devices and water 

shut-off chemicals (e.g., specialized polymers) to prevent or minimize water flow to the well, may 

be used during production in shale plays containing greater amounts of liquid hydrocarbons. To 

treat water at the surface, separation technologies such as hydrocyclones, dissolved air or induced 

gas flotation systems, media (sand) filtration, and biological aerated filters can remove suspended 

solids and some organics from hydraulic fracturing wastewater. 

Media filtration can also remove hardness and some metals if chemical precipitation (i.e., 

coagulation, lime softening) is also employed (Boschee, 2014). An example of a CWT that uses 

chemical precipitation and media filtration to treat hydraulic fracturing waste is the Water Tower 

Square Gas Well Wastewater Processing Facility in Pennsylvania (Table F-6). One or more of these 

technologies is typically used prior to advanced treatment such as reverse osmosis (RO) because 

advanced treatment processes foul, scale, or otherwise do not operate effectively in the presence of 

TSS, certain organics, and/or some metals and metalloid compounds (Boschee, 2014; Drewes et al., 

2009). The biggest challenge associated with use of these separation technologies is solids disposal 

from the resulting sludge (Igunnu and Chen, 2014). 

F.2.1.2. Coagulation/Oxidation 

Coagulation is the process of agglomerating small, unsettleable particles into larger particles to 

promote settling. Chemical coagulants such as alum, iron chloride, and polymers can be used to 

precipitate TSS, some dissolved solids (except monovalent ions such as sodium and chloride), and 

metals from hydraulic fracturing wastewater. Adjusting the pH using chemicals such as lime or 

caustic soda can increase the potential for some constituents, including dissolved metals, to form 

precipitates. Chemical precipitation is often used in industrial wastewater treatment as a 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-10

pretreatment step to decrease the pollutant loading on subsequent advanced treatment 

technologies; this strategy can save time, money, energy consumption, and the lifetime of the 

infrastructure. 

Processes using advanced oxidation and precipitation have been applied to hydraulic fracturing 

wastewaters in on-site and mobile systems. Hydroxyl radicals generated by cavitation processes 

and the addition of ozone can degrade organic compounds and inactivate micro-organisms. The 

process can also aid in the precipitation of ions that cause hardness and scaling in the treated water 

(e.g., calcium, magnesium). The process can also reduce sulfate and carbonate concentrations in the 

treated water. With the removal of constituents that contribute to scaling, this type of treatment 

can be very effective for on-site reuse of wastewater (Ely et al., 2011). 

The produced solid residuals from coagulation/oxidation processes typically require further 

treatment, such as de-watering (Duraisamy et al., 2013; Hammer and VanBriesen, 2012). 

F.2.1.3. Electrocoagulation 

Electrocoagulation (EC) (Figure F-1) combines the principles of coagulation and electrochemistry 

into one process (Gomes et al., 2009). An electrical current added to the wastewater produces 

coagulants that then neutralize the charged particles, causing them to destabilize, precipitate, and 

settle. EC may be used in place of, or in addition to, chemical coagulation. EC can be effective for 

removal of organics, TSS, and metals, but it is not effective at removing TDS and sulfate 

(Halliburton, 2014). Although it is still considered an emerging technology for unconventional oil 

and gas wastewater treatment, EC has been used in mobile treatment systems to treat hydraulic 

fracturing wastewaters (Halliburton, 2014; Igunnu and Chen, 2014). This technology has the 

potential to cause scaling, corrosion, and bacterial growth (Gomes et al., 2009). 

Figure F-1. Electrocoagulation unit. 

Source: Dunkel (2013). Photo courtesy of Pioneer Natural Resources. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-11

Testing of EC has been performed in the Green River Basin (Halliburton, 2014) and the Eagle Ford 

Shale (Gomes et al., 2009). While showing promising results in some trials, results of these early 

studies have illustrated challenges, with removal efficiencies impacted by factors such as pH and 

salt content. 

F.2.1.4. Sedimentation 

Treatment plants may include sedimentation tanks, clarifiers, or some other form of settling basin 

to allow larger particles to settle out of the water where they can eventually be collected, 

dewatered, and disposed of at a landfill or other approved location. These types of tanks/basins all 

serve the same purpose – to reduce the amount of solids going to subsequent processes (i.e., to 

prevent overload of the media filters). 

F.2.1.5. Disinfection 

Some hydraulic fracturing applications may require disinfection to kill bacteria after treatment and 

prior to reuse or discharge. Chlorine is a common disinfectant. Chlorine dioxide, ozone, or 

ultraviolet light can also be used. This is an important step for reused water because bacteria can 

cause problems for further hydraulic fracturing operations by multiplying rapidly and causing 

build-up in the wellbore, which decreases gas extraction efficiency. 

F.2.2. Advanced Treatment 

Advanced treatment technologies consist of membranes (RO, nanofiltration, ultrafiltration, 

microfiltration, electrodialysis, forward osmosis, and membrane distillation), thermal distillation 

technologies, crystallizers, ion exchange, and adsorption. These technologies are effective for 

removing TDS and/or targeted compounds. They typically require pretreatment to remove solids 

and other constituents that may damage or otherwise impede the technology from operating as 

designed. Advanced treatment technologies can be energy-intensive and are typically employed 

when a purified water effluent is necessary for direct discharge, indirect discharge, or reuse. In 

some instances, these water treatment technologies can use methane generated by the gas well as 

an energy source. Some advanced treatment technologies can be made mobile for on-site treatment. 

F.2.2.1. Membranes 

Pressure-Driven Membrane Processes 

Pressure-driven membrane processes, including microfiltration, ultrafiltration, nanofiltration, and 

RO (Figure F-2), are being used in some settings to treat oil and gas wastewater. These processes 

use hydraulic pressure to overcome the osmotic pressure of the influent waste stream, forcing clean 

water through the membrane (Drewes et al., 2009). Microfiltration and ultrafiltration processes are 

advanced processes that do not reduce TDS but can remove TSS and some metals and organics 

(Drewes et al., 2009). RO and nanofiltration are capable of removing TDS, including anions and 

radionuclides. RO, however, may be limited to treating TDS levels of less than 35,000 mg/L (Shaffer 

et al., 2013; Younos and Tulou, 2005). Boron is not easily removed by RO, achieving less than 50% 

removal at neutral pH (Drewes et al., 2009). 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-12

Figure F-2. Photograph of reverse osmosis system. 

Source: U.S. DOI (2016). 

Osmotic-Driven Membrane Processes 

Forward osmosis, an emerging technology for treating hydraulic fracturing wastewater, uses an 

osmotic pressure gradient across a membrane to draw water from a low osmotic solution (the feed 

water) to a high osmotic solution (the draw solution) (Drewes et al., 2009). The draw solution 

(typically composed of sodium chloride) becomes diluted as more water passes through the 

membrane while the feed side becomes more concentrated. For the diluted draw solution, a 

separation process is employed to further treat the product water and concentrate the sodium 

chloride for reuse. 

Thermally-Drive Membrane Processes

Another emerging technology, membrane distillation, relies on a thermal gradient across a 

membrane surface to volatilize pure water and capture it in the distillate (Drewes et al., 2009). 

Membrane distillation has shown promise in removing heavy metals and boron from wastewaters 

(Camacho et al., 2013). 

F.2.2.2. Electrodialysis 

Electrodialysis relies on electrodes (anode and cathode) and ion exchange membranes to separate 

positively- and negatively-charged contaminants from the feed water (Drewes et al., 2009) (Figure 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-13

F-3). Electrodialysis has been considered for use by the shale gas industry, but is currently not 

widely utilized (ALL Consulting, 2013). TDS concentrations above 15,000 mg/L are difficult to treat 

by electrodialysis (ALL Consulting, 2013), and oil and divalent cations (e.g., calcium, iron, 

magnesium) can foul/scale the membranes (Hayes and Severin, 2012b; Guolin et al., 2008). 

Pretreatment is necessary to avoid membrane scaling (ALL Consulting, 2013; Drewes et al., 2009). 

Figure F-3. Picture of mobile electrodialysis units in Wyoming. 

Source: DOE (2006). Reproduced with permission from ALL Consulting. 

F.2.2.3. Thermal Distillation 

Thermal distillation technologies, such as mechanical vapor recompression (MVR) (Figure F-4) and 

dewvaporation, use liquid-vapor separation by applying heat to the waste stream, vaporizing the 

water to separate out impurities, and condensing the vapor into distilled water (Drewes et al., 

2009; LEau LLC, 2008; Hamieh and Beckman, 2006). MVR and dewvaporation can treat high-TDS 

waters and have been proven in the field as effective for treating oil and gas wastewater (Hayes and 

Severin, 2012b; Drewes et al., 2009). Like RO, these processes are energy-intensive and are used 

when the objective is very clean water (i.e., TDS less than 500 mg/L) for direct/indirect discharge 

or if clean water is needed for reuse. As with membrane processes, scaling is an issue with these 

technologies, and scale inhibitors may be needed for them to operate effectively (Igunnu and Chen, 

2014). 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-14

Figure F-4. Picture of a mechanical vapor recompression unit near Decatur, Texas. 

Source: Drewes et al. (2009). Reproduced with permission. 

CWTs such as the Judsonia Central Water Treatment Facility (Arkansas), Casella-Altela Regional 

Environmental Services (Pennsylvania), and Clarion Altela Environmental Services (Pennsylvania) 

have National Pollutant Discharge Elimination System (NPDES) permits and use MVR or thermal 

distillation for TDS removal. Figure F-5 shows a diagram of the treatment train at another facility, 

the Maggie Spain facility in Texas, which used MVR in its treatment of Barnett Shale wastewater 

(Hayes and Severin, 2012a). 

Figure F-5. Mechanical vapor recompression process design – Maggie Spain Facility. 

Adapted from: Hayes and Severin (2012a). Reproduced with permission. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-15

Crystallizers can be employed at CWTs to treat high-TDS waters or to further concentrate the waste 

stream from a distillation process, reducing residual waste disposal volumes. The crystallized salt 

can be landfilled, deep-well injected, or used to produce pure salt products that may be salable 

(Ertel et al., 2013). 

Another thermal method, freeze-thaw evaporation, involves spraying wastewater onto a freezing 

pad, allowing ice crystals to form, and the brine mixture that remains in solution to drain from the 

ice (Drewes et al., 2009). In warmer weather, the ice thaws and the purified water is collected. This 

technology cannot treat waters with high methanol concentrations and is only suitable for areas 

where the temperature is below freezing in the winter months (Igunnu and Chen, 2014). In 

addition, freeze-thaw evaporation can only reduce TDS concentrations to approximately 1,000 

mg/L, which is higher than the 500 mg/L TDS surface water discharge limit required by most 

permits (Igunnu and Chen, 2014). 

F.2.2.4. Ion Exchange and Adsorption 

Ion exchange (Figure F-6) is the process of exchanging ions on a media referred to as resin for 

unwanted ions in the water. Ion exchange is used to treat for target ions that may be difficult to 

remove by other treatment technologies or that may interfere with the effectiveness of advanced 

treatment processes. 

Figure F-6. Picture of a compressed bed ion exchange unit. 

Source: Drewes et al. (2009). Reproduced with permission. 

Adsorption is the process of adsorbing contaminants onto a charged granular media surface.

Adsorption technologies can effectively remove organics, heavy metals, and some anions (Igunnu 

and Chen, 2014). With ion exchange and adsorption processes, the type of resin or adsorptive 

media used (e.g., activated carbon, organoclay, zeolites) dictates the specific contaminants that will 

be removed from the water (Drewes et al., 2009; Fakhru'l-Razi et al., 2009). 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-16

Because they can be easily overloaded by contaminants, ion exchange and adsorption treatment 

processes are generally used as a polishing step following other treatment processes or as a unit 

process in a treatment train rather than as stand-alone treatment (Drewes et al., 2009). Stand-alone 

units require more frequent regeneration and/or replacement of the spent media making these 

technologies more costly to operate (Igunnu and Chen, 2014). The Pinedale Anticline Water 

Reclamation Facility located in Wyoming uses an ion exchange unit with boron-selective resin as a 

polishing step to treat hydraulic fracturing wastewater specifically for boron (Boschee, 2012) 

(Figure F-7). 

F.3. Treatment Technology Removal Capabilities 

Table F-2 provides removal efficiencies for common hydraulic fracturing wastewater constituents 

by treatment technology. With the exception of TSS and TDS, the studies cited demonstrate removal 

for a subset of constituents in a category (e.g., Gomes et al. (2009) reported that electrodialysis was 

an effective treatment for oil and grease, not all organics). The removal efficiencies include ranges 

of 1 to 33% (denoted by +), 34% to 66% (denoted by ++), and greater than 66% removal (denoted 

by +++). Cells denoted with “--" indicate that the treatment technology is not suitable for removal of 

that constituent or group of constituents. If a particular treatment technology only lists removal 

efficiencies for TDS, it can be assumed that, in some cases, cations and anions would also be 

removed by that technology; therefore, where specific results were not provided in literature, cells 

denoted with “Assumed” refer to cations and anions that comprise TDS. 

Table F-2. Removal efficiency of different hydraulic fracturing wastewater constituents using 

various wastewater treatment technologies.a

Hydraulic fracturing wastewater constituents

Treatment 

technology TSS TDS Anions Metals Radionuclides Organics

Hydrocyclones +++

(Duraisamy et 

al., 2013)

-- -- -- -- ++

(Duraisamy et al., 

2013)

Evaporation 

(freeze-thaw 

evaporation)

+++

(Igunnu and 

Chen, 2014; 

Drewes et al., 

2009)

+++

(Igunnu and 

Chen, 2014; 

Drewes et al., 

2009; Arthur 

et al., 2005)

Assumed +++

(Igunnu and 

Chen, 2014; 

Drewes et al., 

2009; Arthur 

et al., 2005)

-- +++

(Igunnu and 

Chen, 2014; 

Duraisamy et al., 

2013; Drewes et 

al., 2009)

Filtration 

(granular media)

+++

(Barrett, 2010)

-- -- +++b

(Duraisamy et 

al., 2013)

-- +++

(Shafer, 2011; 

Drewes et al., 

2009)

Chemical 

precipitation

+++

(Fakhru'l-Razi 

et al., 2009)

-- -- +++

(Fakhru'l-Razi 

et al., 2009;

AWWA, 1999)

+++c

(Zhang et al., 

2014)

+++ 

(Fakhru'l-Razi et 

al., 2009)
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-17

Hydraulic fracturing wastewater constituents

Treatment 

technology TSS TDS Anions Metals Radionuclides Organics

Sedimentation 

(clarifier)

++

(NMSU DACC 

WUTAP, 2007)

-- -- -- -- --

Dissolved air 

flotation 

+++

(Shammas, 

2010)

-- -- -- -- ++/+++

(Duraisamy et al., 

2013; Fakhru'lRazi et al., 2009)

Electrocoagulation +++

(Igunnu and 

Chen, 2014; 

Bukhari, 2008)

-- -- +

(Igunnu and 

Chen, 2014)

-- +++

(Igunnu and 

Chen, 2014; 

Duraisamy et al., 

2013; Fakhru'lRazi et al., 2009)

Advanced 

oxidation and 

precipitation

-- +

(Abrams, 

2013)

-- +/+++

(Abrams, 

2013)

-- +++d

(Duraisamy et al., 

2013; Fakhru'lRazi et al., 2009)

Reverse osmosis -- ++/+++e

(Alzahrani et 

al., 2013; 

Drewes et al., 

2009)

+++

(Alzahrani et 

al., 2013; 

Arthur et al., 

2005)

++/+++f

(Alzahrani et 

al., 2013; 

Drewes et al., 

2009; AWWA, 

1999)

+++

(Drewes et 

al., 2009)

+/++/+++g

(Drewes et al., 

2009; Munter, 

2000)

Membrane 

filtration (UF/MF)

+++

(Arthur et al., 

2005)

-- -- +++

(Fakhru'l-Razi 

et al., 2009)

-- ++/+++

(Duraisamy et al., 

2013; Fakhru'lRazi et al., 2009; 

Hayes and 

Arthur, 2004; 

AWWA, 1999)

h 

Forward osmosis -- +++

(Drewes et al., 

2009)

Assumed Assumed -- --

Distillation, 

including thermal 

distillation (e.g., 

mechanical vapor 

recompression 

(MVR))

+++i

(Hayes et al., 

2014; Bruff 

and Jikich, 

2011; Drewes 

et al., 2009)

+++

(Bruff and 

Jikich, 2011; 

Drewes et al., 

2009)

+++

(Hayes et al., 

2014; Bruff 

and Jikich, 

2011; Drewes 

et al., 2009)

+++

(Bruff and 

Jikich, 2011; 

Drewes et 

al., 2009)

+/++/+++

(Hayes et al., 

2014; Duraisamy 

et al., 2013; 

Drewes et al., 

2009; Fakhru'lRazi et al., 2009)

Ion exchange -- -- +++

(Drewes et 

al., 2009)

+++

(Drewes et al., 

2009; Arthur 

et al., 2005)

+++

(Drewes et 

al., 2009)

+/++/+++

(Fakhru'l-Razi et 

al., 2009; 

Munter, 2000)

j
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-18

Hydraulic fracturing wastewater constituents

Treatment 

technology TSS TDS Anions Metals Radionuclides Organics

Crystallization -- +++

(ER, 2014)

Assumed Assumed -- --

Electrodialysis -- +++k

(Drewes et al., 

2009; Gomes 

et al., 2009; 

Arthur et al., 

2005)

++/+++

(Banasiak and 

Schäfer, 

2009)

+/++/+++

(Banasiak and 

Schäfer, 2009)

-- --

Capacitive 

deionization 

(emerging 

technology)

-- +++l

(Drewes et al., 

2009)

-- -- -- --

Adsorptionm -- -- +/++/+++n

(HabudaStanic et al., 

2014)

+++

(Igunnu and 

Chen, 2014; 

Drewes et al., 

2009)

-- +/++/+++

(Arthur et al., 

2005; Hayes and 

Arthur, 2004; 

Munter, 2000)

Biological 

treatment

+++

(Igunnu and 

Chen, 2014; 

Drewes et al., 

2009)

-- -- -- -- +/++/+++

(Igunnu and 

Chen, 2014; 

Drewes et al., 

2009; Fakhru'lRazi et al., 2009)

Constructed 

wetland/reed 

beds

++/+++

(Manios et al., 

2003)

+

(Arthur et al., 

2005)

-- ++/+++

(Fakhru'l-Razi 

et al., 2009)

-- +/ +++

(Fakhru'l-Razi et 

al., 2009; Arthur 

et al., 2005)

a To the extent possible, removal efficiencies are based on an individual treatment technology that does not assume extensive 

pretreatment or combined treatment processes. However, it should be noted that some processes such as RO, media filtration, 

and sedimentation cannot effectively operate without pretreatment.

b Pretreatment (pH adjustment, aeration, solids separation) required.

c Radium co-precipitation with barium sulfate.

d The Fenton process.

e Typically requires pretreatment. Not a viable technology if TDS influent >50,000 mg/L.

f

Iron and manganese oxides will foul the membranes.

g Some organics will foul the membranes (e.g., organic acids).

h Ultrafiltration membrane was modified with nanoparticles.

i Can typically handle high TDS concentrations.

j Resin consisted of modified zeolites that targeted removal of BTEX.

k

Influent TDS for this technology should be <8,000 mg/L.

l Specific technology was an electronic water purifier which is a hybrid of capacitive deionization. Influent TDS for this 

technology should be <3,000 mg/L.

m Typically polishing step, otherwise can overload bed quickly with organics.

n Removal efficiency is dependent on the type of adsorbent used and the water quality characteristics (e.g., pH).
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-19

F.3.1. Estimated Treatment Removal Efficiencies 

There are relatively few studies that have evaluated the ability of individual treatment processes to 

remove constituents from hydraulic fracturing wastewater and reported the resulting water 

quality. Furthermore, although a specific technology may demonstrate a high removal percentage 

for a particular constituent, if the influent concentration of that constituent is extremely high, the 

constituent concentration in the treated water may still exceed permit limits and/or disposal 

requirements. Table F-3 presents estimated effluent concentrations that could be produced by a 

variety of unit treatment processes for several example constituents and for various influent 

concentrations. This analysis uses simple calculations pairing average hydraulic fracturing 

wastewater concentrations from Chapter 7 and Appendix E with treatment process removal 

efficiencies reported in the literature in Table F-2. This analysis is intended to highlight the 

potential impacts of influent concentration on treatment outcome and to illustrate the relative 

capabilities of various treatment processes for an example set of constituents. The removal 

efficiencies represent a variety of studies (primarily at bench and pilot scale) that have been 

conducted using either conventional or hydraulic fracturing wastewater. Removal efficiency for a 

given treatment process can vary due to a number of factors, and constituent removal may be 

different in a full-scale facility that uses several processes. Thus, the calculations shown in Table F-3

are intended to be rough approximations for illustrative purposes. 

As an example, radium in wastewater from the Marcellus Shale and Upper Devonian sandstones can 

be in the thousands of pCi/L. With a 95% removal rate, chemical precipitation may result in effluent 

that still exceeds 100 pCi/L. Distillation and RO might produce effluent with concentrations in the 

tens of pCi/L. A radium concentration of 120 pCi/L, however, could be reduced to less than 5 pCi/L 

by RO or distillation. Wastewater with barium concentrations in the range of 140 – 160 mg/L (e.g., 

the Cotton Valley and Mesaverde tight sands) might be reduced to concentrations under 5 mg/L by 

distillation and roughly 11 – 13 mg/L by RO. Barium concentrations in the thousands of mg/L 

would be substantially reduced by any of several processes, but might still be relatively high, 

potentially exceeding 100 mg/L. Table F-3 also illustrates the potential for achieving low 

concentrations of organic compounds in wastewater treated with freeze-thaw evaporation or 

advanced oxidation and precipitation. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-20

Table F-3. Estimated effluent concentrations for example constituents based on treatment process removal efficiencies. 

Shale/

sandstone 

play

Contaminant

Units 

(for all 

entries)

MCL 

Avg.

influent 

conc.

Freeze-thaw 

evaporation

Media filtration

Chemical precipitation

Flotation (DAF)

Electro-coagulation

Advanced 

oxidation and 

precipitation

Reverse osmosis

Membrane filtration 

(UF/MF)

Distillation

Ion exchange

Electrodialysis

Adsorption

Biological treatment 

(biodisks, BAFs)

Constructed 

wetland

Bakken Barium mg/L 2 10 1 0.44 0.8 0.1 –

0.03

ND –

0.7 2.2

Barnett Barium mg/L 2 3.6 0.4 0.16 0.29 0.0036 

– 0.11

ND –

0.3 0.8

Fayetteville Barium mg/L 2 4 0.4 0.18 0.32 0.04 –

0.12

ND –

0.3 0.9

Marcellus Barium mg/L 2 2200 220 98 180 22 –

67

ND –

160 490

Cotton Valley Barium mg/L 2 160 16 7 13 1.6 –

4.8

ND –

11 35

Mesa Verde Barium mg/L 2 140 14 6.1 11 1.4 –

4.2

ND –

9.7 31

Marcellus Cadmium μg/L 5 25 2.5 2.5 13 5 15

Bakken Strontium mg/L -- 760 76 7.6 –

23 53

Barnett Strontium mg/L -- 530 53 5.3 –

16 37

Fayetteville Strontium mg/L -- 27 2.7 0.27 –

0.81 1.9

Marcellus Strontium mg/L -- 1700 170 17 –

51 120

Cotton Valley Strontium mg/L -- 2300 230 23 –

69 160
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-21

Shale/

sandstone 

play

Contaminant

Units 

(for all 

entries)

MCL 

Avg.

influent 

conc.

Freeze-thaw 

evaporation

Media filtration

Chemical precipitation

Flotation (DAF)

Electro-coagulation

Advanced 

oxidation and 

precipitation

Reverse osmosis

Membrane filtration 

(UF/MF)

Distillation

Ion exchange

Electrodialysis

Adsorption

Biological treatment 

(biodisks, BAFs)

Constructed 

wetland

Devonian 

Sandstone Strontium mg/L -- 3900 390 39 –120 270

Marcellus Radium 226 pCi/L -- 620 32 –

440 6.2 6.2 –19 44

Devonian 

Sandstone Radium 226 pCi/L -- 2400 120 –1700 24 24 –71 170

Marcellus Radium 228 pCi/L -- 120 6.2 –

85 1.2 1.2 –3.6 8.4

Marcellus Total radium pCi/L 5 2500 130 –

1800 25 25 –76 180

Barnett TOC pCi/L -- 9.8 0.2 0.9 –

2.9 2.1 – 4 1

Marcellus TOC pCi/L -- 160 3.2 16 –

48

35 –

58 16

Cotton Valley TOC mg/L -- 200 4

20 –

59

44 –

71 20

Barnett BOD mg/L -- 580 58 290 –

440

29 –

87 47

Marcellus BOD mg/L -- 40 4

20 –

30 2 – 6 3.2

Barnett Oil and grease mg/L -- 160 16 16 8 1.6 43 9.8

Marcellus Oil and grease mg/L -- 74 7.4 7.4 3.7 0.74 19 4.4

Barnett Benzene μg/L 5 680 68 310 6.8 110 ND

Marcellus Benzene μg/L 5 360 36 170 3.6 58 ND
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-22

Shale/

sandstone 

play

Contaminant

Units 

(for all 

entries)

MCL 

Avg.

influent 

conc.

Freeze-thaw 

evaporation

Media filtration

Chemical precipitation

Flotation (DAF)

Electro-coagulation

Advanced 

oxidation and 

precipitation

Reverse osmosis

Membrane filtration 

(UF/MF)

Distillation

Ion exchange

Electrodialysis

Adsorption

Biological treatment 

(biodisks, BAFs)

Constructed 

wetland

Barnett Toluene μg/L 1,000 760 76 350 84 ND

Marcellus Toluene μg/L 1,000 1100 110 510 120 ND

Barnett Ethylbenzene μg/L 700 29 2.9 17 3.2 ND

Marcellus Ethylbenzene μg/L 700 150 15 90 17 ND

Barnett Xylenes μg/L 10,000 360 36 170 14 ND

Marcellus Xylenes μg/L 10,000 1300 130 600 52 ND

Barnett BTEX μg/L -- 1800 180 7.3 91 270 –

550

3.7 –

91

Marcellus BTEX μg/L -- 2900 290 12 150 440 –

870

5.8 –

150

Barnett Naphthalene μg/L -- 240 0.95

Marcellus Naphthalene μg/L -- 360 1.4

Barnett 1,2,4-Trimethylbenzene μg/L -- 170 0.69

Marcellus 1,2,4-Trimethylbenzene μg/L -- 430 1.7

Barnett 1,2,4-Trimethylbenzene μg/L -- 59 0.24

Marcellus 1,2,4-Trimethylbenzene μg/L -- 310 1.2

ND = Non-detect
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-23

F.4. Treatment for Constituents of Concern 

Constituents of concern in hydraulic fracturing wastewater include TSS, TDS, anions (e.g., chloride, 

bromide, and sulfate), metals, radionuclides, and organic compounds (see Section 8.3 and Chapter 

7). If the end use of the wastewater necessitates treatment, a variety of technologies can be 

employed to remove or reduce the constituent concentrations. 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 literature (both conventional and unconventional) and the specific 

technology(ies) used to remove them. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-24

Table F-4. Studies of removal efficiencies and influent/effluent data for various processes and facilities. 

Location and results

Constituents 

of concern

Pinedale Anticline 

Water Reclamation 

Facility, Wyoming

(Shafer, 2011)

Maggie Spain WaterRecycling Facility, 

Barnett Shale, Texas

(Hayes et al., 2014)

Judsonia, Sunnydale, 

Arkansas 

(U.S. EPA, 2015e)

9-month study treating 

Marcellus Shale waste 

using thermal 

distillation 

(Boschee, 2014; Bruff 

and Jikich, 2011)

San Ardo Water 

Reclamation Facility, San 

Ardo, California 

(conventional oil and gas) 

(Dahm and Chapman, 

2014; Webb et al., 2009)

TSS Results not reported. 90% 

Inf. = 1,272 mg/L

Eff. = 9 mg/L

Chemical oxidation, 

coagulation, and 

clarification

No influent data.

Eff.: <4 mg/L

Meets NPDES Permit 

Settling, biological 

treatment, and induced 

gas flotation

>90% 

Inf.: 35 to 114 mg/L

Eff.: <3 to 3 mg/L

100 micron mesh bag filter 

Results not reported.

TDS >99%

Inf. = 8,000 to 15,000 

mg/L

Eff. = 41 mg/L

RO

99.7% 

Inf. = 49,550 mg/L

Eff. = 171 mg/L

MVR (3 units in parallel)

Results not reported. 

MVR

98% 

Inf.: 22,350 to 37,600 

mg/L

Eff.: 9 to 400 mg/L

Thermal distillation

97% 

Inf. = 7,000 mg/L

Eff. = 180 mg/L

Ion exchange softening and 

double-pass RO
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-25

Location and results

Constituents 

of concern

Pinedale Anticline 

Water Reclamation 

Facility, Wyoming

(Shafer, 2011)

Maggie Spain WaterRecycling Facility, 

Barnett Shale, Texas

(Hayes et al., 2014)

Judsonia, Sunnydale, 

Arkansas 

(U.S. EPA, 2015e)

9-month study treating 

Marcellus Shale waste 

using thermal 

distillation 

(Boschee, 2014; Bruff 

and Jikich, 2011)

San Ardo Water 

Reclamation Facility, San 

Ardo, California 

(conventional oil and gas) 

(Dahm and Chapman, 

2014; Webb et al., 2009)

Anions Chloride: >99% 

Inf. = 3,600 to 6,750 mg/L

Eff. = 18 mg/L

RO

Sulfate: 99% 

Inf. = 10 to 100 mg/L

Eff. = non-detect

Clarification and filtration

Sulfate: 98% 

Inf. = 309 mg/L

Eff. = 6 mg/L

Chemical oxidation, 

coagulation, clarification, 

and MVR

Sulfate:

No influent data.

Eff.: 12 mg/L

Meets NPDES Permit 

MVR

Bromide: >99% 

Inf.: 101 to 162.5 mg/L

Eff.: <0.1 to 1.6 mg/L

Chloride: 98%

Inf.: 9,760 to 16,240 mg/L

Eff.: 2.9 to 184.2 mg/L

Sulfate: 93% 

Inf.: 20.4 to <100 mg/L

Eff.: <1 to 2.2 mg/L

Fluoride: 96% 

Inf.: <2 to <20 mg/L

Eff.: <0.2 to 0.42 mg/L

Thermal distillation

Chloride: >99% 

Inf. = 3,400 mg/L

Eff. = 11 mg/L

Double-pass RO

Sulfate: 6% 

Inf. = 133 mg/L

Eff. = 125 mg/L

Sulfuric acid is added after 

RO to neutralize the pH so 

no sulfate removal is 

expected.
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-26

Location and results

Constituents 

of concern

Pinedale Anticline 

Water Reclamation 

Facility, Wyoming

(Shafer, 2011)

Maggie Spain WaterRecycling Facility, 

Barnett Shale, Texas

(Hayes et al., 2014)

Judsonia, Sunnydale, 

Arkansas 

(U.S. EPA, 2015e)

9-month study treating 

Marcellus Shale waste 

using thermal 

distillation 

(Boschee, 2014; Bruff 

and Jikich, 2011)

San Ardo Water 

Reclamation Facility, San 

Ardo, California 

(conventional oil and gas) 

(Dahm and Chapman, 

2014; Webb et al., 2009)

Metals Boron: 99% 

Inf. = 15 to 30 mg/L

Eff. = non-detect

Ion exchange

Iron: >99% 

Inf. = 28 mg/L

Eff. = 0.1 mg/L

For iron, 90% attributed to 

chemical oxidation, 

coagulation, and 

clarification

Boron: 98% 

Inf. = 17 mg/L

Eff. = 0.4 mg/L

Barium: >99% 

Inf. = 15 mg/L

Eff. = 0.1 mg/L

Calcium: >99%

Inf. = 2,916 mg/L

Eff. = 3.2 mg/L

Magnesium: >99%

Inf. = 316 mg/L

Eff. = 0.4 mg/L 

Cobalt:

No influent data.

Eff.: <0.007 mg/L

Arsenic:

No influent data.

Eff.: <0.001 mg/L

Cadmium:

No influent data.

Eff.: <0.0001 mg/L

Chromium:

No influent data.

Eff.: <0.007 mg/L 

Copper:

No influent data.

Eff.: <0029 mg/L 

Lead:

No influent data.

Eff.: <0.001 mg/L

Copper: >99% 

Inf. = <0.2 to <1.0 mg/L

Eff. = <0.02 to <0.08 mg/L

Zinc: inf below detect

Inf. = <0.2 to <1.0 mg/L

Eff. = <0.02 to 0.05 mg/L

Barium: >99%

Inf. = 260.5 to 405.5 mg/L

Eff. = <0.1 to 4.54 mg/L

Strontium: 98%

Inf. = 233 to 379 mg/L

Eff. = 0.026 to 3.93 mg/L

Iron:

Inf. = 13.9 to 22.9 mg/L

Eff. = <0.02 to 0.06 mg/L 

Boron: 97%

Inf. = <1 to 3.12 mg/L

Eff. = 0.02 to 0.06 mg/L

Sodium: 98%

Inf. = 2,300 mg/L

Eff. = 50 mg/L

Boron: >99% 

Inf. = 26 mg/L

Eff. = 0.1 mg/L

RO with elevated influent 

pH
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-27

Location and results

Constituents 

of concern

Pinedale Anticline 

Water Reclamation 

Facility, Wyoming

(Shafer, 2011)

Maggie Spain WaterRecycling Facility, 

Barnett Shale, Texas

(Hayes et al., 2014)

Judsonia, Sunnydale, 

Arkansas 

(U.S. EPA, 2015e)

9-month study treating 

Marcellus Shale waste 

using thermal 

distillation 

(Boschee, 2014; Bruff 

and Jikich, 2011)

San Ardo Water 

Reclamation Facility, San 

Ardo, California 

(conventional oil and gas) 

(Dahm and Chapman, 

2014; Webb et al., 2009)

Metals, cont. Sodium: >99%

Inf. = 10,741 mg/L

Eff. = 14.3 mg/L

Strontium: >99%

Inf. = 505 mg/L

Eff. = 0.5 mg/L

MVR

Mercury:

No influent data.

Eff.: <0.005 mg/L

Zinc:

No influent data.

Eff.: 0.02 mg/L

Meets NPDES permit 

except for TMDLs for 

hexavalent chromium and 

mercury

Settling, biological 

treatment, induced gas 

flotation, and MVR

Calcium: 98%

Inf. = 1,175 to 1,933 mg/L

Eff. = 0.36 to 22.2 mg/L

Sodium: 98%

Inf. = 4,712 to 7,781 mg/L

Eff. = 0.37 to 87.9 mg/L

Arsenic: 82%

Inf. = <0.01 to 0.028 mg/L

Eff. = <0.005 mg/L 

Thermal distillation
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-28

Location and results

Constituents 

of concern

Pinedale Anticline 

Water Reclamation 

Facility, Wyoming

(Shafer, 2011)

Maggie Spain WaterRecycling Facility, 

Barnett Shale, Texas

(Hayes et al., 2014)

Judsonia, Sunnydale, 

Arkansas 

(U.S. EPA, 2015e)

9-month study treating 

Marcellus Shale waste 

using thermal 

distillation 

(Boschee, 2014; Bruff 

and Jikich, 2011)

San Ardo Water 

Reclamation Facility, San 

Ardo, California 

(conventional oil and gas) 

(Dahm and Chapman, 

2014; Webb et al., 2009)

Radionuclides Results not reported. Results not reported. Not regulated under 

permit – believed to be 

absent.

Radium-226: 97% - 99% 

Inf. = 130 to 162 pCi/L

Eff. = 0.224 to 2.87 pCi/L

Radium-228: 97% - 99%

Inf. = 45 to 85.5 pCi/L

Eff. = 0.259 to 1.32 pCi/L

Gross Alpha: 97% - >99%

Inf. = 161 to 664 pCi/L

Eff. = 0.841 to 6.49 pCi/L

Gross Beta: 98% - >99%

Inf. = 79.7 to 847 pCi/L

Eff. = 0.259 to 1.57 pCi/L

Thermal distillation

Results not reported.
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-29

Location and results

Constituents 

of concern

Pinedale Anticline 

Water Reclamation 

Facility, Wyoming

(Shafer, 2011)

Maggie Spain WaterRecycling Facility, 

Barnett Shale, Texas

(Hayes et al., 2014)

Judsonia, Sunnydale, 

Arkansas 

(U.S. EPA, 2015e)

9-month study treating 

Marcellus Shale waste 

using thermal 

distillation 

(Boschee, 2014; Bruff 

and Jikich, 2011)

San Ardo Water 

Reclamation Facility, San 

Ardo, California 

(conventional oil and gas) 

(Dahm and Chapman, 

2014; Webb et al., 2009)

Organics Oil & Grease: 99%

Inf. = 50 to 2,400 mg/L

Eff. = non-detect

BTEX: 99%

Inf. = 28 to 80 mg/L

Eff. = non-detect

GRO: 99%

Inf. = 88 to 420 mg/L

Eff. = non-detect

DRO: 99%

Inf. = 77 to 1,100 mg/L

Eff. = non-detect

Methanol: 99%

Inf. = 40 to 1,500 mg/L

Eff. = non-detect

Oil-water separator, 

anaerobic and aerobic 

biological treatment, 

coagulation, flocculation, 

flotation, sand filtration, 

membrane bioreactor, 

and ultrafiltration

TPH: >80% 

Inf. = 388 mg/L

Eff. = 4.6 mg/L

BTEX: 94% 

Inf. = 3.3 mg/L

Eff. = 0.2 mg/L

TOC: 48% 

Inf. = 42 mg/L

Eff. = 22 mg/L

Coagulation, 

sedimentation, MVR 

Biochemical oxygen 

demand:

No influent data.

Eff.: <2 mg/L

Oil & Grease:

No influent data.

Eff.: <5 mg/L

Benzo (k) fluoranthene:

No influent data.

Eff.: <0.005 mg/L

Bis (2-Ethylhexyl) 

Phthalate:

No influent data.

Eff.: <0.001 mg/L

Butyl benzyl phthalate:

No influent data.

Eff.: <0.001 mg/L

Meets NPDES permit 

Settling, biological 

treatment, induced gas 

flotation, and MVR

Acetone: 93% 

Inf. = 8.71 to 13.8 mg/L

Eff. = 0.524 to 0.949 mg/L

Toluene: >80% 

Inf. = 0.0083 to 0.0015 

mg/L

Eff. = non-detect to 0.0013 

mg/L

Methane: >99% 

Inf. = 0.748 to 5.49 mg/L

Eff. = non-detect to 0.0013 

mg/L

DRO: 0 to 82% 

Inf. = 4 to 7.1 mg/L

Eff. = 0.99 to 4.9 mg/L

Oil & Grease: No removal

Thermal distillation 

Results not reported. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-30

F.4.1. Total Suspended Solids 

The reduction of TSS is typically required before wastewater can be reused for subsequent 

hydraulic fracturing jobs. Hydraulic fracturing wastewaters containing suspended solids can plug 

the well and damage equipment if reused for other fracturing operations (Tiemann et al., 2014; 

Hammer and VanBriesen, 2012). For treated water that is discharged to a surface water body, the 

EPA has a secondary treatment standard for POTWs that limits TSS in the effluent to 30 mg/L (30-

day average). In addition, most advanced treatment technologies require the removal of TSS prior 

to treatment to avoid operational problems, such as membrane fouling/scaling, and to extend the 

life of the treatment unit. 

TSS removal efficiencies shown in Table F-4 (90% and over 90%) were achieved with chemical 

oxidation, coagulation, and clarification, as well as filtration. Technologies that remove TSS have 

also been employed in another Marcellus Shale study (sedimentation and filtration) (Mantell, 

2013); Utica Shale (chemical precipitation and filtration) (Mantell, 2013); Barnett Shale (chemical 

precipitation and inclined plate clarifier, >90% removal) (Hayes et al., 2014); and Utah (EC, 90% 

removal) (Halliburton, 2014). 

F.4.2. Total Dissolved Solids 

The TDS concentration of hydraulic fracturing wastewater is a key treatment consideration, with 

the required level of TDS removal dependent upon the intended use of the treatment effluent. 

POTW treatment and basic treatment processes at a CWT (i.e., chemical precipitation, 

sedimentation, and filtration) are typically not reliable methods for removing TDS. Reduction 

requires more advanced treatment processes such as RO, nanofiltration, thermal distillation 

(including MVR), evaporation, and/or crystallization (Olsson et al., 2013; Boschee, 2012; Drewes et 

al., 2009). Pretreatment (e.g., chemical precipitation, flotation, etc.) is typically needed to remove 

constituents that may cause fouling or scaling with the advanced treatment processes or to remove 

specific constituents not removed by a particular advanced process. TDS removal efficiencies 

reported in Table F-4 ranged from 97% to >99% with RO, thermal distillation, MVR, and ion 

exchange softening with a double pass RO. 

RO and thermal distillation processes can treat waste streams with TDS concentrations up to 

35,000 mg/L and more than 100,000 mg/L, respectively (Tiemann et al., 2014). Extremely high TDS 

waters may require a series of advanced treatment processes to remove TDS to desired levels. 

However, the cost of treating high-TDS waters may preclude facilities from choosing treatment if 

other options, such as deep well injection, are available and more cost-effective (Tiemann et al., 

2014). 

F.4.3. Anions 

Although chemical precipitation processes can reduce concentrations of multivalent anions such as 

sulfate, monovalent anions (e.g., bromide and chloride) are not removed by basic treatment 

processes and require more advanced treatment such as RO, thermal distillation (including MVR), 

evaporation, and/or crystallization (Hammer and VanBriesen, 2012). As shown in Table F-4, anion 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-31

removal efficiencies in the four studies where sulfate removal was measured ranged from 93% to 

>99%. 

F.4.4. Metals and Metalloids 

Removal of dissolved and precipitated metals and metalloids is commonly needed prior to 

discharge to a waterbody or reuse. The facilities in Table F-4 report removals of 98%–99% for a 

number of metals. Other work demonstrating effective removal includes a 99% reduction in barium 

using chemical precipitation (Marcellus Shale region) (Warner et al., 2013a) and over 90% boron 

removal with RO (at pH of 10.8) at two California facilities (Webb et al., 2009; Kennedy/Jenks 

Consultants, 2002). However, influent concentration must be considered together with removal 

efficiency to determine whether effluent quality meets the requirements dictated by end use or by 

regulations. In the case of the facility described by Kennedy/Jenks Consultants (2002), the boron 

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. 

F.4.5. Radionuclides 

Data on radionuclide removals achieved in active treatment plants are scarce. The literature does 

provide some data from the Marcellus Shale region on use of distillation and chemical precipitation 

(co-precipitation of radium with barium sulfate). As shown in Table F-4, one nine-month pilot scale 

study conducted by Bruff and Jikich (2011) reported that distillation treatment produced removal 

efficiencies between 97% and >99% for radium, gross alpha, and gross beta, and 71% to 90% for 

thorium. In a separate study, Warner et al. (2013b) reported that a CWT was estimated to have 

achieved over 99% removal of radium via co-precipitation of radium with barium sulfate (radium 

226 influent of 3231 pCi/L and effluent of 4 pCi/L; radium 228 influent of 452 pCi/L and effluent of 

2 pCi/L). However, in both studies, radionuclides were detected in effluent samples, and the CWT 

was discharging to a surface water body during this time (Warner et al., 2013b; Bruff and Jikich, 

2011) (Section 8.5.2). Between 2010 and 2012, samples of wastewater effluent from a western 

Pennsylvania CWT contained a mean radium level of 4 pCi/L (Warner et al., 2013a). 

F.4.6. Organics 

Facilities have demonstrated the capability to treat for organic compounds in hydraulic fracturing 

wastewaters. Table F-4 shows that one facility achieved 99% removal of oil and grease, BTEX 

(benzene, toluene, ethylbenxene, xylenes), gasoline range organics (GRO), diesel range organics 

(DRO), and methanol while another facility reported >80% removal of total petroleum 

hydrocarbons (TPH), 94% removal of BTEX, and 48% removal of total organic carbon (TOC). 

Given the variety of properties among classes of organic constituents, different treatment processes 

may be required depending upon the types of organic compounds needing removal. Table F-5 lists 

treatment processes and the classes of organic compounds they can treat. It should be noted that in 

many studies, rather than testing for several organic constituents, researchers often measure 

organics in terms of biochemical oxygen demand and/or chemical oxygen demand, which are 

indirect measures of the amount of organic compounds in the water. Organic compounds may also 

be measured and/or reported in groupings such as TPH (which includes GRO, DRO, oil and grease), 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-32

volatile organic compounds (VOCs) (which include BTEX), and semi-volatile organic compounds 

(SVOCs). 

Table F-5. Treatment processes for hydraulic fracturing wastewater organic constituents. 

Treatment processes Organic compounds removed References

Adsorption with activated carbon Soluble organic compounds Fakhru'l-Razi et al. (2009)

Adsorption with organoclay media Insoluble organic compounds Fakhru'l-Razi et al. (2009)

Air stripping Volatile organic compounds Tchobanoglous et al. (2013)

Dissolved air flotation Volatile organic compounds, dispersed oil Drewes et al. (2009)

Freeze/thaw evaporationa TPH, volatile organic compounds, semivolatile organic compoundsDuraisamy et al. (2013); Drewes 

et al. (2009)

Ion exchange (with modified 

zeolites)

BTEX, chemical oxygen demand, 

biochemical oxygen demand

Hayes et al. (2014); Duraisamy et 

al. (2013); Drewes et al. (2009); 

Fakhru'l-Razi et al. (2009); 

Munter (2000)

Distillation BTEX, polycyclic aromatic hydrocarbons 

(PAHs)

Hayes et al. (2014); Duraisamy et 

al. (2013); Drewes et al. (2009); 

Fakhru'l-Razi et al. (2009).

Chemical precipitation Oil & grease Drewes et al. (2009); Fakhru'lRazi et al. (2009)

Chemical Oxidation Oil & grease Drewes et al. (2009); Fakhru'lRazi et al. (2009)

Media filtration (walnut shell 

media or sand)

Oil & grease Drewes et al. (2009); Fakhru'lRazi et al. (2009)

Microfiltration Oil & grease Drewes et al. (2009); Fakhru'lRazi et al. (2009)

Ultrafiltration Oil & grease, BTEX Drewes et al. (2009); Fakhru'lRazi et al. (2009)

Reverse osmosisb Dissolved organics Drewes et al. (2009); U.S. EPA 

(2005)

Electrocoagulation Chemical oxygen demand, Biochemical 

oxygen demand

Fakhru'l-Razi et al. (2009)

Biologically aerated filters Oil & grease, TPH, BTEX Fakhru'l-Razi et al. (2009)

Reed bed technologies Oil & grease, TPH, BTEX Fakhru'l-Razi et al. (2009)

Hydrocyclone separators Dispersed oil Drewes et al. (2009)

a Technology cannot be used if the methanol concentration in the hydraulic fracturing wastewater exceeds 5%.

b RO will remove specific classes of organic compounds with removal efficiencies dependent on the compound’s structure and 

the physical and chemical properties of the hydraulically fractured wastewater. Organoacids will foul membranes.
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-33

F.5. Centralized Waste Treatment Facilities and Waste Management Options 

CWTs are designed to treat for site-specific wastewater constituents so that the effluent meets the 

requirements of the designated disposal option(s) (i.e., reuse, direct/indirect discharge). The most 

basic treatment processes that a CWT might use include (Easton, 2014; Duhon, 2012): 

 Physical treatment technologies such as dissolved air or induced gas flotation systems, 

media filtration, hydrocyclones, and settling including sedimentation/clarification; 

 Chemical treatment technologies such as chemical precipitation (coagulation) and 

chemical oxidation; and 

 Biological treatment technologies such as biological aerated filter systems and reed beds. 

Although these technologies are effective at removing oil and grease, suspended solids, scaleforming compounds, and some heavy metals, advanced processes such as RO, thermal distillation, 

or evaporation are necessary if TDS should be reduced as required by the intended disposal option. 

This section provides an overview of treatment technologies employed at CWTs treating for oil and 

gas wastewaters and their discharge options. 

F.5.1. Design of Treatment Trains for CWTs 

Based on the chemical composition of the hydraulic fracturing wastewater and the desired effluent 

water quality, a series of treatment technologies will most likely be necessary. The possible 

combinations of unit processes combined into treatment trains are extensive. One report identified 

41 different treatment unit processes that have been used in the treatment of oil and gas 

wastewater and 19 unique treatment trains (Drewes et al., 2009). Fakhru'l-Razi et al. (2009) also 

provide examples of process flow diagrams that have been used in pilot-scale and commercial 

applications for treating oil and gas wastewater. Figure F-7 shows the treatment train for the 

Pinedale Anticline Facility as of 2012, which includes pretreatment for dispersed oil, VOCs, and 

heavy metals and advanced treatment for removal of TDS, dissolved organics, and boron. This CWT 

can either discharge to surface water or provide the treated wastewater to operators for reuse. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-34

Figure F-7. Full discharge water process used in the Pinedale Anticline field. 

Source: Redrawn and adapted from a figure in Boschee (2012). 

Table F-6 provides information on some CWTs in locations across the country and the processes 

they employ. The table also notes for each facility whether data on effluent quality are readily 

available. Comprehensive and systematic data on influent and effluent quality from CWTs that treat 

to a variety of water quality levels are difficult to procure. This makes it challenging to understand 

removal efficiencies and resulting effluent quality, especially when a facility offers varying degrees 

of treatment to meet the water quality needs for different end uses (e.g., reuse vs. discharge). For 

those facilities with NPDES permits, discharge monitoring report (DMR) data may be available for 

some constituents, although if the facility does not discharge regularly, these data will be sporadic. 

As of July 2016, the Pinedale Anticline Facility, the Judsonia Facility, the Eureka Resources Standing 

Stone Facility, and Wellington Operating Company’s facility appear to be the only CWTs in Table 

F-6 discharging to surface water or a groundwater aquifer.1 

1

 For Pinedale Anticline Water Reclamation Facility, surface water discharges are permitted under 40 CFR 435 Subpart E 

(beneficial use subcategory agricultural and wildlife water) not 40 CFR 437 (the discharge permit for CWTs). For the 

purposes of this assessment, this facility is included with CWTs. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-35

Table F-6. Examples of centralized waste treatment facilities. 

Facility Locality

Description of 

unit processes

Does CWT have a 

NPDES permit for 

discharge?

Does CWT 

provide 

effluent for 

reuse?

Does CWT have 

advanced 

process for TDS 

removal?

What is the status of 

the facility as of July, 

2016?

Are effluent quality 

data available 

through literature 

search?

Pinedale 

Anticline 

Water 

Reclamation 

Facility

WY Oil/water 

separation, 

biological 

treatment, aeration, 

clarification, sand 

filtration, 

bioreactor, 

membrane 

bioreactor, RO, ion 

exchange, and 

desalinization

No - However, 

facility is permitted 

to discharge under 

40 CFR 435 Subpart 

E (WY0054224). 

Facility is permitted 

to discharge up to 

25% of its effluent 

stream

Yes Yes, RO (Boschee, 

2014, 2012)

The treatment plant 

produces treated water 

for reuse and for 

discharge to outfalls 

located at the New Fork 

River and at Sand Draw. 

Yes – DMR data 

available on Wyoming 

DEQ website. Some 

information can also be 

obtained from Shafer 

(2011). 

SEECO –

Judsonia 

Water Reuse 

Recycling 

Facility

AR Settling, biological 

treatment, induced 

gas flotation, and 

MVR

Yes - AR0052051 Yes Yes, MVR The treatment plant 

provides treated water 

for reuse and for 

discharge to surface 

water. Based on DMR 

data from late 2015-

early 2016, the system is 

discharging treated 

water to a surface water 

body, though 

intermittently.

DMR data available

Eureka 

Resources –

Williamsport 

2nd Street 

Facility

PA Settling, oil/water 

separation, 

chemical 

precipitation, 

clarification, MVR. 

Can treat with or 

without TDS 

removal.

No - However, 

future plans to 

install RO for direct 

discharge capability

Yes Yes, MVR Per Ertel et al. (2013), 

the facility provides 

treatment wastewater 

for reuse and indirect 

discharge. The facility 

treats entirely or almost 

entirely hydraulic 

fracturing wastewater. 

No
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-36

Facility Locality

Description of 

unit processes

Does CWT have a 

NPDES permit for 

discharge?

Does CWT 

provide 

effluent for 

reuse?

Does CWT have 

advanced 

process for TDS 

removal?

What is the status of 

the facility as of July, 

2016?

Are effluent quality 

data available 

through literature 

search?

Eureka 

Resources –

Standing 

Stone Facility, 

Bradford 

County

PA Settling, oil/water 

separation, 

chemical 

precipitation, 

clarification, MVR, 

crystallization

Yes - PA0232351 Yes Yes, MVR, 

crystallizer 

The facility can provide 

treated wastewater for 

reuse and also has 

received an NPDES 

permit for direct 

discharge. 

The facility treats 

hydraulic fracturing 

wastewater. 

No

Wellington 

Operating 

Company, LLC 

– 3W 

Production 

Water 

Treatment 

Facility

CO Dissolved air 

flotation, prefiltration, 

microfiltration with 

ceramic 

membranes, 

activated carbon 

adsorption. Water is 

pumped to rapidinfiltration pit which 

then percolates to a

tributary aquifer. 

The aquifer supplies 

water to an RO 

plant (Alzahrani et 

al., 2013).

Shallow 

groundwater 

percolation pit 

permits issued by 

COGCC – 281818 

and 281824

Yes Yes, RO but only 

after the water is 

sent to an aquifer 

storage and 

recovery well

Per Stewart (2013), the 

facility is providing 

treated wastewater for 

reuse, for agricultural 

use, to a shallow well to 

augment the municipal 

drinking water supply, 

and for discharge to the 

Colorado River. 

No
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-37

Facility Locality

Description of 

unit processes

Does CWT have a 

NPDES permit for 

discharge?

Does CWT 

provide 

effluent for 

reuse?

Does CWT have 

advanced 

process for TDS 

removal?

What is the status of 

the facility as of July, 

2016?

Are effluent quality 

data available 

through literature 

search?

Casella Altela 

Regional 

Environmental 

Services 

(CARES) 

McKean 

Facility

McKean 

County, PA

Pretreatment 

system (not defined 

in literature) and 

thermal distillation

Yes – PA0102288 Yes Yes – thermal 

distillation

The treatment plant is 

capable of reuse and 

recycle for fracturing 

operations and surface 

water discharge of 

excess water. However, 

the vendor has indicated 

that the facility is only 

treating water for 

reuse/recycle as of early 

2015.

No - just NPDES 

discharge requirements

Clarion Altela 

Environmental 

Services 

(CAES) Facility

Clarion 

County, PA

Pretreatment 

system (not defined 

in literature) and 

thermal distillation

Yes – PA0103632 Yes Yes – thermal 

distillation

The treatment plant is 

capable of reuse and 

recycle for fracturing 

operations and surface 

water discharge of 

excess water. However, 

the facility has indicated 

that it is only treating 

water for reuse/recycle 

as of early 2015. 

No – just NPDES 

discharge requirements

Terraqua 

Resource 

Management 

(aka. Water 

Tower Square 

Gas Well 

Wastewater 

Processing 

Facility)

Lycoming 

County, PA

Equalization tanks, 

oil-water separation 

via chemical 

addition (sulfuric 

acid, emulsion 

breaker), pH 

adjustment, 

coagulation, 

flocculation, 

inclined plate 

clarifier, sand 

filtration

No Yes No – However, 

TARM recognizes 

that they can’t 

discharge, until 

they install TDS 

treatment

Listed as proposed CWT, 

Part I NPDES permit 

issued, awaiting Part II 

WQM application per PA 

DEP website visited 

August 25, 2016. (See 

DEP’s list of Waste 

Water Treatment 

Facilities and 

http://mshaletaskforce.

org/SIte_Locations.html)

.

No 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-38

Facility Locality

Description of 

unit processes

Does CWT have a 

NPDES permit for 

discharge?

Does CWT 

provide 

effluent for 

reuse?

Does CWT have 

advanced 

process for TDS 

removal?

What is the status of 

the facility as of July, 

2016?

Are effluent quality 

data available 

through literature 

search?

Maggie Spain 

WaterRecycling 

Facility

Decatur, TX Settling, flash mixer 

with lime and 

polymer addition, 

inclined plate 

clarifier, surge tank, 

MVR

No Yes Yes – MVR The facility 

reuses/recycles treated 

water for fracturing 

operations. It is unclear 

if the MVR mobile unit is 

still at this facility. A 

pilot study is in progress 

at the facility that began 

in 2015 looking at the 

addition of a hollow 

fiber air stripping 

membrane unit for CO2 

removal prior to an 

UF/RO unit.

Yes – Some information 

can be obtained from 

Hayes et al. (2014).

Fountain 

Quail/NAC 

Services -

Kenedy

Kenedy, TX Oil-water separator, 

coagulation, 

flocculation, 

sedimentation, 

filtration, MVR. 

No Yes Yes – MVR According to its website, 

the facility 

reuses/recycles treated 

water for fracturing 

operations

(http://www.fountainqu

ail.com/water-recyclingsolutions/cleanbrine/casestudies/eagle-fordshale-texas). 

No

Purestream -

Gonzales 

facility

Gonzales, TX Induced gas 

flotation and MVR

No Yes Yes - MVR Per Dahm and Chapman 

(2014) commercial 

operations deployed 

March 2014 for 

reuse/recycle for 

fracturing operations.

No
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-39

Facility Locality

Description of 

unit processes

Does CWT have a 

NPDES permit for 

discharge?

Does CWT 

provide 

effluent for 

reuse?

Does CWT have 

advanced 

process for TDS 

removal?

What is the status of 

the facility as of July, 

2016?

Are effluent quality 

data available 

through literature 

search?

FourPoint 

Energy, LLC

(formerly 

owned by Linn 

Energy -

Granite Wash 

Wheeler 

County, TX

Induced gas 

flotation and MVR

No Yes Yes - MVR AVARA system installed 

for reuse/recycle in June 

2014, according to 

http://purestream.com/

index.php/watermanagement/vaporrecompression/photosand-videos.

Assume still operational 

but status unclear as 

new private company 

acquired Linn Energy’s 

oil and gas assets in 

2014. 

No

Fluid Recovery 

Service 

Josephine 

Facilitya

PA Oil-water separator, 

aeration, chemical 

precipitation with 

sodium sulfate, 

lime, and a polymer, 

inclined plate 

clarifier 

PA0095273

Permit renewal 

application 

submitted and 

under review by PA 

DEP.

No No The facility stopped 

accepting Marcellus 

wastewater September 

30, 2011 (Ferrar et al., 

2013). It treats 

conventional oil and gas 

wastewater. 

The facility plans to 

upgrade to include 

evaporative technology 

to attain monthly 

average TDS levels of 

500 mg/L or less. Not 

upgraded as of July, 

2016.

Yes – Some effluent 

results obtained from 

Ferrar et al. (2013) and 

Warner et al. (2013a). 

Also minimal DMR data 

from the EPA. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-40

Facility Locality

Description of 

unit processes

Does CWT have a 

NPDES permit for 

discharge?

Does CWT 

provide 

effluent for 

reuse?

Does CWT have 

advanced 

process for TDS 

removal?

What is the status of 

the facility as of July, 

2016?

Are effluent quality 

data available 

through literature 

search?

Fluid Recovery 

Service 

Franklin 

Facilitya

PA Oil-water separator, 

aeration, chemical 

precipitation with 

sodium sulfate, 

lime, and a polymer, 

inclined plate 

clarifier

PA0101508

Permit renewal 

application 

submitted and 

under review by PA 

DEP.

No No This facility is not 

accepting wastewater 

from hydraulic 

fracturing operations as 

of July 2016. It treats 

conventional oil and gas 

wastewater. The facility 

plans to upgrade to 

include evaporative 

technology to attain 

monthly average TDS 

levels of 500 mg/L or 

less. Not upgraded as of 

July, 2016.

Minimal DMR data from 

the EPA. 

Hart 

ResourcesCreekside 

Facilitya

PA Oil-water separator, 

aeration, chemical 

precipitation with 

sodium sulfate, 

lime, and a polymer, 

inclined plate 

clarifier

PA0095443

Permit renewal 

application 

submitted and 

under review by PA 

DEP.

No No This facility is not 

accepting wastewater 

from hydraulic 

fracturing operations as 

of July 2016. It treats 

conventional oil and gas 

wastewater. The facility 

plans to upgrade to 

include evaporative 

technology to attain 

monthly average TDS 

levels of 500 mg/L or 

less. Not upgraded as of 

July, 2016.

Minimal DMR data from 

the EPA. 

a As of May 15, 2013, these facilities are under an administrative order (AO). According to the AO, these facilities must comply with a monthly effluent limit for TDS not to exceed 

500 mg/L. This will allow them to treat high-saline wastewaters typical of unconventional oil and gas operations. To meet the requirements of the AO, they have applied to the 

Pennsylvania Department of Environmental Protection (PA DEP) for a NPDES permit and are planning to install treatment for TDS.
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F.5.2. Discharge Options for CWTs

Direct discharge CWTs are allowed to discharge treated wastewater directly to surface waters 

under the NPDES permit program. Discharge limitations may be based on water quality standards 

in the NPDES and technology-based effluent limitation guidelines under 40 CFR Part 437. In 

addition, permitting authorities have permitted facilities for discharge under 40 CFR 435, Subpart 

E. Judsonia Central Water Treatment Facility in Sunnydale, Arkansas is permitted to directly

discharge treated effluent from produced water from the Fayetteville Shale play to Byrd pond

located on the property. Pinedale Anticline Field Wastewater Treatment Facility in Wyoming, WY,

originally designed to treat produced water from tight gas plays in the Pinedale Anticline Field to

levels suitable for reuse, was upgraded to include desalinization and RO treatment for discharge to

a local river. CWTs with NPDES discharge permits may also opt to treat oil and gas wastewater for

reuse as shown in Table F-6. Some facilities have the ability to treat wastewater to different

qualities (e.g., with or without TDS removal), which they might do to target various reuse water

quality criteria. Both the Judsonia and Pinedale facilities discussed above have the ability to employ

either TDS- or non-TDS-removal treatments depending on the customers’ needs.

Indirect discharge CWTs may treat hydraulic fracturing wastewater and then discharge the treated 

wastewater effluent to a POTW. Discharge to the POTW is controlled by an Industrial User 

mechanism, which incorporates pretreatment standards established in 40 CFR Part 437. Two 

facilities, one located in Pennsylvania (Eureka Resources) and the other in Ohio (Patriot Water 

Treatment), include indirect discharge as an option in wastewater treatment. The EurekaWilliamsport facility accepts wastewater (primarily from the Marcellus Shale play) and either 

treats it for reuse or discharges it to the local POTW. The Patriot facility offers services to hydraulic 

fracturing operators in the Marcellus and Utica Shale plays for removal of solids and metals using 

chemical treatment. As of March 2015, however, the Patriot facility is limited by the Ohio 

Environmental Protection Agency to accepting only "low salinity" (<50,000 mg/L TDS) produced 

water and may only discharge 100,000 gal (380,000 L) per day to the Warren Ohio POTW. 

Zero-discharge CWTs do not discharge treated wastewater; instead, the wastewater is treated and 

reused in subsequent hydraulic fracturing operations. WVWRI (2012) state that this practice 

reduces potential effects on surface drinking water resources by reducing both direct and indirect 

discharges. Zero-discharge facilities may offer varying levels of treatment, including minimal 

treatment (for example, filtration), low-level treatment (chemical precipitation), and/or advanced 

treatment (evaporation, crystallization). Reserved Environmental Services (RES) in Mt. Pleasant, 

Pennsylvania, is a zero liquid discharge facility permitted by PA DEP to treat wastewater from the 

Marcellus Shale play for reuse. Residual solids are dewatered and sent to a landfill. Treated 

wastewater effluent is stored, monitored, and chlorinated for reuse (ONG Services, 2015). 

F.6. Water Reuse

With the scarcity of freshwater supplies and limited access to disposal wells in some areas of the 

country, reuse of hydraulic fracturing wastewaters for subsequent hydraulic fracturing activity has 

become more prevalent (Section 8.4.4). This section discusses factors to consider in adopting reuse 

and the recommended or otherwise observed water quality needed. 

F-41
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-42

F.6.1. Factors in Considering Reuse

In making the decision whether to manage wastewater via reuse, operators have several factors to 

consider (Slutz et al., 2012; NPC, 2011): 











Wastewater generation rates compared to water demand for future fracturing operations, 

Wastewater quality and treatment requirements for use in future operations, 

The costs and benefits of wastewater management for reuse compared with other 

management strategies, 

Available infrastructure and treatment technologies, and 

Regulatory considerations. 

Among these factors, costs may be the most significant driver, weighing the costs of transportation 

from the generating well to the treatment facility and to the new well against the costs for transport 

to alternative locations (a disposal well or CWT). Trucking large quantities of water can be 

relatively expensive (from $0.50 to $8.00 per barrel), rendering on-site treatment technologies and 

reuse potentially economically competitive in some settings (Dahm and Chapman, 2014; Guerra et 

al., 2011). Also, logistics, including proximity of the water sources for aggregation, may be a factor 

in implementing reuse. For example, Boschee (2014) notes that in the Permian Basin, older 

conventional wells are linked by pipelines to a centralized transfer facility, enabling movement of 

treated water to areas where it is needed for reuse. 

Regulatory factors may facilitate reuse. In 2013, the Texas Railroad Commission adopted rules 

intended to encourage statewide water conservation. These rules facilitate reuse by eliminating the 

need for a permit when operators reuse on their own lease or transfer the fluids to another 

operator for use in hydraulic fracturing (Rushton and Castaneda, 2014). Data for the years after 

2013 will allow evaluation of whether reuse increased after this regulatory change. 

Recommended compositional ranges for the base fluid used to formulate hydraulic fracturing fluid 

may shift in the future as fracturing fluid technology continues to develop. Development of 

fracturing mixture additives that are brine-tolerant have allowed for the use of high TDS 

wastewaters (up to tens of thousands of mg/L) for reuse in fracturing (Tiemann et al., 2014; GTI, 

2012; Minnich, 2011). Some new fracturing fluid systems are claimed to be able to tolerate salt 

concentrations exceeding 300,000 mg/L (Boschee, 2014). This greater flexibility in acceptable 

water chemistry can facilitate reuse both logistically and economically by reducing treatment 

needs. 

Reuse rates may also fluctuate with changes in the supply and demand of treated wastewater and 

the availability of fresh water. Flowback may be preferable to later-stage produced water for reuse 

because 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. 

Flowback also tends to have lower TDS concentrations than later-stage produced water. In the 

Marcellus, TDS has been shown to increase from tens of thousands to about 100,000 mg/L during 

the first 30 days (Barbot et al., 2013; Maloney and Yoxtheimer, 2012); see Chapter 7. As more wells 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-43

go into production, the changing production rate and quality of wastewaters generated in a region 

need to be taken into account, as well as a possible reduction in the demand for reused water as 

plays mature (Lutz et al., 2013; Hayes and Severin, 2012b; Slutz et al., 2012). 

F.6.1.1. On-Site Treatment for Reuse

On-site systems that treat produced water for reuse can reduce potential impacts on drinking 

water resources associated with transportation and disposal, and they can facilitate the logistics of 

reuse by preparing the water close to well sites. These systems sometimes consist of mobile units 

containing one or more treatment processes that can be moved from site to site to treat waters in 

newly developed sites that are not yet producing at full-scale. Semi-permanent facilities that serve 

specific areas also exist (Halldorson, 2013; Boschee, 2012). 

Treatment systems are typically tailored for site-specific produced water chemical concentrations 

and desired water quality treatment goals, including whether significant TDS removal is needed. If 

low TDS water is needed, more advanced treatment will be required (as discussed in Section F.2). 

This more extensive treatment can increase the treatment costs by three to four times compared to 

treatment systems that do not remove TDS (Halldorson, 2013). On-site facilities may be warranted 

where truck hauling or seasonal accessibility to and from a central facility is an issue (Boschee, 

2014; Tiemann et al., 2014). Operators may also consider on-site facilities if they have not fully 

committed to an area and the well counts are initially low. In those instances, they can later decide 

to add or remove units based on changing production volumes (Boschee, 2014). 

F.6.2. Water Quality for Reuse

As of 2016, there is no consensus on the water quality requirements for reuse of wastewater for 

hydraulic fracturing, and operator opinions vary on the minimum standards for the water quality 

needed for fracturing fluids (Vidic et al., 2013; Acharya et al., 2011). Table F-7 provides a list of 

constituents and the recommended or observed target concentrations for reuse applications. The 

wide concentration ranges for many constituents (e.g., TDS ranging from 500 to 70,000 mg/L) 

suggest that water quality requirements for reuse are dictated by operation-specific requirements, 

including operator preference and selection of fracturing fluid chemistry. 

Table F-7. Water quality requirements for reuse. 

Source: U.S. EPA (2015m). 

Constituent Reasons for limiting 

concentrations

Recommended or observed base fluid target 

concentrations (mg/L, after blending)b

TDS Fluid stability 500 – 70,000

Chloride Fluid stability 2,000 – 90,000

Sodium Fluid stability 2,000 – 5,000
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-44

Constituent Reasons for limiting 

concentrations

Recommended or observed base fluid target 

concentrations (mg/L, after blending)b

Metals

Iron Scaling 1 – 15

Strontium Scaling 1

Barium Scaling 2 – 38

Silica Scaling 20

Calcium Scaling 50 – 4,200

Magnesium Scaling 10 – 1,000

Sulfate Scaling 124 – 1,000

Potassium Scaling 100 – 500

Scale formersaScaling 2,500

Other

Phosphate Not Reported 10

TSS Plugging 50 – 1,500

Oil Fluid stability 5 – 25

Boron Fluid stability 0 – 10

pH (S.U.) Fluid stability 6.5 – 8.1

Bacteria (counts/mL) Bacterial growth 0 – 10,000

a

Includes total of barium, calcium, manganese, and strontium.

b Unless otherwise noted.

Wastewater quality can be managed for reuse either by blending it with freshwater and allowing 

dilution to bring the concentrations of problematic constituents to an acceptable range or through 

treatment (Veil, 2010). Treatment, if needed, can be conducted at facilities that are mobile, semipermanent modular systems, or fully permanent CWTs (Nicot et al., 2012). At a minimum, hydraulic 

fracturing service providers generally prefer that the wastewater be treated to remove TSS, 

microorganisms, and constituents that form scale or inhibit crosslinking in gelled fluid systems 

(Boschee, 2014). Figure F-8 shows a schematic of a treatment system to treat wastewater for reuse 

that can remove suspended solids, hardness, and organic constituents. 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-45

Figure F-8. Diagram of treatment for reuse of flowback and produced water. 

Source: Kimball (2010). Reprinted with permission from CDM Smith. 

In the Marcellus, the wastewater to be reused is generally treated with oil/gas-water separation, 

filtration, and dilution (Ma et al., 2014). Although many Marcellus treatment facilities only supply 

basic reuse treatment that removes oil and solids, advanced treatment facilities that use techniques 

such as RO or distillation methods are also in operation (Veil, 2010). 

Reuse concerns can vary with the type of hydraulic fracturing fluid used (e.g., slickwater, linear gel, 

crosslinked gel, foam) (Wasylishen and Fulton, 2012) and the anticipated changes in water 

chemistry over time during the transition from flowback to produced water (Hammer and 

VanBriesen, 2012). Elevated TDS is a concern, but residual constituents from previous fluid 

mixtures (e.g., breakers) may also cause difficulties when reusing water for subsequent fracturing 

operations (Montgomery, 2013; Walsh, 2013). 

F.7. Hydraulic Fracturing Wastewater Impacts on POTWs 

Wastewater treatment processes used by POTWs are generally not designed or operated to treat 

wastewater containing high salt concentrations (>0.1-5% salt), and sudden increases in chloride 

concentration above 5 – 8 g/L may cause problems for wastewater treatment (Ludzack and Noran, 

1965). Four basic problems for biological treatment of saline water have been described (Woolard 

and Irvine, 1995): (1) microbes in POTW treatment systems tend to be sensitive to changes in ionic 

strength; (2) microbial metabolic functions are disrupted, leading to decreased degradation of 

carbon compounds; (3) effluent suspended solids are increased due to cell lysis and/or a reduction 

in organisms that promote flocculation; and (4) the extent to which biomass at a POTW can 

acclimate to a salty environment is limited. To address concerns with high salinity and other 

contaminants that are either not removed by or can adversely impact the POTW treatment system, 
Appendix F – Wastewater Disposal and Reuse Supplemental Information 

F-46

EPA has promulgated pretreatment standards intended to prevent pollutants in unconventional oil 

and gas wastewaters from reaching POTWs (Chapter 8). 

If indirect discharge to a POTW is being considered or is employed, some adaptations can be useful 

for wastewater treatment trains at CWTs handling hydraulic fracturing wastewater to meet the 

established federal limits. For example, biological pre-treatment may be beneficial as an added 

process prior to indirect discharge from a CWT to a POTW for removal of organic contaminants. 

Specialized treatment systems using salt-tolerant bacteria may be beneficial as an additional level 

of treatment for pre-treating (or polishing) wastewaters at CWTs. (These processes differ from 

conventional biological processes in standard wastewater treatment, which are not suitable for 

large volumes of hydraulic fracturing wastewater). In particular, membrane bioreactors (MBRs) 

have been examined for the treatment of oil and gas wastewater (Dao et al., 2013; Kose et al., 2012; 

Miller, 2011). MBRs provide advantages over conventional aeration basin processes as they can be 

incorporated into existing treatment trains more easily and have a much smaller areal footprint 

than aeration basins. 

F.8. Hydraulic Fracturing Wastewater and Disinfection Byproducts

F.8.1. Disinfection Byproducts

This section provides background information on disinfection byproducts (DBPs) and their 

formation to support the discussion in Section 8.5.1 of Chapter 8 regarding impacts on surface 

waters and downstream drinking water utilities due to elevated bromide and iodide in hydraulic 

fracturing wastewaters. 

Regulated DBPs are a small subset of the full spectrum of DBPs that include other chlorinated, 

brominated, iodated, and nitrogenous DBPs. Some of the emerging unregulated DBPs may be more 

toxic than their regulated counterparts (Harkness et al., 2015; McGuire et al., 2014; Parker et al., 

2014). Of the many types of DBPs that can form when drinking water is disinfected, Safe Drinking 

Water Act (SDWA) Stage 1 and Stage 2 DBP Rules regulate four total trihalomethanes (TTHM), five 

haloacetic acids (HAA5), bromate, and chlorite (U.S. EPA, 2006). 

Most brominated DBPs form when water containing organic material and bromide reacts with a 

disinfectant such as chlorine or chloramines during drinking water treatment. Parameters that 

affect DBP formation include concentration and type of organic material, disinfectant type, 

disinfectant concentration, pH, water temperature, and disinfectant contact time. In addition, many 

studies have found that elevated bromide levels correlate with increased DBP formation (AWWA, 

2010; Obolensky and Singer, 2008; Matamoros et al., 2007; Hua et al., 2006; Yang and Shang, 2004). 

Some studies found similar results for iodide as well (McGuire et al., 2014; Parker et al., 2014). Pope 

et al. (2007) reported that increased bromide levels are the second best indicator of DBP formation, 

with pH being the best. 

In addition, research finds that higher levels of bromide and iodide contribute to increased 

concentrations of the brominated and iodated forms of DBPs (both regulated and unregulated), 

which tend to be more cytotoxic, genotoxic, and carcinogenic than chlorinated species (McGuire et 
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F-47

al., 2014; Parker et al., 2014; States et al., 2013; Krasner, 2009; Richardson et al., 2007). Studies 

generally report that the ratios of halogen incorporation into DBPs reflect the ratio of halogen 

concentrations in the source water (Criquet et al., 2012; Jones et al., 2012; Obolensky and Singer, 

2008) but that bromide is preferentially incorporated into halogenated DBPs (McGuire et al., 2014; 

Parker et al., 2014; States et al., 2013; Krasner, 2009; Obolensky and Singer, 2008; Richardson et al., 

2007; Hua et al., 2006). 

From a regulatory perspective, elevated bromide levels create difficulties in meeting drinking water 

maximum contaminant levels (MCLs). When the TTHM are predominately in the form of 

brominated DBPs, the higher molecular weight of bromide (79.9 g/mol) relative to chloride (35.5 

g/mol) causes the overall mass of the TTHM sum to increase. This can lead to elevated 

concentrations of TTHM, in turn potentially leading to violations of the TTHM MCL for the drinking 

water utility (Francis et al., 2009). 

High bromide levels are also cited as causing formation of nitrogenous DBP Nnitrosodimethylamine (NDMA) in water disinfected with chloramines (Luh and Mariñas, 2012).

Although NDMA is not regulated by the EPA as of 2016, it is listed as a priority toxic pollutant, and 

the EPA is planning to evaluate NDMA and other nitrosamines as candidates for regulation during 

the six-year review of the Microbial and Disinfection Byproducts (MDBP) rules (U.S. EPA, 2014a). 

F.8.2. Studies Modeling Bromide in Receiving Waters from CWT Effluents

Contaminant modeling by Weaver et al. (2016) found that reducing effluent concentrations (e.g., 

discharging flowback versus produced water), discharging during higher stream flow periods, and 

using a pulsing or intermittent discharge can reduce bromide levels in receiving streams. Input data 

for the model came from several sources. Effluent bromide concentrations and permitted discharge 

flows came from eight commercial wastewater treatment plants in western Pennsylvania. Receiving 

stream flows were based on U.S. Geological Survey gage data. Data on flow accretion based on an 

analysis of tracer data from literature and EPA studies. The model assessed both steady-state and 

transient scenarios. The steady-state model assumed fixed discharges and flows and calculated 

mass and volume flow balance in a river network. The transient (i.e., pulsed or intermittent 

discharge) model simulations were based on a model developed by Weaver et al. (2016) assuming 

discharges of 12, 8, and 4 hours per day as well as a 24-hour simulation for comparison to a steadystate scenario. For steady-state scenarios, bromide concentrations were lowest under high flow 

conditions in the source water and with lower concentrations of bromide in the effluent. Bromide 

concentrations were generally lower for the pulsed scenarios than for the steady-state discharge 

scenarios.

In a separate study, U.S. EPA (2015m) 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 Allegheny River and its 

tributaries receive runoff and discharges containing an array of contaminants. Contaminant sources 

include discharges from CWTs for oil and gas wastewater, runoff from acid mine drainage and 

mining operations, discharges from coal-fired electric power stations, industrial wastewater 

treatment plant effluents, and POTW discharges. The Allegheny River is the water supply for 
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F-48

thirteen public water systems that serve over 500,000 people in western Pennsylvania 

underscoring the importance of a full understanding of upstream contaminant contributions. 

In Pennsylvania, wastewater produced from hydraulic fracturing of the Marcellus formation has 

been mostly diverted from CWTs and POTWs that discharge to public waters in the state to other 

management practices such as reuse (Hammer and VanBriesen, 2012). Wastewater produced from 

hydraulic fracturing of non-Marcellus formations, however, continues to be sent to CWTs and 

POTWs on the Allegheny River. 

In order to quantify relative contributions of anions as a contaminant source at public drinking 

water system intakes, an EPA source apportionment study determined relative contributions of 

bromide from several upstream activities (U.S. EPA, 2015m). The study developed chemical source 

profiles for discharges upstream of the drinking water system intakes, characterized water quality 

in the river upstream and downstream of the CWTs and other facilities, characterized the water 

quality at the drinking water system intakes, and analyzed the sampling data collected with the EPA 

Positive Matrix Factorization (PMF) receptor model. The study focused on low-flow conditions. 

Researchers found that CWTs and coal-fired power plants with flue gas desulfurization were 

responsible for the majority of bromide at the two public water supply intakes. CWTs accounted for 

a substantial contribution of bromide, with 88-89% at one intake and 37% at the other. Coal-fired 

power plants with flue gas desulfurization were the other substantial contributors, with 50% at the 

second intake but less than 1% at the first. Sediment and acid mine drainage were also minor 

contributors in the range of 1 to 11% (U.S. EPA, 2015m).
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Appendix G. Identification and Hazard 

Evaluation of Chemicals across the Hydraulic 

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Appendix G. Identification and Hazard Evaluation of 

Chemicals across the Hydraulic Fracturing Water Cycle 

Supplemental Information 

G.1. Introduction 

Appendix G provides detail and supporting information on the oral reference values (RfVs) and oral 

slope factors (OSFs) that were identified in Chapter 9 of this assessment.1 Section G.2 provides 

detail on the criteria used to select sources of RfVs, OSFs, and qualitative cancer classifications for 

chemicals used or detected in hydraulic fracturing processes, and lists all sources that were 

considered for this study. Section G.3 provides a glossary of the toxicity terminology that is used by 

these various sources. Section G.4 provides a brief description of other potential tools and 

approaches that could be used by stakeholders to prioritize and estimate toxicity of chemicals that 

have a limited toxicity database. Lastly, all of the toxicity data collected from the sources that met 

the criteria for inclusion in this study are provided. Table G-1a through G-1e show the available 

RfVs, OSFs, and qualitative cancer classifications for chemicals used in hydraulic fracturing fluids, 

and Table G-2a through Table G-2e show the available RfVs, OSFs, and qualitative cancer 

classifications for chemicals detected in produced water from hydraulically fractured wells. These 

tables also indicate whether each chemical has available data on physicochemical properties or 

occurrence. 

G.2. Criteria for Selection and Inclusion of Reference Value (RfV), Oral Slope 

Factor (OSF), and Qualitative Cancer Classification Data Sources 

The criteria listed below were used to evaluate the quality of RfVs, OSFs, and qualitative cancer 

classifications considered for use in the hazard analyses conducted in Chapter 9. These criteria 

were originally outlined in the hydraulic fracturing research plan (U.S. EPA, 2011a) and interim 

progress report (U.S. EPA, 2012e). Only data sources that met these criteria were considered of 

sufficient quality to be included in the analyses. 

The following criteria had to be met for a source to be deemed of sufficient quality: 

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. 

a. Governmental bodies include sovereign states, and federated states/units. 

b. Intergovernmental bodies are those whose members are sovereign states, and the 

subdivisions or agencies of such intergovernmental bodies. The United Nations is 

an example of an intergovernmental body. The International Agency for Research 

 

1 As defined in Chapter 9, the term RfV refers to reference values for noncancer effects occurring via the oral route of 

exposure and for chronic durations, except where noted. 
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G-4 

on Cancer (IARC) is an agency of the World Health Organization (WHO), which is 

itself an agency of the United Nations. Thus, IARC is considered a subdivision of the 

United Nations. 

2. The data source must include peer-reviewed RfVs, peer-reviewed OSFs, or peer reviewed 

qualitative assessments. 

a. A committee that is established to derive the RfVs, OSFs, or qualitative 

assessments can have members of that same committee provide the peer review, 

so long as either the entire committee, or members of the committee who did not 

participate in the derivation of a specific section of a work product, conduct the 

review. 

b. Peer reviewers who work for grantees of the organization deriving the RfVs, OSFs, 

or qualitative assessments are generally allowed, and this will not be considered to 

constitute a conflict/duality of interest. 

c. Peer reviewers may work in the same or different office, so long as they did not 

participate in any way in the development of the product, and these individuals 

must be free of conflicts/duality of interest with respect to the chemical(s) 

assigned. 

i. For instance, peer reviewers for Program X, conducted by Office A, may 

also be employed by Office A so long as they did not participate in the 

creation of the Program X product they are reviewing. 

3. The RfVs, OSFs, or qualitative assessments must be based on peer-reviewed scientific data. 

a. There are cases where industry reports that were not published in a peerreviewed, scholarly journal may be used, if the industry report has been 

adequately peer-reviewed by an external body (external to the group generating 

the report, and external to the group generating the peer-reviewed RfVs, peerreviewed OSFs, or peer-reviewed qualitative assessment) that is free of 

conflicts/dualities of interest. 

4. The RfVs, OSFs, or qualitative assessments must be focused on protection of the general 

public. 

a. Sources that are focused on workers are not appropriate as workers are assumed 

to accommodate additional risk than the general public due to their status as 

workers. 

5. The body generating the values or qualitative assessments must be free of conflicts of 

interest with respect to the chemicals for which it derives RfVs, OSFs, or qualitative 

assessments. 

a. If a body generating the RfVs, OSFs, or qualitative assessments accepts funding 

from an interested party (i.e., a company or organization that may be impacted by 

past, present, or future values or qualitative assessments), then the body has a 

conflict of interest. 
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b. For instance, if a non-profit organization is funded by an industry trade group, and 

the non-profit generates RfVs, OSFs, or qualitative assessments for chemicals that 

trade group is interested in, then the non-profit is considered to have a conflict of 

interest with respect to those chemicals. 

It is important to note that having a conflict/duality of interest for one chemical is sufficient to 

disqualify the entire database, as it is assumed that conflicts/dualities of interest may exist for 

other chemicals as well. 

G.2.1. Included Sources 

We applied our criteria to 16 different sources of RfVs and/or OSFs. After application of our criteria, 

we were left with eight sources. For those sources which did not meet our criteria, we provide an 

explanation of why they were excluded. 

The following sources were evaluated, met our criteria, and were selected as sources of reference 

doses or cancer slope factors for this analysis: 

















U.S. EPA Integrated Risk Information System (IRIS). 

U.S. EPA Human Health Benchmarks for Pesticides (HHBP). 

U.S. EPA Provisional Peer-Reviewed Toxicity Values (PPRTVs). 

U.S. Agency for Toxic Substances and Disease Registry (ATSDR) Minimal Risk Levels 

(MRLs). 

California EPA (CalEPA) Toxicity Criteria Database. 

International Programme on Chemical Safety (IPCS) Concise International Chemical 

Assessment Documents (CICAD). 

The following sources were evaluated, met our criteria, and were selected as sources of qualitative 

cancer classifications: 

International Agency for Research on Cancer (IARC). 

US National Toxicology Program (NTP) Report on Carcinogens (RoC). 

RfVs, OSFs, and qualitative cancer characterizations from these data sources are listed in Tables G1a through G-1e for chemicals used in hydraulic fracturing fluid formulation, and Tables G-2a 

through G-2e for chemicals reported in hydraulic fracturing produced water. 

In addition, Table G-1a and Table G-2a also list the EPA’s drinking water maximum contaminant 

levels (MCLs) and maximum contaminant goal levels (MCLG) when available. These values are 

generally based on IRIS values, and MCLs are treatment-based. 

G.2.2. Excluded Sources 

The following sources were excluded: 
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G-6 











American Conference of Governmental Industrial Hygienists: The assessments 

derived by this body are specific to workers and are not generalizable to the general 

public. In addition, this body is not a governmental or intergovernmental body. Thus, these 

values were excluded based on criteria 1 and 4.

European Chemicals Bureau, Classification and Labeling Annex I of Directive 

67/548/EEC: These assessments are not based on peer-reviewed values, but are based on 

data supplied by manufacturers. Further, the enabling legislation states that 

“Manufacturers, importers, and downstream users shall examine the information...to 

ascertain whether it is adequate, reliable and scientifically valid for the purpose of the 

evaluation...” This clearly demonstrates that the data and the evaluation are not required 

to be peer-reviewed. Thus, these values were excluded based on criterion 2. 

Toxicology Excellence for Risk Assessment’s (TERA’s) International Toxicity 

Estimates for Risk Assessment (ITER): The ITER database is developed by TERA a 

501(c)(3) non-profit. TERA accepts funding from various sources, including interested 

parties that may be impacted by their assessment work. Thus, ITER is excluded based on 

criteria 1 and 5.

Other U.S. states: The EPA evaluated values from all states that had values reported on 

their websites. If a state’s values were determined to be largely duplicative of the EPA’s 

values (e.g., the state adopts EPA values, such as the regional screening levels, and does 

not typically generate its own peer-reviewed values), that state’s values were no longer 

considered. The EPA contacted those states whose values were determined to not be 

duplicative of the EPA’s values, and confirmed whether or not a peer review process was 

used to develop the state’s values. The EPA determined that of the states with values not 

duplicative of the EPA’s values, only California’s values met all of the EPA’s criteria for this 

report. Other states with publicly accessible RfVs and/or OSFs include: Alabama, Florida, 

Hawaii, and Texas. 

WHO Guidelines for Drinking-Water Quality: The WHO Guidelines’ values are not RfVs, 

but rather drinking water values. 

G.3. Glossary of Toxicity Value Terminology 

This section defines the toxicity values and qualitative cancer classifications that are frequently 

found in the sources identified above. 

Lowest-observed-adverse-effect level (LOAEL): 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. Source: U.S. EPA (2011c). 

Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive 

toxicant at which the chemical would have no observable adverse reproductive effect, assuming 

exposure at 1,000 times that level. Source: OEHHA (2012). 
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Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in 

drinking water. MCLs are set as close to the MCLG as feasible using the best available analytical and 

treatment technologies and taking cost into consideration. MCLs are enforceable standards. Source: 

U.S. EPA (2012a). 

Maximum contaminant level goal (MCLG): 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. Source: U.S. EPA (2012a).

Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance 

at or below which the substance is unlikely to pose a measurable risk of harmful (adverse), 

noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a 

specified time period (acute, intermediate, or chronic). MRLs should not be used as predictors of 

harmful (adverse) health effects.













Chronic MRL: Duration of exposure is 365 days or longer.

Intermediate MRL: Duration of exposure is >14 to 364 days.

Acute MRL: Duration of exposure is 1 to 14 days.

Source: ATSDR (2009). 

No-observed-adverse-effect level (NOAEL): 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 (2011c). 

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. Source: U.S. EPA (2011c).

Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of 

a daily oral exposure to the human population (including sensitive subgroups) that is likely to be 

without an appreciable risk of deleterious effects during a lifetime. It can be derived from a NOAEL, 

LOAEL, or benchmark dose, with uncertainty factors generally applied to reflect limitations of the 

data used. Generally used in the EPA's noncancer health assessments. 

Chronic RfD: Duration of exposure is up to a lifetime. 

Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average lifespan. 

Acute RfD: Duration of exposure is 24 hours or less.

Source: U.S. EPA (2011c). 
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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. RfV is a generic term not specific to a given route of exposure. In the context 

of this report, the term RfV refers to reference values for noncancer effects occurring via the oral 

route of exposure and for chronic durations, except where noted. Source: U.S. EPA (2011c). 

Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass 

basis, to which an individual in a (sub) population may be exposed daily over its lifetime without 

appreciable health risk. Source: WHO (2015).

Qualitative cancer classifications: A system used for the hazard identification of potential 

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.



o

o

o

o

o

o



o

o

o



EPA 1986 guidelines: Under the EPA's 1986 risk assessment guidelines, the WOE was 

described by categories “A through E,” with Group A for known human carcinogens 

through Group E for agents with evidence of noncarcinogenicity. Five standard WOE 

descriptors were used: 

A: Human carcinogen. 

B1: Probable human carcinogen―based on limited evidence of carcinogenicity in 

humans and sufficient evidence of carcinogenicity in animals. 

B2: Probable human carcinogen―based on sufficient evidence of carcinogenicity in 

animals. 

C: Possible human carcinogen. 

D: Not classifiable as to human carcinogenicity. 

E: Evidence of noncarcinogenicity for humans. 

Source: U.S. EPA (2011c). 

EPA 1996 proposed guidelines: The EPA’s 1996 proposed guidelines outlined a major 

change in the way hazard evidence was weighted in reaching conclusions about the human 

carcinogenic potential of agents. These guidelines replaced the WOE letter categories with 

the use of standard descriptors of conclusions incorporated into a brief narrative. Three 

categories of descriptors with the narrative were used:

Known/likely. 

Cannot be determined. 

Not likely. 

Source: U.S. EPA (1996). 

EPA 1999 guidelines: The 1999 guidelines adopted a framework incorporating hazard 

identification, dose-response assessment, exposure assessment, and risk characterization 
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with an emphasis on characterization of evidence and conclusions in each part of the 

assessment. Five descriptors summarizing the WOE in the narrative were used: 

o

o

o

o

o



o

o

o

o

o



o

o

o

o

o



Carcinogenic to humans. 

Likely to be carcinogenic to humans. 

Suggestive evidence of carcinogenicity, but not sufficient to assess human 

carcinogenic potential. 

Data are inadequate for an assessment of human carcinogenic potential. 

Not likely to be carcinogenic to humans. 

Source: U.S. EPA (1999a). 

EPA 2005 guidelines: The approach outlined in the EPA's 2005 guidelines for carcinogen 

risk assessment considers all scientific information in determining whether and under 

what conditions an agent may cause cancer in humans and provides a narrative approach 

to characterize carcinogenicity rather than categories. Five standard WOE descriptors are 

used as part of the narrative: 

Carcinogenic to humans. 

Likely to be carcinogenic to humans. 

Suggestive evidence of carcinogenic potential. 

Inadequate information to assess carcinogenic potential. 

Not likely to be carcinogenic to humans. 

Source: U.S. EPA (2011c). 

IARC Monographs on the evaluation of carcinogenic risks to humans: The IARC 

classifies carcinogen risk as a matter of scientific judgement that reflects the strength of 

the evidence derived from studies in humans, in experimental animals, from mechanistic 

data, and from other relevant data. Five WOE classifications are used: 

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. 

Source: IARC (2015). 

NTP: The NTP describes the results of individual experiments on a chemical agent and 

notes the strength of the evidence for conclusions regarding each study. Negative results, 

in which the study animals do not have a greater incidence of neoplasia than control 

animals, do not necessarily mean that a chemical is not a carcinogen, inasmuch as the 

experiments are conducted under a limited set of conditions. Positive results demonstrate 

that a chemical is carcinogenic for laboratory animals under the conditions of the study 

and indicate that exposure to the chemical has the potential for hazard to humans. For 
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G-10

each separate experiment, one of the following five categories is selected to describe the 

findings. These categories refer to the strength of the experimental evidence and not to 

potency or mechanism.

o

o

o

o

o



o

o

Clear evidence of carcinogenic activity. 

Some evidence of carcinogenic activity. 

Equivocal evidence of carcinogenic activity. 

No evidence of carcinogenic activity. 

Inadequate study of carcinogenic activity. 

Source: NTP (2014a). 

The RoC is a congressionally mandated, science-based, public health report that identifies 

agents, substances, mixtures, or exposures (collectively called “substances”) in our 

environment that may potentially put people in the United States at increased risk for 

cancer. NTP prepares the RoC on behalf of the Secretary of the Health and Human Services. 

The listing criteria in the RoC Document are:

Known to be a human carcinogen. 

Reasonably anticipated to be a human carcinogen. 

Source: NTP (2014b). 

G.4. Additional Tools for Hazard Evaluation 

In addition to the methods and approaches utilized in this chapter, there are other potential tools 

that could be used by stakeholders to prioritize and estimate toxicity of chemicals that have a 

limited toxicity database. We describe three such approaches here. This list is not intended to be 

exhaustive, but provides examples of tools that stakeholders may find useful when faced with many 

data-poor chemicals at a field site. 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. 

G.4.1. Threshold of Toxicological Concern (TTC) 

The TTC approach is a risk assessment tool based on the concept that there is an exposure 

threshold value for all chemicals below which there is a very low probability of risk to human 

health (Kroes et al., 2005; Kroes et al., 2004). The TTC approach proposes that such a de minimis 

value can be identified for many chemicals based on knowledge of chemical structure (Lapenna and 

Worth, 2011; Kroes et al., 2005; Kroes et al., 2004). The estimated TTC is integrated with an 

estimate of human exposure to that chemical, and used by the model to determine if there is 

potential for concern or if more detailed chemical specific data are necessary (Kroes et al., 2005; 

Kroes et al., 2004). As a preliminary step in risk assessment, this approach can be applied as a 

screening tool, for ranking and prioritization, and as an indicator of data needs (Lapenna and 

Worth, 2011; Kroes et al., 2005; Kroes et al., 2004). 
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The various TTC approaches are based on a decision tree proposed by Cramer et al. (1978), which 

classifies chemicals into categories of high (Class III), medium (Class II), or low (Class I) level of 

concern, based on structure and reactivity. Based on the analysis of chronic oral toxicity data within 

each of these structural classes, Munro et al. (1996) proposed oral intake TTC values of 1.5, 9.0, and 

30 μg/kg body weight/day for Class III, II, and I, respectively. A tiered decision tree proposed by 

Kroes et al. (Kroes et al., 2005; Kroes et al., 2004) expanded these approaches by including 

structural alerts for possible genotoxic and/or high potency carcinogens as well as a TTC value for 

organophosphates. Recently, in order to help facilitate the consistent and transparent application of 

the TTC approach, a freely available software tool – Toxtree (http://toxtree.sourceforge.net/) – was 

developed by the European Commission Joint Research Centre (JRC) for predicting toxicological 

effects and mechanism of action (Lapenna and Worth, 2011). Toxtree implements the approaches 

relevant to TTC assessment, including the original Cramer decision tree and the expanded TTC 

decision tree by (Kroes et al., 2004), and includes improvements to the original Cramer scheme to 

overcome to potential for chemical misclassification. 

G.4.2. Organisation for Economic Co-operation and Development (OECD) Quantitative 

Structure-Activity Relationship (QSAR) Toolbox 

The OECD QSAR Toolbox is another available QSAR-based software tool developed to fill in toxicity 

data gaps for assessing the hazards of chemicals (OECD, 2016), and serves as a platform that 

incorporates various modules, databases, and structure-activity relationship models from a wide 

range of sources. This approach also implements read-across concepts by grouping chemicals into 

categories based on profiles related to physicochemical properties, human health, ecotoxicity, and 

environmental fate. The main features of the OECD QSAR Toolbox are: identification of relevant 

structural characteristics and potential mechanism or mode of action of a target chemical; 

identification of other chemicals that have the same structural characteristics and/or mechanism or 

mode of action; and use of existing experimental data to fill the data gap(s). The Toolbox’s key 

strengths are for screening environmental fate endpoints, physicochemical properties, acute 

ecotoxicity endpoints and toxicity endpoints such as skin/eye irritation, sensitization and 

mutagenicity. 

G.4.3. Application of Data from High Throughput Screening Assays 

In addition to the tools outlined above, there have been recent advances in emerging technologies 

such as high throughput screening (HTS) assays that may aid in prioritizing chemical inventories 

for potential hazard (Wambaugh et al., 2013). HTS assays are in vitro assays that allow rapid 

screening of chemicals for potential toxicity and biological activity across multiple cellular 

pathways and targets (Wetmore et al., 2012; Rotroff et al., 2010). Recent advances have been made 

in dosimetry methods that extrapolate in vitro concentration data to a human oral equivalent dose, 

providing a quantitative estimate of the dose of a chemical that would result in an adverse effect 

(Wetmore et al., 2015; Wetmore et al., 2012; Judson et al., 2011; Rotroff et al., 2010). HTS data may 

also be combined with emerging methods to estimate exposure potential, providing a method to 

refine risk-based prioritization for chemicals with limited toxicity information (Wambaugh et al., 

2013). Consequently, the integration of data from emerging technologies with estimates of human 

oral dose and exposure may provide another potential approach to address risk management needs 

when in vivo toxicology data are not available. 
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-12

Table G-1a. Chemicals reported to be used in hydraulic fracturing fluids, with available chronic oral RfVs, OSFs, and qualitative 

cancer classifications from United States federal sources. 

Chemicals from the FracFocus database are listed first, ranked by IRIS reference dose (RfD). The “--“ symbol indicates that no value was available from the 

sources consulted. Additionally, an “x” indicates the availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties data from EPI 

SuiteTM (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Acrylamide 79-06-1 x x 0.002 0.5

"Likely to be 

carcinogenic 

to humans"

-- -- -- 0.001 -- 0 TT g

Propargyl alcohol 107-19-7 x x 0.002 -- -- -- -- -- -- -- -- --

Furfural 98-01-1 x x 0.003 -- -- -- -- -- -- 0.01 -- --

Benzene 71-43-2 x x 0.004 0.015-

0.055

A (Human 

carcinogen) -- -- -- 0.0005 -- 0 0.005

Dichloromethane 75-09-2 x x 0.006 0.002

“Likely to be 

carcinogenic 

in humans”

-- -- -- 0.06 -- 0 0.005

1,2,3-Trimethylbenzene 526-73-8 x x 0.01 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

1,2,4-Trimethylbenzene 95-63-6 x x 0.01 -- -- -- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-13

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

1,3,5-Trimethylbenzene 108-67-8 x x 0.01 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Trimethylbenzene 25551-13-7 x 0.01 -- -- -- -- -- -- -- -- --

Chlorobenzene 108-90-7 x x 0.02 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- 0.1 0.1

Naphthalene 91-20-3 x x 0.02 --

“Data are 

inadequate 

to assess 

human 

carcinogenic 

potential”

-- -- -- -- -- -- --

1,3-Dichloropropene

542-75-6 x x 0.03 0.05

”Likely to be 

a human 

carcinogen”

-- -- -- 0.03 -- -- --

1,4-Dioxane 123-91-1 x x 0.03 0.1

"Likely to be 

carcinogenic 

to humans"

-- -- -- 0.1 -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-14

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Chlorine dioxide 10049-04-4 x 0.03 --

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- -- -- -- -- -- --

Sodium chlorite 7758-19-2 x 0.03 --

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- -- -- -- -- 1 0.8

Bisphenol A 80-05-7 x x 0.05 -- -- -- -- -- -- -- -- --

Bisphenol A 80-05-7 x x 0.05 -- -- -- -- -- -- -- -- --

Toluene 108-88-3 x x 0.08 --

“Inadequate 

information 

to assess the 

carcinogenic 

potential”

-- -- -- -- -- 1 1

1-Butanol 71-36-3 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

2-Butoxyethanol 111-76-2 x x 0.1 --

“Not likely to 

be carcinogenic to 

humans”

-- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-15

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Acetophenone 98-86-2 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Cumene 98-82-8 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Ethylbenzene 100-41-4 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- 0.7 0.7

Boron 7440-42-8 x 0.2 --

“Data are 

inadequate 

to assess the 

carcinogenic 

potential”

-- -- -- -- -- -- --

Formaldehyde 50-00-0 x x 0.2 --

B1 (Probable 

human 

carcinogen)

-- -- -- 0.2 -- -- --

Xylenes 1330-20-7 x x 0.2 --

“Data are 

inadequate 

to assess the 

carcinogenic 

potential”

-- -- -- 0.2 -- 10 10

2-Methyl-1-

propanol 78-83-1 x x 0.3 -- -- -- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-16

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Phenol 108-95-2 x x 0.3 --

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- -- -- -- -- -- --

Acetone 67-64-1 x x 0.9 --

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- -- -- -- -- -- --

Ethyl acetate 141-78-6 x x 0.9 -- -- -- -- IN -- -- -- --

Ethylene glycol 107-21-1 x x 2 -- -- -- -- -- -- -- -- --

Methanol 67-56-1 x x 2 -- -- -- -- -- -- -- -- --

Benzoic acid 65-85-0 x x 4 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

(E)-Crotonaldehyde 123-73-9 x x -- --

C (Possible 

human 

carcinogen)

0.001 -- -- -- -- -- --

1,2-Propylene 

glycol 57-55-6 x x -- -- -- 20 -- NL -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-17

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

2-(2-Butoxyethoxy)

ethanol 112-34-5 x x -- -- -- 0.03 -- IN -- -- -- --

2-(Thiocyanomethy

lthio)benzothiazole 21564-17-0 x x -- -- -- -- -- -- -- 0.01 -- --

Aluminum 7429-90-5 x -- -- -- 1 -- IN 1 -- -- --

Ammonium 

phosphate 7722-76-1 x -- -- -- 49 -- IN -- -- -- --

Aniline 62-53-3 x x -- 0.0057

B2 (Probable 

human 

carcinogen)

0.007 -- -- -- -- -- --

Benzenesulfonic 

acid, C10-16-alkyl 

derivs.

68584-22-5 x -- -- -- -- -- -- -- 0.5 -- --

Benzyl chloride 100-44-7 x x -- 0.17

B2 (Probable 

human 

carcinogen)

0.002 -- -- -- -- -- --

Bis(2-chloroethyl) 

ether 111-44-4 x x -- 1.1

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --

Didecyldimethylammonium 

chloride

7173-51-5 x x -- -- -- -- -- -- -- 0.1 -- --

Dodecylbenzenesulfonic acid 27176-87-0 x x -- -- -- -- -- -- -- 0.5 -- --

Epichlorohydrin 106-89-8 x x -- 0.0099

B2 (Probable 

human 

carcinogen)

0.006 -- -- -- -- 0 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-18

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Ethylenediamine 107-15-3 x x -- --

D (Not 

classifiable as 

to human 

carcinogenicity)

0.09 -- IN -- -- -- --

Formic acid 64-18-6 x x -- -- -- 0.9 -- IN -- -- -- --

Hexanedioic acid 124-04-9 x x -- -- -- 2 -- -- -- -- -- --

Hydrazine 302-01-2 x -- 3

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --

Iron 7439-89-6 x -- -- -- 0.7 -- IN -- -- -- --

Mineral oil -

includes paraffin oil 8012-95-1 x -- -- -- 3 -- IN -- -- -- --

N,N-Dimethylformamide 68-12-2 x x -- -- -- 0.1 -- IN -- -- -- --

o-Xylene 95-47-6 x x -- -- -- -- -- -- 0.2 -- 10 10

Phosphoric acid 7664-38-2 x -- -- -- 48.6 -- IN -- -- -- --

Potassium 

phosphate, tribasic 7778-53-2 x -- -- -- 49 -- IN -- -- -- --

Quaternary 

ammonium 

compounds, 

benzyl-C12-16-

alkyldimethyl, 

chlorides

68424-85-1 x -- -- -- -- -- -- -- 0.44 -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-19

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Quinoline 91-22-5 x x -- 3

”Likely to be 

carcinogenic 

in humans”

-- -- -- -- -- -- --

Sodium chlorate 7775-09-9 x -- -- -- -- -- -- -- 0.03 -- --

Sodium 

trimetaphosphate 7785-84-4 x -- -- -- 49 -- IN -- -- -- --

Tetrasodium 

pyrophosphate 7722-88-5 x -- -- -- 49 -- IN -- -- -- --

Tricalcium 

phosphate 7758-87-4 x -- -- -- 49 -- IN -- -- -- --

Triphosphoric acid, 

pentasodium salt 7758-29-4 x -- -- -- 49 -- IN -- -- -- --

Trisodium 

phosphate 7601-54-9 x -- -- -- 49 -- IN -- -- -- --

Arsenic 7440-38-2 0.0003 1.5 A (Human 

carcinogen) -- -- -- 0.0003 -- 0 0.01

Phosphine 7803-51-2 0.0003 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Acrolein 107-02-8 x 0.0005 --

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-20

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Chromium (VI) 18540-29-9 0.003 --

Inhaled: A 

(Human 

carcinogen); 

Oral: D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- 0.0009 -- -- --

Di(2-ethylhexyl) 

phthalate 117-81-7 x 0.02 0.014

B2 (Probable 

human 

carcinogen)

-- -- -- 0.06 -- 0 0.006

Chlorine 7782-50-5 0.1 -- -- -- -- -- -- -- -- --

Styrene 100-42-5 x 0.2 -- -- -- -- -- -- -- 0.1 0.1

Zinc 7440-66-6 0.3 --

“Inadequate 

information 

to assess 

carcinogenic 

potential”

-- -- -- 0.3 -- -- --

Acrylic acid 79-10-7 x 0.5 -- -- -- -- IN -- -- -- --

Chromium (III) 16065-83-1 1.5 --

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- -- -- -- -- -- --

Phthalic anhydride 85-44-9 x 2 -- -- -- -- -- -- -- -- --

Cyclohexanone 108-94-1 x 5 -- -- -- -- IN -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-21

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Frac 

Focus 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

RfDa

(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer 

WOE 

characterizationc

Chronic 

oral 

MRLd

(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

1,2-Propylene 

oxide 75-56-9 x -- 0.24

B2 (Probable 

human 

carcinogen)

-- -- -- -- 0.001 -- --

2-(2-Ethoxyethoxy)

ethanol 111-90-0 x -- -- -- 0.06 -- IN -- -- -- --

2-Methoxyethanol 109-86-4 x -- -- -- 0.005 -- IN -- -- -- --

Lead 7439-92-1

-- --

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- 0

TT; 

Action 

Level=0.

015 h

Phosphoric acid, 

aluminium sodium 

salt

7785-88-8 -- -- -- 49 -- IN -- -- -- --

Phosphoric acid, 

diammonium salt 7783-28-0 -- -- -- 49 -- IN -- -- -- --

Polyphosphoric 

acids, sodium salts 68915-31-1 -- -- -- 49 -- IN -- -- -- --

p-Xylene 106-42-3 x -- -- -- -- -- -- 0.2 -- 10 10

Sodium 

pyrophosphate 7758-16-9 -- -- -- 49 -- IN -- -- -- --

Tributyl phosphate 126-73-8 x -- -- -- 0.01 0.009 LI 0.08 -- -- --

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; NPDWRs = National Primary Drinking Water Regulations.

a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population (including sensitive subgroups) 

that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observedadverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally used in the EPA's 

noncancer health assessments. Chronic RfD: Duration of exposure is up to a lifetime.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-22

b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime oral exposure to an agent. This estimate, usually 

expressed in units of proportion (of a population) affected per mg/kg-day, is generally reserved for use in the low dose region of the dose response relationship, that is, for 

exposures corresponding to risks less than 1 in 100. 

c Weight of evidence (WOE) characterization for carcinogenicity: A system used for characterizing the extent to which the available data support the hypothesis that an agent 

causes cancer in humans. See glossary for details.

d Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of 

harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs 

should not be used as predictors of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer. 

e Maximum contaminant level goal (MCLG): 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.

f Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to the MCLG as feasible using the best available 

analytical and treatment technologies and taking cost into consideration. MCLs are enforceable standards.

g

 In public water systems, acrylamide is regulated by a Treatment Technique (TT). Public water systems must certify annually that when acrylamide is used to treat water, the 

combination of dose and monomer level does not exceed 0.05% dosed at 1 mg/l (or equivalent).

h

 In public water systems, lead is regulated by a Treatment Technique (TT) that requires systems to control the corrosiveness of their water. If more than 10% of tap water 

exceeds the action level of 0.015 mg/l, water systems must take additional steps.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-23

Table G-1b. Chemicals reported to be used in hydraulic fracturing fluids, with available 

chronic oral RfVs and OSFs from state sources. 

Chemicals from the FracFocus database are listed first, ranked by CalEPA maximum allowable daily level (MADL). 

The “--“ symbol indicates that no value was available from the sources consulted. Additionally, an “x” indicates the 

availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties data from EPI SuiteTM

(see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

CalEPA

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available

Oral MADLa

(μg/day)

OSFb(per 

mg/kg-day)

Ethylene oxide 75-21-8 x x 20 0.31

Benzene 71-43-2 x x 24 0.1

Acrylamide 79-06-1 x x 140 4.5

N-Methyl-2-pyrrolidone 872-50-4 x x 17000 --

1,3-Butadiene 106-99-0 x x -- 0.6

1,3-Dichloropropene 542-75-6 x x -- 0.091

1,4-Dioxane 123-91-1 x x -- 0.027

Aniline 62-53-3 x x -- 0.0057

Benzyl chloride 100-44-7 x x -- 0.17

Bis(2-chloroethyl) ether 111-44-4 x x -- 2.5

Dichloromethane 75-09-2 x x -- 0.014

Epichlorohydrin 106-89-8 x x -- 0.08

Ethylbenzene 100-41-4 x x -- 0.011

Hydrazine 302-01-2 x -- 3

Nitrilotriacetic acid 139-13-9 x x -- 0.0053

Nitrilotriacetic acid trisodium 

monohydrate 18662-53-8 x x -- 0.01

Thiourea 62-56-6 x x -- 0.072

Lead 7439-92-1 0.5 0.0085

Chromium (VI) 18540-29-9 8.2 0.5
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-24

CalEPA

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available

Oral MADLa

(μg/day)

OSFb(per 

mg/kg-day)

Di(2-ethylhexyl) phthalate 117-81-7 x

20 (neonate male); 

58 (infant male); 

410 (adult)

0.003

2-Methoxyethanol 109-86-4 x 63 --

2-Ethoxyethanol 110-80-5 x 750 --

1,2-Propylene oxide 75-56-9 x -- 0.24

Arsenic 7440-38-2 -- 9.5

CASRN = Chemical Abstract Service Registry Number; CalEPA = California Environmental Protection Agency.

a Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive toxicant at which the chemical 

would have no observable adverse reproductive effect, assuming exposure at 1,000 times that level. 

b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime 

oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per mg/kg day, is 

generally reserved for use in the low-dose region of the dose-response relationship, that is, for exposures corresponding to 

risks less than 1 in 100.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-25

Table G-1c. Chemicals reported to be used in hydraulic fracturing fluids, with available 

chronic oral RfVs and OSFs from international sources. 

Chemicals from the FracFocus database are listed first, ranked by CICAD reference value (TDI- tolerable daily 

intake). An “x” indicates the availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical 

properties data from EPI SuiteTM (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids 

and produced water. 

Chemical name CASRN

FracFocus data 

available

Physicochemical 

data available

IPCS CICAD Chronic 

TDIa(mg/kg-day)

Potassium iodide 7681-11-0 x 0.01

Sodium iodide 7681-82-5 x 0.01

Copper(I) iodide 7681-65-4 x 0.01

Ethylene glycol 107-21-1 x x 0.05

D-Limonene 5989-27-5 x x 0.1

Glyoxal 107-22-2 x x 0.2

N-Methyl-2-pyrrolidone 872-50-4 x x 0.6

Chromium (VI) 18540-29-9 0.0009

Strontium chloride 10476-85-4 0.13

CASRN = Chemical Abstract Service Registry Number; IPCS = International Programme on Chemical Safety; CICAD = Concise 

International Chemical Assessment Documents. 

a Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass basis, to which an individual in 

a (sub) population may be exposed daily over its lifetime without appreciable health risk.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-26

Table G-1d. Chemicals reported to be used in hydraulic fracturing fluids, with available lessthan-chronic oral RfVs and OSFs. 

Chemicals from the FracFocus database are listed first, ranked by PPRTV subchronic reference dose (sRfD). The “--“ 

symbol indicates that no value was available from the sources consulted. Additionally, an “x” indicates the 

availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties data from EPI SuiteTM

(see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

PPRTV ATSDR

Chemical name CASRN

FracFocus 

data 

available

Physicochemical 

data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Inter-mediate 

oral MRLb

(mg/kg-day)

Benzyl chloride 100-44-7 x x 0.002 -- --

Epichlorohydrin 106-89-8 x x 0.006 -- --

(E)-Crotonaldehyde 123-73-9 x x 0.01 -- --

Benzene 71-43-2 x x 0.01 -- --

Ethylbenzene 100-41-4 x x 0.05 -- 0.4

Chlorobenzene 108-90-7 x x 0.07 -- 0.4

Ethylenediamine 107-15-3 x x 0.2 -- --

2-(2-Butoxyethoxy)eth

anol 112-34-5 x x 0.3 -- --

Hexane 110-54-3 x x 0.3 -- --

N,N-Dimethylformamide 68-12-2 x x 0.3 -- --

Xylenes 1330-20-7 x x 0.4 1 0.4

Antimony trioxide 1309-64-4 x 0.5 -- --

Ethyl acetate 141-78-6 x x 0.7 -- --

Iron 7439-89-6 x 0.7 -- --

Toluene 108-88-3 x x 0.8 0.8 0.02

Formic acid 64-18-6 x x 0.9 -- --

Hexanedioic acid 124-04-9 x x 2 -- --

Benzoic acid 65-85-0 x x 4 -- --

1,2-Propylene glycol 57-55-6 x x 20 -- --

Mineral oil - includes 

paraffin oil 8012-95-1 x 30 -- --

Phosphoric acid 7664-38-2 x 48.6 -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-27

PPRTV ATSDR

Chemical name CASRN

FracFocus 

data 

available

Physicochemical 

data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Inter-mediate 

oral MRLb

(mg/kg-day)

Ammonium phosphate 7722-76-1 x 49 -- --

Potassium phosphate, 

tribasic 7778-53-2 x 49 -- --

Sodium 

trimetaphosphate 7785-84-4 x 49 -- --

Tetrasodium 

pyrophosphate 7722-88-5 x 49 -- --

Tricalcium phosphate 7758-87-4 x 49 -- --

Triphosphoric acid, 

pentasodium salt 7758-29-4 x 49 -- --

Trisodium phosphate 7601-54-9 x 49 -- --

1,3-Dichloropropene 542-75-6 x x -- -- 0.04

1,4-Dioxane 123-91-1 x x -- 5 0.5

2-Butoxyethanol 111-76-2 x x -- 0.4 0.07

Acetone 67-64-1 x x -- -- 2

Acrylamide 79-06-1 x x -- 0.01 0.001

Aluminum 7429-90-5 x -- -- 1

Boron 7440-42-8 x -- 0.2 0.2

Dichloromethane 75-09-2 x x -- 0.2 --

Ethylene glycol 107-21-1 x x -- 0.8 0.8

Formaldehyde 50-00-0 x x -- -- 0.3

Naphthalene 91-20-3 x x -- 0.6 0.6

o-Xylene 95-47-6 x x -- 1 0.4

Phenol 108-95-2 x x -- 1 --

Sodium chlorite 7758-19-2 x -- -- 0.1

Antimony trichloride 10025-91-9 0.0004 -- --

2-Methoxyethanol 109-86-4 x 0.02 -- --

Tributyl phosphate 126-73-8 x 0.03 1.1 0.08

Acrylic acid 79-10-7 x 0.2 -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-28

PPRTV ATSDR

Chemical name CASRN

FracFocus 

data 

available

Physicochemical 

data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Inter-mediate 

oral MRLb

(mg/kg-day)

2-(2-Ethoxyethoxy)

ethanol 111-90-0 x 0.6 -- --

Cyclohexanone 108-94-1 x 2 -- --

Phosphoric acid, 

aluminium sodium salt 7785-88-8 49 -- --

Phosphoric acid, 

diammonium salt 7783-28-0 49 -- --

Polyphosphoric acids, 

sodium salts 68915-31-1 49 -- --

Sodium 

pyrophosphate 7758-16-9 49 -- --

Acrolein 107-02-8 x -- -- 0.004

Arsenic 7440-38-2 -- 0.005 --

Chromium (VI) 18540-29-9 -- -- 0.005

Copper 7440-50-8 -- 0.01 0.01

Di(2-ethylhexyl) 

phthalate 117-81-7 x -- -- 0.1

p-Xylene 106-42-3 x -- 1 0.4

Styrene 100-42-5 x -- 0.1 --

Zinc 7440-66-6 -- -- 0.3

CASRN = Chemical Abstract Service Registry Number; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for 

Toxic Substances and Disease Registry; HHBP = Human Health Benchmarks for Pesticides.

a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the 

human population (including sensitive subgroups) that is likely to be without an appreciable risk of deleterious effects during a 

lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observed-adverse-effect level (LOAEL), or 

benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally 

used in the EPA's noncancer health assessments. Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average 

lifespan.

b Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the 

substance is unlikely to pose a measurable risk of harmful (adverse), noncancerous effects. MRLs are calculated for a route of 

exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs should not be used as 

predictors of harmful (adverse) health effects. Acute MRL: Duration of exposure is 1 to 14 days. Intermediate MRL: Duration of 

exposure is >14 to 364 days.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-29

Table G-1e. Available qualitative cancer classifications for chemicals reported to be used in 

hydraulic fracturing fluids. 

Chemicals from the FracFocus database are listed first, with chemicals classified as known carcinogens by one or 

more sources listed first. See the Appendix G glossary (Section G.3) for details on the weight of evidence 

characterizations. The “--“ symbol indicates that no value was available from the sources consulted. Additionally,

an “x” indicates the availability of usage data from FracFocus (U.S. EPA, 2015a) and physicochemical properties 

data from EPI SuiteTM (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and 

produced water. Cancer classifications from IRIS and PPRTV are also listed in Table G-1a.

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

1,3-Butadiene 106-99-0 x x

"Carcinogenic 

to humans" -- 1 Known

Arsenic 7440-38-2

A (Human 

carcinogen) -- 1 Known

Benzene 71-43-2 x x

A (Human 

carcinogen) -- 1 Known

Chromium (VI) 18540-29-9

Inhaled: A 

(Human 

carcinogen);

Oral: D (Not 

classifiable as 

to human 

carcinogenicity)

-- 1 Known

Ethanol 64-17-5 x x -- -- 1 --

Ethylene oxide 75-21-8 x x -- -- 1 Known

Formaldehyde 50-00-0 x x

B1 (Probable 

human 

carcinogen)

-- 1 Known

Nickel sulfate 7786-81-4 x -- -- 1 --

Nickel(II) sulfate 

hexahydrate 10101-97-0 -- -- 1 --

Quartz-alpha 

(SiO2)

14808-60-7 x -- -- 1 --

Sulfuric acid 7664-93-9 x -- -- 1 Known

(E)-

Crotonaldehyde 123-73-9 x x

C (Possible 

human 

carcinogen)

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-30

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

1,2-Propylene 

oxide 75-56-9 x

B2 (Probable 

human 

carcinogen)

-- 2B RAHC

1,3-

Dichloropropene 542-75-6 x x

”Likely to be 

a human 

carcinogen”

-- 2B RAHC

1,4-Dioxane 123-91-1 x x

"Likely to be 

carcinogenic 

to humans"

-- 2B RAHC

4-Methyl-2-

pentanone

108-10-1 x x

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- 2B --

Acetaldehyde 75-07-0 x x

B2 (Probable 

human 

carcinogen)

-- 2B RAHC

Acrylamide 79-06-1 x x

"Likely to be 

carcinogenic 

to humans"

-- 2A RAHC

Aniline 62-53-3 x x

B2 (Probable 

human 

carcinogen)

-- 3 --

Antimony 

trioxide 1309-64-4 x --

Inhaled: 

"Suggestive 

evidence of 

carcinogenic 

potential";

Oral: "Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

2B --

Attapulgite 12174-11-7 x -- -- 2B or 3 --

Benzyl chloride 100-44-7 x x

B2 (Probable 

human 

carcinogen)

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-31

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Bis(2-chloroethyl) 

ether 111-44-4 x x

B2 (Probable 

human 

carcinogen)

-- 3 --

Carbon black 1333-86-4 -- -- 2B --

Coconut oil 

acid/Diethanolamine condensate 

(2:1)

68603-42-9 x -- -- 2B --

Cumene 98-82-8 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

-- 2B RAHC

Di(2-ethylhexyl) 

phthalate 117-81-7 x

B2 (Probable 

human 

carcinogen)

-- 2B RAHC

Dibromoacetonitrile 3252-43-5 x x -- -- 2B --

Dichloromethane 75-09-2 x x

“Likely to be 

carcinogenic 

in humans”

-- 2A RAHC

Diethanolamine 111-42-2 x x -- -- 2B --

Epichlorohydrin 106-89-8 x x

B2 (Probable 

human 

carcinogen)

-- 2A RAHC

Ethylbenzene 100-41-4 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

-- 2B --

Hydrazine 302-01-2 x

B2 (Probable 

human 

carcinogen)

-- 2A RAHC

Lead 7439-92-1

B2 (Probable 

human 

carcinogen)

-- 2B RAHC
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-32

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

N,N-Dimethylformamide 68-12-2 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

2A --

Naphthalene 91-20-3 x x

“Data are 

inadequate to 

assess human 

carcinogenic 

potential”

-- 2B RAHC

Nitrilotriacetic 

acid 139-13-9 x x -- -- 2B RAHC

Quinoline 91-22-5 x x

”Likely to be 

carcinogenic 

in humans”

-- -- --

Styrene 100-42-5 x -- -- 2B RAHC

Thiourea 62-56-6 x x -- -- 3 RAHC

Titanium dioxide 13463-67-7 x -- -- 2B

Tributyl 

phosphate 126-73-8 x --

"Likely to be 

carcinogenic to 

humans"

-- --

1,2,3-

Trimethylbenzene 526-73-8 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

1,3,5-

Trimethylbenzene 108-67-8 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

1-Butanol 71-36-3 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-33

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

1-Propene 115-07-1 x x -- -- 3 --

1-tert-Butoxy-2-

propanol 57018-52-7 x x -- -- 3 --

2-(2-Butoxyethoxy)ethanol 112-34-5 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

2-(2-Ethoxyethoxy) ethanol 111-90-0 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

2-Butoxyethanol 111-76-2 x x

“Not likely to 

be 

carcinogenic 

to humans”

-- 3 --

2-

Methoxyethanol 109-86-4 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Acetone 67-64-1 x x

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- -- --

Acetophenone 98-86-2 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-34

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Acrolein 107-02-8 x

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- 3 --

Acrylic acid 79-10-7 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

3 --

Aluminum 7429-90-5 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Amaranth 915-67-3 x x -- -- 3 --

Ammonium 

phosphate 7722-76-1 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Benzoic acid 65-85-0 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- --

Boron 7440-42-8 x

“Data are 

inadequate to 

assess the 

carcinogenic 

potential”

-- -- --

Chlorine dioxide 10049-04-4 x

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-35

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Chlorobenzene 108-90-7 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

Chloromethane 74-87-3 x x

"Carcinogenic 

potential 

cannot be 

determined"

-- 3 --

Chromium (III) 16065-83-1

“Data are 

inadequate 

for an 

assessment

of human 

carcinogenic 

potential”

-- 3 --

Coumarin 91-64-5 x -- -- 3 --

Cyclohexanone 108-94-1 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

3 --

Dapsone 80-08-0 x x -- -- 3 --

D-Limonene 5989-27-5 x x -- -- 3 --

Ethyl acetate 141-78-6 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Ethylene 74-85-1 x x -- -- 3 --

Ethylenediamine 107-15-3 x x

D (Not 

classifiable as 

to human 

carcinogenicity)

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

FD&C Blue no. 1 3844-45-9 x x -- -- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-36

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

FD&C Yellow 6 2783-94-0 x -- -- 3 --

Formic acid 64-18-6 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Furfural 98-01-1 x x -- -- 3 --

Hematite 1317-60-8 x -- -- 3 --

Hexane 110-54-3 x x

"Inadequate 

information 

to assess the 

carcinogenic 

potential"

-- -- --

Hydrochloric acid 7647-01-0 x -- -- 3 --

Hydrogen 

peroxide 7722-84-1 x -- -- 3 --

Iron 7439-89-6 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Iron(III) oxide 1309-37-1 x -- -- 3 --

Isopropanol 67-63-0 x x -- -- 3 --

Latex 2000 TM 9003-55-8 -- -- 3 --

Ligroine 8032-32-4 -- -- 3 --

Mineral oil -

includes paraffin 

oil

8012-95-1 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Mineral spirits 64475-85-0 -- -- 3 --

Morpholine 110-91-8 x x -- -- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-37

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Pentane 109-66-0 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic

potential"

-- --

Petroleum 8002-05-9 x -- -- 3 --

Phenanthrene 85-01-8 x -- -- 3 --

Phenol 108-95-2 x x

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- 3 --

Phosphine 7803-51-2

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- --

Phosphoric acid 7664-38-2 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Phosphoric acid, 

aluminium 

sodium salt

7785-88-8 --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Phosphoric acid, 

diammonium salt 7783-28-0 --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Policapram 

(Nylon 6) 25038-54-4 x -- -- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-38

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Poly(tetrafluoroethylene) 9002-84-0 x -- -- 3 --

Polyphosphoric 

acids, sodium 

salts

68915-31-1 --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Polyvinyl acetate 

copolymer 9003-20-7 -- -- 3 --

Polyvinyl alcohol 9002-89-5 -- -- 3 --

Polyvinylpyrrolidone 9003-39-8 x -- -- 3 --

Potassium 

phosphate, 

tribasic

7778-53-2 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Rhodamine B 81-88-9 x -- -- 3 --

Silica 7631-86-9 x -- -- 3 --

Sodium bisulfite 7631-90-5 x -- -- 3 --

Sodium chlorite 7758-19-2 x

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- 3 --

Sodium 

metabisulfite 7681-57-4 x -- -- 3 --

Sodium 

pyrophosphate 7758-16-9 --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Sodium sulfite 7757-83-7 x -- -- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-39

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Sodium 

trimetaphosphate7785-84-4 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Stoddard solvent 8052-41-3 x -- -- 3 --

Sulfan blue 129-17-9 x x -- -- 3 --

Sulfur dioxide 7446-09-5 x -- -- 3 --

Talc 14807-96-6 x -- -- 3 --

Tetrasodium 

pyrophosphate 7722-88-5 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Toluene 108-88-3 x x

“Inadequate 

information 

to assess the 

carcinogenic 

potential”

-- 3 --

Tricalcium 

phosphate 7758-87-4 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Triethanolamine 102-71-6 x x -- -- 3 --

Triphosphoric 

acid, pentasodium salt

7758-29-4 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Trisodium 

phosphate 7601-54-9 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-40

Qualitative cancer classification

Chemical name CASRN

FracFocus 

data 

available

Physicochemical data 

available IRISa PPRTVbIARCc RoCd

Xylenes 1330-20-7 x x

“Data are 

inadequate to 

assess the 

carcinogenic 

potential”

-- 3 --

Zeolites 1318-02-1 -- -- 3 --

Zinc 7440-66-6

“Inadequate 

information 

to assess 

carcinogenic 

potential”

-- -- --

1,2-Propylene 

glycol 57-55-6 x x --

"Not likely to 

be carcinogenic 

to humans"

-- --

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

IRIS assessments use the 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. 

b PPRTV assessments use the 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.

c 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.

d The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated 

to be a human carcinogen.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-41

Table G-2a. Chemicals reported to be detected in produced water, with available chronic oral RfVs, OSFs, and qualitative cancer 

classifications from United States federal sources. 

Chemicals are ranked by IRIS reference dose (RfD). The “--“ symbol indicates that no value was available from the sources consulted. Additionally, an “x” 

indicates the availability of measured concentration data in produced water (see Appendix E) and physicochemical properties data from EPI SuiteTM (see 

Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Heptachlor 

epoxide 1024-57-3 x 0.000013 9.1

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- 0 0.0002

Phosphorus 7723-14-0 x 0.00002 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Aldrin 309-00-2 x 0.00003 17

B2 (Probable 

human 

carcinogen)

-- -- -- 0.00003 -- -- --

Dieldrin 60-57-1 x 0.00005 16

B2 (Probable 

human 

carcinogen)

-- -- -- 0.00005 -- -- --

Arsenic 7440-38-2 x 0.0003 1.5 A (Human 

carcinogen) -- -- -- 0.0003 -- 0 0.01

Lindane 58-89-9 x 0.0003 -- -- -- -- -- -- -- 0.0002 0.0002
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-42

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Antimony 7440-36-0 x 0.0004 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- 0.006 0.006

Acrolein 107-02-8 x 0.0005 --

“Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential”

-- -- -- -- -- -- --

Heptachlor 76-44-8 x 0.0005 4.5

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- 0 0.0004

Cyanide 57-12-5 x 0.0006 --

“Inadequate 

information 

to assess the 

carcinogenic 

potential”

-- -- -- -- -- 0.2 0.2

Pyridine 110-86-1 x x 0.001 -- -- -- -- -- -- -- -- --

Methyl bromide 74-83-9 x 0.0014 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- 0.02 -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-43

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Beryllium 7440-41-7 x 0.002 --

B1 (Probable 

human 

carcinogen)

-- -- -- 0.002 -- 0.004 0.004

Propargyl 

alcohol 107-19-7 x 0.002 -- -- -- -- -- -- -- -- --

2,4-

Dichlorophenol

120-83-2 x x

0.003 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Benzidine 92-87-5 x x

0.003 230 A (Human 

carcinogen) -- -- -- -- -- -- --

Chromium (VI) 18540-29-9 x 0.003 --

Inhaled: A 

(Human 

carcinogen; 

Oral: D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- 0.0009 -- -- --

2-Methylnaphth

alene 91-57-6 x x 0.004 --

“Data are 

inadequate 

to assess 

human 

carcinogenic 

potential”

-- -- -- 0.04 -- -- --

Benzene 71-43-2 x x 0.004 0.015-

0.055

A (Human 

carcinogen) -- -- -- 0.0005 -- 0 0.005
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-44

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Molybdenum 7439-98-7 x 0.005 -- -- -- -- -- -- -- -- --

Selenium 7782-49-2 x 0.005 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- 0.005 -- 0.05 0.05

Silver 7440-22-4 x 0.005 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Dichloromethane

75-09-2 x 0.006 0.002

“Likely to be 

carcinogenic 

in humans”

-- -- -- 0.06 -- 0 0.005

Tetrachloroethene 127-18-4 x 0.006 0.0021

“Likely to be 

carcinogenic 

in humans”

-- -- -- 0.008 -- 0 0.005

1,2,3-Trimethylbenzene

526-73-8 x 0.01 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

1,2,4-Trichlorobenzene 120-82-1 x 0.01 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- 0.029

"Likely to be 

carcinogenic 

to humans"

0.1 -- 0.07 0.07
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-45

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

1,2,4-Trimethylbenzene 95-63-6 x x 0.01 -- -- -- -- -- -- -- -- --

1,3,5-Trimethylbenzene 108-67-8 x x 0.01 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Chloroform 67-66-3 x x 0.01 --

B2 (Probable 

human 

carcinogen)

-- -- -- 0.01 -- -- --

Trimethylbenzene

25551-13-7 0.01 -- -- -- -- -- -- -- -- --

2,4-

Dimethylphenol 105-67-9 x x 0.02 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Bromodichloromethane 75-27-4 x 0.02 0.062

B2 (Probable 

human 

carcinogen)

-- -- -- 0.02 -- -- --

Bromoform 75-25-2 x 0.02 0.0079

B2 (Probable 

human 

carcinogen)

-- -- -- 0.02 -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-46

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Chlorobenzene 108-90-7 x 0.02 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- 0.1 0.1

Chlorodibromomethane 124-48-1 x 0.02 0.084

C (Possible 

human 

carcinogen)

-- -- -- 0.09 -- -- --

Di(2-ethylhexyl) 

phthalate 117-81-7 x x 0.02 0.014

B2 (Probable 

human 

carcinogen)

-- -- -- 0.06 -- 0 0.006

Naphthalene 91-20-3 x x 0.02 --

“Data are 

inadequate 

to assess 

human 

carcinogenic 

potential”

-- -- -- -- -- -- --

Diphenylamine 122-39-4 x x 0.025 -- -- -- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- 0.1 -- --

1,4-Dioxane 123-91-1 x x 0.03 0.1

"Likely to be 

carcinogenic 

to humans"

-- -- -- 0.1 -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-47

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Pyrene 129-00-0 x x 0.03 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Fluoranthene 206-44-0 x x 0.04 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Fluorene 86-73-7 x x 0.04 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Bisphenol A 80-05-7 x 0.05 -- -- -- -- -- -- -- -- --

m-Cresol 108-39-4 x x 0.05 --

C (Possible 

human 

carcinogen)

-- -- -- -- -- -- --

o-Cresol 95-48-7 x x 0.05 --

C (Possible 

human 

carcinogen)

-- --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-48

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Toluene 108-88-3 x x 0.08 --

“Inadequate 

information 

to assess the 

carcinogenic 

potential”

-- -- -- -- -- 1 1

1-Butanol 71-36-3 x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicit

y)

-- -- -- -- -- -- --

2-

Butoxyethanol 111-76-2 x 0.1 --

“Not likely to 

be carcinogenic to 

humans”

-- -- -- -- -- -- --

Acetophenone 98-86-2 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Carbon disulfide 75-15-0 x x 0.1 -- -- -- -- -- -- -- -- --

Chlorine 7782-50-5 0.1 -- -- -- -- -- -- -- -- --

Cumene 98-82-8 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-49

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Dibutyl 

phthalate 84-74-2 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Ethylbenzene 100-41-4 x x 0.1 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- 0.7 0.7

Nitrite 14797-65-0 x 0.1 -- -- -- -- -- -- -- 1 1

Manganese 7439-96-5 x 0.14 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Barium 7440-39-3 x 0.2 --

”Not likely to 

be carcinogenic to 

humans”

-- -- -- 0.2 -- 2 2

Benzyl butyl 

phthalate 85-68-7 x x

0.2 --

C (Possible 

human 

carcinogen)

-- -- -- -- -- -- --

Boron 7440-42-8 x 0.2 --

“Data are 

inadequate 

to assess the 

carcinogenic 

potential”

-- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-50

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Xylenes 1330-20-7 x x 0.2 --

“Data are 

inadequate 

to assess the 

carcinogenic 

potential”

-- -- -- 0.2 -- 10 10

Phenol 108-95-2 x x 0.3 --

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- -- -- -- -- -- --

Zinc 7440-66-6 x 0.3 --

“Inadequate 

information 

to assess 

carcinogenic 

potential”

-- -- -- 0.3 -- -- --

Biphenyl 92-52-4 x x

0.5 0.008

"Suggestive 

evidence of 

carcinogenic 

potential"

-- -- -- -- -- -- --

Caprolactam 105-60-2 x x 0.5 -- -- -- -- -- -- -- -- --

Methyl ethyl 

ketone 78-93-3 x 0.6 --

“Data are 

inadequate 

to assess 

carcinogenic 

potential”

-- -- -- -- -- -- --

Strontium 7440-24-6 x 0.6 -- -- -- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-51

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Diethyl 

phthalate 84-66-2 x 0.8 --

D (Not 

classifiable as 

to human 

carcinogenicity)

-- -- -- -- -- -- --

Acetone 67-64-1 x x 0.9 --

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- -- -- -- -- -- --

Chromium (III) 16065-83-1 x 1.5 --

“Data are 

inadequate 

to assess 

human 

carcinogenicity”

-- -- -- -- -- -- --

Nitrate 14797-55-8 x 1.6 -- -- -- -- -- -- -- 10 10

Ethylene glycol 107-21-1 x 2 -- -- -- -- -- -- -- -- --

Methanol 67-56-1 x 2 -- -- -- -- -- -- -- -- --

Cadmium 7440-43-9 x

0.0005 

(water) --

B1 (Probable 

human 

carcinogen)

-- -- -- 0.0001 -- 0.005 0.005

1,1-Dichloroethane 75-34-3 x -- --

C (Possible 

human 

carcinogen)

0.2 -- -- -- -- -- --

1,2-Diphenylhydrazine 122-66-7 x x

-- 0.8

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-52

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

1,2-Propylene 

glycol 57-55-6 x -- -- -- 20 --

"Not likely 

to be 

carcinogenic 

to humans"

-- -- -- --

1-Methylnaphthalene 90-12-0 x -- -- -- 0.007 0.029 -- 0.07 -- -- --

2-(2-Butoxyethoxy)ethanol 112-34-5 x -- -- -- 0.03 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

2-Chloroethanol 107-07-3 x -- -- -- 0.02 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- 0.045 -- --

Acrylonitrile 107-13-1 x -- 0.54

B1 (Probable 

human 

carcinogen)

-- -- -- 0.04 -- -- --

Alpha particle 12587-46-1 x -- -- -- -- -- -- -- -- -- 15

Aluminum 7429-90-5 x -- -- -- 1 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

1 -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-53

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Benz(a)anthracene 56-55-3 x x-- --

B2 (Probable 

human 

carcinogen)

-- 0.7 -- -- -- -- --

Benzo(a)pyrene 50-32-8 x x -- 7.3

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- 0 0.0002

Benzyl alcohol 100-51-6 x x -- -- -- 0.1 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Benzyl chloride 100-44-7 x -- 0.17

B2 (Probable 

human 

carcinogen)

0.002 -- -- -- -- -- --

Beta particle 12587-47-2 x -- -- -- -- -- -- -- -- -- 4

betaHexachloro

cyclohexane

319-85-7 x -- 1.8

C (Possible 

human 

carcinogen)

-- -- -- -- -- -- --

Bis(2-chloroethyl) ether 111-44-4 x -- 1.1

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --

Butylbenzene 104-51-8 x -- -- -- 0.05 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-54

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Cobalt 7440-48-4 x -- -- -- 0.0003 --

"Likely to be 

carcinogenic 

to humans"

-- -- -- --

Copper 7440-50-8

x

-- -- -- -- -- -- -- -- 1.3

TT; 

Action 

Level=1.3

g

Dibenzothiophene 132-65-0 x -- -- -- 0.01 -- -- -- -- -- --

Fluoride 16984-48-8 x -- -- -- -- -- -- -- -- 4 4

Formic acid 64-18-6 x -- -- -- 0.9 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

Hydrazine 302-01-2 -- 3

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --

Iron 7439-89-6 x -- -- -- 0.7 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-55

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Lead 7439-92-1 x -- --

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- 0

TT; 

Action 

Level=0.0

15 g

Lithium 7439-93-2 x -- -- -- 0.002 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

m,p-Cresol 

mixture

NOCAS_

24858 -- -- -- -- -- -- 0.1 -- -- --

m-Xylene 108-38-3 x -- -- -- -- -- -- 0.2 -- 10 10

N,N-Dimethylformamide 68-12-2 x -- -- -- 0.1 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

N-Nitrosodiphenylamine 86-30-6 x x -- 0.0049

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --

N-Nitroso-Nmethylethylamine

10595-95-6 x x -- 22

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-56

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Nonane 111-84-2 x -- -- -- 0.0003 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

o-Xylene 95-47-6 x -- -- -- -- -- -- 0.2 -- 10 10

p,p'-DDE 72-55-9 x -- 0.34

B2 (Probable 

human 

carcinogen)

-- -- -- -- -- -- --

Phorate 298-02-2 x -- -- -- -- -- -- -- 0.0005 -- --

p-Xylene 106-42-3 x -- -- -- -- -- -- 0.2 -- 10 10

Quinoline 91-22-5 x -- 3

”Likely to be 

carcinogenic 

in humans”

-- -- -- -- -- -- --

Radium 7440-14-4 x -- -- -- -- -- -- -- -- -- 5 pCi/L

Radium-226 13982-63-3 x -- -- -- -- -- -- -- -- -- 5 pCi/L

Radium-228 15262-20-1 x -- -- -- -- -- -- -- -- -- 5 pCi/L

Thallium 7440-28-0 x -- -- -- -- -- -- -- -- 0.0005 0.002

Tributyl 

phosphate 126-73-8 x x -- -- -- 0.01 0.009

"Likely to be 

carcinogenic 

to humans"

0.08 -- -- --

Uranium-235 15117-96-1 x -- -- -- -- -- -- -- -- -- 30

Uranium-238 7440-61-1 x -- -- -- -- -- -- -- -- -- 30
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-57

IRIS PPRTV ATSDR HHBP NPDWRs

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic 

RfDa(mg/

kg-day)

OSFb

(per mg/

kg-day)

Cancer WOE 

characterizationc

Chronic oral 

MRLd(mg/

kg-day)

Chronic 

RfDa

(mg/kgday)

Public 

health 

goale

(MCLG) 

(mg/L)

MCLf

(mg/L)

Vanadium 7440-62-2 x -- --

“Data are 

inadequate 

to assess 

carcinogenic 

potential”

0.00007 --

"Data are 

inadequate 

for an 

assessment 

of human 

carcinogenic 

potential"

-- -- -- --

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; NPDWRs = National Primary Drinking Water Regulations.

a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population (including sensitive subgroups) 

that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observedadverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally used in the EPA's 

noncancer health assessments. Chronic RfD: Duration of exposure is up to a lifetime.

b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime oral exposure to an agent. This estimate, usually 

expressed in units of proportion (of a population) affected per mg/kg day, is generally reserved for use in the low dose region of the dose response relationship, that is, for 

exposures corresponding to risks less than 1 in 100. 

c Weight of evidence (WOE) characterization for carcinogenicity: A system used for characterizing the extent to which the available data support the hypothesis that an agent 

causes cancer in humans. See glossary for details.

d Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of 

harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs 

should not be used as predictors of harmful (adverse) health effects. Chronic MRL: Duration of exposure is 365 days or longer. 

e Maximum contaminant level goal (MCLG): 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.

f Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to the MCLG as feasible using the best available 

analytical and treatment technologies and taking cost into consideration. MCLs are enforceable standards.

g

In public water systems, lead and copper are regulated by a Treatment Technique (TT) that requires systems to control the corrosiveness of their water. If more than 10% of 

tap water exceeds the action level, water systems must take additional steps. For copper, the action level is 1.3 mg/l, and for lead is 0.015 mg/l.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-58

Table G-2b. Chemicals reported to be detected in produced water, with available chronic oral 

RfVs and OSFs from state sources. 

Chemicals are ranked by CalEPA maximum allowable daily level (MADL). The “--“ symbol indicates that no value 

was available from the sources consulted. Additionally, an “x” indicates the availability of measured concentration 

data in produced water (see Appendix E) and physicochemical properties data from EPI SuiteTM (see Appendix C). 

Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

CalEPA

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Oral MADLa

(μg/day)

OSFb(per 

mg/kg-day)

Lead 7439-92-1 x 0.5 0.0085

Cadmium 7440-43-9 x 4.1 15

Chromium (VI) 18540-29-9 x 8.2 0.5

Dibutyl phthalate 84-74-2 x x 8.7 --

Benzene 71-43-2 x x 24 0.1

Benzyl butyl phthalate 85-68-7 x x 1200 --

1,2-Benzenedicarboxylic acid, 

1,2-bis(8-methylnonyl) ester 89-16-7 x 2200 --

Diisodecyl phthalate 26761-40-0 x 2,200 --

Di(2-ethylhexyl) phthalate 117-81-7 x x

20 (neonate 

male); 58 (infant 

male); 410 (adult)

0.003

1,2,4-Trichlorobenzene 120-82-1 x -- 0.0036

1,4-Dioxane 123-91-1 x x -- 0.027

7,12-Dimethylbenz(a)anthracene 57-97-6 x -- 250

Acrylonitrile 107-13-1 x -- 1

Aldrin 309-00-2 x -- 17

Arsenic 7440-38-2 x -- 9.5

Benz(a)anthracene 56-55-3 x x -- 1.2

Benzidine 92-87-5 x x -- 500

Benzo(a)pyrene 50-32-8 x x -- 2.9

Benzo(b)fluoranthene 205-99-2 x x -- 1.2

Benzo(k)fluoranthene 207-08-9 x x -- 1.2

Benzyl chloride 100-44-7 x -- 0.17
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-59

CalEPA

Chemical name CASRN

Concentration 

data 

available

Physicochemical 

data 

available

Oral MADLa

(μg/day)

OSFb(per 

mg/kg-day)

beta-Hexachlorocyclohexane 319-85-7 x -- 1.5

Bis(2-chloroethyl) ether 111-44-4 x -- 2.5

Bromodichloromethane 75-27-4 x -- 0.13

Bromoform 75-25-2 x -- 0.011

Chloroform 67-66-3 x x -- 0.019

Chrysene 218-01-9 x x -- 0.12

Dibenz(a,h)anthracene 53-70-3 x x -- 4.1

Dichloromethane 75-09-2 x -- 0.014

Dieldrin 60-57-1 x -- 16

Ethylbenzene 100-41-4 x x -- 0.011

Heptachlor 76-44-8 x -- 4.1

Heptachlor epoxide 1024-57-3 x -- 5.5

Hydrazine 302-01-2 -- 3

Indeno(1,2,3-cd)pyrene 193-39-5 x x -- 1.2

Lindane 58-89-9 x -- 1.1

N-Nitrosodiphenylamine 86-30-6 x x -- 0.009

N-Nitroso-N-methylethylamine 10595-95-6 x x -- 22

p,p'-DDE 72-55-9 x -- 0.34

Safrole 94-59-7 x -- 0.22

Tetrachloroethene 127-18-4 x -- 0.051

CASRN = Chemical Abstract Service Registry Number; CalEPA = California Environmental Protection Agency.

a Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive toxicant at which the chemical 

would have no observable adverse reproductive effect, assuming exposure at 1,000 times that level. 

b Oral slope factor (OSF): An upper-bound, approximating a 95% confidence limit, on the increased cancer risk from a lifetime 

oral exposure to an agent. This estimate, usually expressed in units of proportion (of a population) affected per mg/kg day, is 

generally reserved for use in the low-dose region of the dose-response relationship, that is, for exposures corresponding to 

risks less than 1 in 100.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-60

Table G-2c. Chemicals reported to be detected in produced water, with available chronic oral 

RfVs and OSFs from international sources. 

Chemicals are ranked by CICAD reference value (TDI- tolerable daily intake). An “x” indicates the availability of 

measured concentration data in produced water (see Appendix E) and physicochemical properties data from EPI 

SuiteTM (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

Chemical name CASRN

Concentration 

data available

Physicochemical 

data available

IPCS CICAD Chronic 

TDIa(mg/kg-day)

Heptachlor 76-44-8 x 0.0001

Chromium (VI) 18540-29-9 x 0.0009

Mercury 7439-97-6 x 0.002

Beryllium 7440-41-7 x 0.002

Iodine 7553-56-2 x 0.01

Chloroform 67-66-3 x x 0.015

Barium 7440-39-3 x 0.02

Ethylene glycol 107-21-1 x 0.05

Tetrachloroethene 127-18-4 x 0.05

D-Limonene 5989-27-5 x 0.1

Strontium 7440-24-6 x 0.13

Benzyl butyl phthalate 85-68-7 x x 1.3

Diethyl phthalate 84-66-2 x 5

CASRN = Chemical Abstract Service Registry Number; IPCS = International Programme on Chemical Safety; CICAD = Concise 

International Chemical Assessment Documents.

a Tolerable Daily Intake (TDI): An estimate of the intake of a substance, expressed on a body mass basis, to which an individual 

in a (sub) population may be exposed daily over its lifetime without appreciable health risk.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-61

Table G-2d. Chemicals reported to be detected in produced water, with available less-than-chronic oral RfVs and OSFs. 

Chemicals are ranked by PPRTV subchronic reference dose (sRfD). The “--“ symbol indicates that no value was available from the sources consulted. 

Additionally, an “x” indicates the availability of measured concentration data in produced water (see Appendix E) and physicochemical properties data from EPI 

SuiteTM (see Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. 

PPRTV ATSDR HHBP

Chemical name CASRN

Concentration data 

available

Physicochemical data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Intermediate 

oral MRLb

(mg/kg-day)

Acute RfDa

(mg/kg-day)

Aldrin 309-00-2 x 0.00004 0.002 -- --

Antimony 7440-36-0 x 0.0004 -- -- --

Vanadium 7440-62-2 x 0.0007 -- 0.01 --

Benzyl chloride 100-44-7 x 0.002 -- -- --

Lithium 7439-93-2 x 0.002 -- -- --

Cobalt 7440-48-4 x 0.003 -- 0.01 --

Nonane 111-84-2 x 0.003 -- -- --

2-Methylnaphthalene 91-57-6 x x 0.004 -- -- --

Methyl bromide 74-83-9 x 0.005 -- 0.003 0.02

1,2,3-Trichlorobenzene 87-61-6 x 0.008 -- -- --

Bromodichloromethane 75-27-4 x 0.008 0.04 -- --

Benzene 71-43-2 x x 0.01 -- -- --

2,4-Dichlorophenol 120-83-2 x x 0.02 -- 0.003 --

p-Cresol 106-44-5 x x 0.02 -- -- --

Bromoform 75-25-2 x 0.03 0.7 0.2 --

Tributyl phosphate 126-73-8 x x 0.03 1.1 0.08 --

2,4-Dimethylphenol 105-67-9 x x 0.05 -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-62

PPRTV ATSDR HHBP

Chemical name CASRN

Concentration data 

available

Physicochemical data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Intermediate 

oral MRLb

(mg/kg-day)

Acute RfDa

(mg/kg-day)

Ethylbenzene 100-41-4 x x 0.05 -- 0.4 --

Chlorobenzene 108-90-7 x 0.07 -- 0.4 --

Chlorodibromomethane 124-48-1 x 0.07 0.1 -- --

1,2,4-Trichlorobenzene 120-82-1 x 0.09 -- 0.1 --

Butylbenzene 104-51-8 x 0.1 -- -- --

Fluoranthene 206-44-0 x x 0.1 -- 0.4 --

2-Chloroethanol 107-07-3 x 0.2 -- -- 0.045

o-Cresol 95-48-7 x x 0.2 -- -- --

2-(2-Butoxyethoxy)ethanol 112-34-5 x 0.3 -- -- --

Benzyl alcohol 100-51-6 x x 0.3 -- -- --

Hexane 110-54-3 x 0.3 -- -- --

N,N-Dimethylformamide 68-12-2 x 0.3 -- -- --

Pyrene 129-00-0 x x 0.3 -- -- --

Xylenes 1330-20-7 x x 0.4 1 0.4 --

Iron 7439-89-6 x 0.7 -- -- --

Toluene 108-88-3 x x 0.8 0.8 0.02 --

Formic acid 64-18-6 x 0.9 -- -- --

1,1-Dichloroethane 75-34-3 x 2 -- -- --

1,2-Propylene glycol 57-55-6 x 20 -- -- --

1,4-Dioxane 123-91-1 x x -- 5 0.5 --

2-Butoxyethanol 111-76-2 x -- 0.4 0.07 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-63

PPRTV ATSDR HHBP

Chemical name CASRN

Concentration data 

available

Physicochemical data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Intermediate 

oral MRLb

(mg/kg-day)

Acute RfDa

(mg/kg-day)

Acetone 67-64-1 x x -- -- 2 --

Acrolein 107-02-8 x -- -- 0.004 --

Acrylonitrile 107-13-1 x -- 0.1 0.01 --

Aluminum 7429-90-5 x -- -- 1 --

Arsenic 7440-38-2 x -- 0.005 -- --

Barium 7440-39-3 x -- -- 0.2 --

beta-Hexachlorocyclohexane 319-85-7 x -- 0.05 0.0006 --

Boron 7440-42-8 x -- 0.2 0.2 --

Cadmium 7440-43-9 x -- -- 0.0005 --

Carbon disulfide 75-15-0 x x -- 0.01 -- --

Chloroform 67-66-3 x x -- 0.3 0.1 --

Chromium (VI) 18540-29-9 x -- -- 0.005 --

Copper 7440-50-8 x -- 0.01 0.01 --

Di(2-ethylhexyl) phthalate 117-81-7 x x -- -- 0.1 --

Dibutyl phthalate 84-74-2 x x -- 0.5 -- --

Dichloromethane 75-09-2 x -- 0.2 -- --

Dieldrin 60-57-1 x -- -- 0.0001 --

Diethyl phthalate 84-66-2 x -- 7 6 --

Diethyltoluamide 134-62-3 x -- -- 1 --

Dioctyl phthalate 117-84-0 x x -- 3 0.4 --

Ethylene glycol 107-21-1 x -- 0.8 0.8 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-64

PPRTV ATSDR HHBP

Chemical name CASRN

Concentration data 

available

Physicochemical data 

available

sRfDa

(mg/kg-day)

Acute oral 

MRLb

(mg/kg-day)

Intermediate 

oral MRLb

(mg/kg-day)

Acute RfDa

(mg/kg-day)

Fluorene 86-73-7 x x -- -- 0.4 --

Heptachlor 76-44-8 x -- 0.0006 0.0001 --

Lindane 58-89-9 x -- 0.003 0.00001 --

m,p-Cresol mixture NOCAS_24858 -- -- 0.1 --

m-Xylene 108-38-3 x -- 1 0.4 --

Naphthalene 91-20-3 x x -- 0.6 0.6 --

o-Xylene 95-47-6 x -- 1 0.4 --

Phenol 108-95-2 x x -- 1 -- --

Phosphorus 7723-14-0 x -- -- 0.0002 --

p-Xylene 106-42-3 x -- 1 0.4 --

Strontium 7440-24-6 x -- -- 2 --

Tetrachloroethene 127-18-4 x -- 0.008 0.008 --

Tin 7440-31-5 x -- -- 0.3 --

Zinc 7440-66-6 x -- -- 0.3 --

CASRN = Chemical Abstract Service Registry Number; PPRTV = Provisional Peer Reviewed Toxicity Values; ATSDR = Agency for Toxic Substances and Disease Registry; HHBP = 

Human Health Benchmarks for Pesticides.

a Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of a daily oral exposure to the human population (including sensitive subgroups) 

that is likely to be without an appreciable risk of deleterious effects during a lifetime. It can be derived from a no observed-adverse-effect level (NOAEL), lowest observedadverse-effect level (LOAEL), or benchmark dose (BMD), with uncertainty factors generally applied to reflect limitations of the data used. The RfD is generally used in the EPA's 

noncancer health assessments. Subchronic RfD (sRFD): Duration of exposure is up to 10% of an average lifespan. Acute RfD: Duration of exposure is 24 hours or less.

b Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance at or below which the substance is unlikely to pose a measurable risk of 

harmful (adverse), noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a specified time period (acute, intermediate, or chronic). MRLs 

should not be used as predictors of harmful (adverse) health effects. Acute MRL: Duration of exposure is 1 to 14 days. Intermediate MRL: Duration of exposure is >14 to 364 

days.
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-65

Table G-2e. Available qualitative cancer classifications for chemicals reported to be detected 

in produced water. 

Chemicals classified as known carcinogens by one or more sources are listed first. The “--“ symbol indicates that no 

value was available from the sources consulted. Additionally, an “x” indicates the availability of measured 

concentration data in produced water (see Appendix E) and physicochemical properties data from EPI SuiteTM (see 

Appendix C). Italicized chemicals are found in both hydraulic fracturing fluids and produced water. Cancer 

classifications from IRIS and PPRTV are also listed in Table G-2a.

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Alpha particle 12587-46-1 x -- -- 1 --

Arsenic 7440-38-2 x

A (Human 

carcinogen) -- 1 Known

Benzene 71-43-2 x x

A (Human 

carcinogen) -- 1 Known

Benzidine 92-87-5 x x

A (Human 

carcinogen) -- 1 Known

Benzo(a)pyrene 50-32-8 x x

B2 (Probable 

human carcinogen) -- 1 RAHC

Beryllium 7440-41-7 x

B1 (Probable 

human carcinogen) -- 1 Known

Beta particle 12587-47-2 x -- -- 1 --

Cadmium 7440-43-9 x

B1 (Probable 

human carcinogen) -- 1 Known

Chromium (VI) 18540-29-9 x

Inhaled: A (Human 

carcinogen); Oral: 

D (Not classifiable 

as to human 

carcinogenicity)

-- 1 Known

Lindane 58-89-9 x -- -- 1 RAHC

Radium-226 13982-63-3 x -- -- 1 --

Radium-228 15262-20-1 x -- -- 1 --

Ethanol 64-17-5 x -- -- 1 --

Radium 7440-14-4 x -- -- 1 --

1,2,4-

Trichlorobenzene 120-82-1 x

D (Not classifiable 

as to human 

carcinogenicity)

"Likely to be 

carcinogenic to 

humans"

-- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-66

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

1,2-Diphenylhydrazine 122-66-7 x xB2 (Probable 

human carcinogen) -- -- RAHC

1,4-Dioxane 123-91-1 x x

"Likely to be 

carcinogenic to 

humans"

-- 2B RAHC

2-Mercaptobenzothiazole 149-30-4 x x -- -- 2A --

Acrylonitrile 107-13-1 x

B1 (Probable 

human carcinogen) -- 2B RAHC

Aldrin 309-00-2 x

B2 (Probable 

human carcinogen) -- 3 --

Benz(a)anthracene

56-55-3 x x

B2 (Probable 

human carcinogen) -- 2B RAHC

Benzo(b)fluoranthene 205-99-2 x x -- -- 2B RAHC

Benzo(k)fluoranthene 207-08-9 x x -- -- 2B RAHC

Benzophenone 119-61-9 x -- -- 2B --

Benzyl butyl 

phthalate 85-68-7 x x

C (Possible human 

carcinogen) -- 3 --

beta-Hexachlorocyclohexane 319-85-7 xC (Possible human 

carcinogen) -- -- --

Biphenyl 92-52-4 x x

"Suggestive 

evidence of 

carcinogenic 

potential"

-- -- --

Bis(2-chloroethyl) 

ether 111-44-4 x

B2 (Probable 

human carcinogen) -- 3 --

Bromodichloromethane 75-27-4 xB2 (Probable 

human carcinogen) -- 2B RAHC

Bromoform 75-25-2 x

B2 (Probable 

human carcinogen) -- 3 --

Chlorodibromomethane 124-48-1 xC (Possible human 

carcinogen) -- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-67

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Chloroform 67-66-3 x x

B2 (Probable 

human carcinogen) -- 2B RAHC

Chrysene 218-01-9 x x

B2 (Probable 

human carcinogen) -- 2B --

Cobalt 7440-48-4 x --

"Likely to be 

carcinogenic to 

humans"

2B --

Cumene 98-82-8 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- 2B RAHC

Di(2-ethylhexyl) 

phthalate 117-81-7 x x

B2 (Probable 

human carcinogen) -- 2B RAHC

Dibenz(a,h)anthracene

53-70-3 x x -- -- 2A RAHC

Dichloromethane 75-09-2 x

“Likely to be 

carcinogenic in 

humans”

-- 2A RAHC

Dieldrin 60-57-1 x

B2 (Probable 

human carcinogen) -- 3 --

Ethylbenzene 100-41-4 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- 2B --

Heptachlor 76-44-8 x

B2 (Probable 

human carcinogen) -- 2B --

Heptachlor 

epoxide 1024-57-3 x

B2 (Probable 

human carcinogen) -- -- --

Indeno(1,2,3-

cd)pyrene 193-39-5 x x -- -- 2B RAHC

Lead 7439-92-1 x

B2 (Probable 

human carcinogen) -- 2B RAHC

m-Cresol 108-39-4 x x

C (Possible human 

carcinogen) -- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-68

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Naphthalene 91-20-3 x x

“Data are 

inadequate to 

assess human 

carcinogenic 

potential”

-- 2B RAHC

Nickel 7440-02-0 x -- -- 2B RAHC

Nitrate 14797-55-8 x -- -- 2A --

Nitrite 14797-65-0 x -- -- 2A --

N-Nitrosodiphenylamine 86-30-6 x xB2 (Probable 

human carcinogen) -- 3 --

N-Nitroso-Nmethylethylamine 10595-95-6 x xB2 (Probable 

human carcinogen) -- 2B --

o-Cresol 95-48-7 x x

C (Possible human 

carcinogen)

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

p-Cresol 106-44-5 x x

C (Possible human 

carcinogen) -- -- --

p,p'-DDE 72-55-9 x

B2 (Probable 

human carcinogen) -- -- --

Safrole 94-59-7 x -- -- 2B RAHC

Tetrachloroethene

127-18-4 x

“Likely to be 

carcinogenic in 

humans”

-- 2A RAHC

1,1-

Dichloroethane 75-34-3 x

C (Possible human 

carcinogen) -- -- --

Benzyl chloride 100-44-7 x

B2 (Probable 

human carcinogen) -- -- --

Hydrazine 302-01-2

B2 (Probable 

human carcinogen) -- 2A RAHC
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-69

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

N,N-Dimethylformamide 68-12-2 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

2A --

Quinoline 91-22-5 x

”Likely to be 

carcinogenic in 

humans”

-- -- --

Tributyl 

phosphate 126-73-8 x x --

"Likely to be 

carcinogenic to 

humans"

-- --

Dibromoacetonitrile 3252-43-5 x -- -- 2B --

Acetaldehyde 75-07-0 x

B2 (Probable 

human carcinogen) -- 2B RAHC

1,2,3-Trichlorobenzene 87-61-6 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

1,3,5-

Trimethylbenzene 108-67-8 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic

potential"

-- --

2,4-

Dichlorophenol 120-83-2 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

2,4-

Dimethylphenol 105-67-9 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-70

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

2,5-Cyclohexadiene-1,4-dione 106-51-4 x x -- -- 3 --

2-Methylnaphthalene 91-57-6 x x

“Data are 

inadequate to 

assess human 

carcinogenic 

potential”

-- -- --

Acetone 67-64-1 x x

“Data are 

inadequate for an 

assessment of 

human 

carcinogenic 

potential”

-- -- --

Acetophenone 98-86-2 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Acrolein 107-02-8 x

“Data are 

inadequate for an 

assessment of 

human 

carcinogenic 

potential”

-- 3 --

Aluminum 7429-90-5 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Antimony 7440-36-0 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Benzo(g,h,i)perylene

191-24-2 x x -- -- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-71

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Benzyl alcohol 100-51-6 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Boron 7440-42-8 x

“Data are 

inadequate to 

assess the 

carcinogenic 

potential”

-- -- --

Butylbenzene 104-51-8 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Caffeine 58-08-2 x x -- -- 3 --

Chloromethane 74-87-3 x

"Carcinogenic 

potential cannot be 

determined"

-- 3 --

Cholesterol 57-88-5 x x -- -- 3 --

Chromium 7440-47-3 -- -- 3 --

Chromium (III) 16065-83-1 x

“Data are 

inadequate for an 

assessment of 

human 

carcinogenic 

potential”

-- 3 --

Cyanide 57-12-5 x

“Inadequate 

information to 

assess the 

carcinogenic 

potential”

-- -- --

deltaHexachlorocyclohexane

319-86-8 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-72

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Dibenzothiophene 132-65-0 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

3 --

Dibutyl phthalate 84-74-2 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Diethyl phthalate 84-66-2 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Dimethyl 

phthalate 131-11-3 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Diphenylamine 122-39-4 x x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Fluoranthene 206-44-0 x x

D (Not classifiable 

as to human 

carcinogenicity)

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

3 --

Fluorene 86-73-7 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- 3 --

Fluoride 16984-48-8 x -- -- 3 --

Formic acid 64-18-6 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-73

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Iron 7439-89-6 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Isopropanol 67-63-0 x -- -- 3 --

Lithium 7439-93-2 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Manganese 7439-96-5 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Mercury 7439-97-6 x

D (Not classifiable 

as to human 

carcinogenicity)

-- 3 --

Methyl bromide 74-83-9 x

D (Not classifiable 

as to human 

carcinogenicity)

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

3 --

Methyl ethyl 

ketone 78-93-3 x

“Data are 

inadequate to 

assess carcinogenic 

potential”

-- -- --

Perylene 198-55-0 x -- -- 3 --

Phenanthrene 85-01-8 x x -- -- 3 --

Phenol 108-95-2 x x

“Data are 

inadequate for an 

assessment of 

human 

carcinogenic 

potential”

-- 3 --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-74

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Phosphorus 7723-14-0 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Pyrene 129-00-0 x x

D (Not classifiable 

as to human 

carcinogenicity)

-- 3 --

Pyridine 110-86-1 x x -- -- 3 --

Selenium 7782-49-2 x

D (Not classifiable 

as to human 

carcinogenicity)

-- 3 --

Silica 7631-86-9 -- -- 3 --

Silver 7440-22-4 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Toluene 108-88-3 x x

“Inadequate 

information to 

assess the 

carcinogenic 

potential”

-- 3 --

Vanadium 7440-62-2 x

“Data are 

inadequate to 

assess the 

carcinogenic 

potential”

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Xylenes 1330-20-7 x x

“Data are 

inadequate to 

assess the 

carcinogenic 

potential”

-- 3 --

Zinc 7440-66-6 x

“Inadequate 

information to 

assess carcinogenic 

potential”

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-75

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

2-Chloroethanol 107-07-3 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Nonane 111-84-2 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

2-Butoxyethanol 111-76-2 x

“Not likely to be 

carcinogenic to 

humans”

-- 3 --

D-Limonene 5989-27-5 x -- -- 3 --

Chlorobenzene 108-90-7 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

1-Butanol 71-36-3 x

D (Not classifiable 

as to human 

carcinogenicity)

-- -- --

Hydrochloric acid 7647-01-0 -- -- 3 --

2-(2-Butoxyethoxy)ethanol 112-34-5 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

Hexane 110-54-3 x

"Inadequate 

information to 

assess the 

carcinogenic 

potential"

-- -- --
Appendix G – Identification and Hazard Evaluation of Chemicals across 

the Hydraulic Fracturing Water Cycle Supplemental Information 

G-76

Qualitative cancer classification

Chemical 

name CASRN

Concentration 

data 

available

Physicochemical 

data 

available IRISa PPRTVbIARCc RoCd

Pentane 109-66-0 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

1,2,3-Trimethylbenzene 526-73-8 x --

"Data are 

inadequate for 

an assessment 

of human 

carcinogenic 

potential"

-- --

1,2-Propylene 

glycol 57-55-6 x --

"Not likely to be 

carcinogenic to 

humans"

-- --

Barium 7440-39-3 x

”Not likely to be 

carcinogenic to 

humans”

-- -- --

Caprolactam 105-60-2 x x -- -- 4 --

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

IRIS assessments use the 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. 

b PPRTV assessments use the 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.

c 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.

d The listing criteria in the 13th RoC Document are: Known = Known to be a human carcinogen; RAHC = Reasonably anticipated 

to be a human carcinogen.
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-1 

Appendix H. Chemicals Identified in Hydraulic 

Fracturing Fluids and/or Produced Water 
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-2 

This page is intentionally left blank. 
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-3

Appendix H. Chemicals Identified in Hydraulic Fracturing 

Fluids and/or Produced Water 

H.1. Supplemental Tables and Information

The EPA identified authoritative sources for information on hydraulic fracturing-related chemicals 

and, to the extent possible, verified the chemicals used in hydraulic fracturing fluids and detected in 

produced water of hydraulically fractured wells. The EPA used 28 sources of information to identify 

the chemicals used in hydraulic fracturing fluids or detected in produced water of hydraulically 

fracturing wells. The sources include compilations of industry-provided data (all Toxic Substance 

Control Act (TSCA) confidential business information (CBI) chemical lists handled by the EPA were 

managed in accordance with TSCA CBI procedures); publications that represent collaborations 

between state, non-profit, academic, and/or industry groups; and peer-reviewed journal articles. 

Most of the listed chemicals were cited by multiple sources. 

Seven of the 28 sources obtained information about the chemicals used in hydraulic fracturing 

fluids from Material Safety Data Sheets (MSDSs) provided by chemical manufacturers for the 

products they sell, as required by the Occupational Safety and Health Administration (OSHA). The 

MSDSs must list all hazardous ingredients if they comprise at least 1% of the product; for 

carcinogens, the reporting threshold is 0.1%. However, chemical manufacturers may withhold 

information (e.g., chemical name, concentration of the substance in a mixture) about a hazardous 

substance from MSDSs if it is claimed as confidential business information (CBI), provided that 

certain conditions are met (OSHA, 2013). 

Table H-1. Sources used to create lists of chemicals used in fracturing fluids or detected in 

produced water. 

The number next to each citation in the reference column corresponds to numbers in the reference columns found 

in Table H-2, Table H-3, Table H-4, and Table H-5.

Reference Citation

House of Representatives (U.S. House of Representatives). (2011). Chemicals used in 

hydraulic fracturing. Washington, D.C.: U.S. House of Representatives, Committee on 

Energy and Commerce, Minority Staff. 

http://www.conservation.ca.gov/dog/general_information/Documents/Hydraulic%

ic-Fracturing-Chemicals-2011-4-18.pdf.

House of Representatives 

(2011) a(1)

Colborn, T; Kwiatkowski, C; Schultz, K; Bachran, M. (2011). Natural gas operations 

from a public health perspective. Hum Ecol Risk Assess 17: 1039-1056. 

http://dx.doi.org/10.1080/10807039.2011.605662.

Colborn et al. (2011) a(2)

NYSDEC (New York State Department of Environmental Conservation). (2011). 

Revised draft supplemental generic environmental impact statement (SGEIS) on the 

oil, gas and solution mining regulatory program: Well permit issuance for horizontal 

drilling and high-volume hydraulic fracturing to develop the Marcellus shale and 

other low-permeability gas reservoirs. Albany, NY: NY SDEC. 

http://www.dec.ny.gov/energy/75370.html. 

NYSDEC (2011) a,b (3)
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-4

Reference Citation

U.S. EPA (U.S. Environmental Protection Agency). (2013). Data received from oil and 

gas exploration and production companies, including hydraulic fracturing service 

companies 2011 to 2013. Non-confidential business information source documents 

are located in Federal Docket ID: EPA-HQ-ORD2010-0674. Available at 

http://www.regulations.gov.

U.S. EPA (2013a) a(4)

Material Safety Data Sheets. (a) Encana/Halliburton Energy Services, Inc.: Duncan, 

Oklahoma. Provided by Halliburton Energy Services during an onsite visit by the EPA 

on May 10, 2010; (b) Encana Oil and Gas (USA), Inc.: Denver, Colorado. Provided to 

US EPA Region 8.

Material Safety Data 

Sheets a(5)

U.S. EPA (U.S. Environmental Protection Agency). (2004). Evaluation of impacts to 

underground sources of drinking water by hydraulic fracturing of coalbed methane 

reservoirs. (EPA/816/R-04/003). Washington, DC.: U.S. Environmental Protection 

Agency, Office of Solid Waste.

U.S. EPA (2004) a(6)

PA DEP (Pennsylvania Department of Environmental Protection). (2010). Chemicals 

used by hydraulic fracturing companies in Pennsylvania for surface and hydraulic 

fracturing activities. Harrisburg, PA: Pennsylvania Department of Environmental 

Protection (PADEP). 

http://files.dep.state.pa.us/OilGas/BOGM/BOGMPortalFiles/MarcellusShale/Frac%20

list%206-30-2010.pdf. 

PA DEP (2010) a(7)

U.S. EPA (U.S. Environmental Protection Agency). (2015). Analysis of hydraulic 

fracturing fluid data from the FracFocus chemical disclosure registry 1.0: Project 

database [EPA Report]. (EPA/601/R-14/003). Washington, D.C.: U.S. Environmental 

Protection Agency, Office of Research and Development. 

http://www2.epa.gov/hfstudy/epa-project-database-developed-fracfocus-1-

disclosures. 

U.S. EPA (2015c) a(8)

Hayes, T. (2009). Sampling and analysis of water streams associated with the 

development of Marcellus shale gas. Des Plaines, IL: Marcellus Shale Coalition http://

energyindepth.org/wp-content/uploads/marcellus/2012/11/MSCommissionReport.pdf.

Hayes (2009) b(9)

U.S. EPA (U.S. Environmental Protection Agency). (2011). Sampling data for flowback 

and produced water provided to EPA by nine oil and gas well operators (nonconfidential business information). US Environmental Protection Agency. 

http://www.regulations.gov/#!docketDetail;rpp=100;so=DESC;sb=docId;po=0;D=EPAHQ-ORD-2010-0674. 

U.S. EPA (2011b) b(10)

Akob, DM; Cozzarelli, IM; Dunlap, DS; Rowan, EL; Lorah, MM. (2015). Organic and 

inorganic composition and microbiology of produced waters from Pennsylvania shale 

gas wells. Appl Geochem 60: 116-125. 

http://dx.doi.org/10.1016/j.apgeochem.2015.04.011. 

Akob et al. (2015) b(11)

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. 

http://dx.doi.org/10.1021/es501173p. 

Cluff et al. (2014) b(12)
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-5 

Reference Citation

Digiulio, DC; Jackson, RB. (2016). Impact to underground sources of drinking water 

and domestic wells from production well stimulation and completion practices in the 

Pavillion, Wyoming, Field. Environ Sci Technol 50: 4524-4536. 

http://dx.doi.org/10.1021/acs.est.5b04970. 

Digiulio and Jackson 

(2016) b(13)

Geological Survey of Alabama. (2014). Water management strategies for improved 

coalbed methane production in the Black Warrior Basin. (DE-FE0000888). 

Washington, DC: U.S. Department of Energy, National Energy Technology Library. 

https://www.netl.doe.gov/research/oil-and-gas/natural-gas-resources/00888-

geosurveyalabama. 

Geological Survey of 

Alabama (2014) b(14)

Hayes, T; Severin, B. (2012). Characterization of flowback water from the the 

Marcellus and the Barnett shale regions. Barnett and Appalachian shale water 

management and reuse technologies. (08122-05.09; Contract 08122-05). Hayes, T; 

Severin, B. http://www.rpsea.org/media/files/project/2146b3a0/08122-05-RTCharacterization_Flowback_Waters_Marcellus_Barnett_Shale_Regions-03-20-12.pdf. 

Hayes and Severin 

(2012a) b(15)

Khan, NA; Engle, M; Dungan, B; Holguin, FO; Xu, P; Carroll, KC. (2016). Volatile-organic 

molecular characterization of shale-oil produced water from the Permian Basin. 

Chemosphere 148: 126-136. http://dx.doi.org/10.1016/j.chemosphere.2015.12.116.

Khan et al. (2016) b(16)

Lester, Y; Ferrer, I; Thurman, EM; Sitterley, KA; Korak, JA; Aiken, G; Linden, KG. (2015). 

Characterization of hydraulic fracturing flowback water in Colorado: Implications for 

water treatment. Sci Total Environ 512-513: 637-644. 

http://dx.doi.org/10.1016/j.scitotenv.2015.01.043. 

Lester et al. (2015) b(17)

Maguire-Boyle, SJ; Barron, AR. (2014). Organic compounds in produced waters from 

shale gas wells. Environ Sci Process Impacts 16: 2237-2248. 

http://dx.doi.org/10.1039/c4em00376d. 

Maguire-Boyle and 

Barron (2014) b(18)

Olsson, O; Weichgrebe, D; Rosenwinkel, KH. (2013). Hydraulic fracturing wastewater 

in Germany: Composition, treatment, concerns. Environ Earth Sci 70: 3895-3906. 

http://dx.doi.org/10.1007/s12665-013-2535-4. 

Olsson et al. (2013) b(19)

Orem, WH; Tatu, CA; Lerch, HE; Rice, CA; Bartos, TT; Bates, AL; Tewalt, S; Corum, MD. 

(2007). Organic compounds in produced waters from coalbed natural gas wells in the 

Powder River Basin, Wyoming, USA. Appl Geochem 22: 2240-2256. 

http://dx.doi.org/10.1016/j.apgeochem.2007.04.010. 

Orem et al. (2007) b(20)

Orem, W; Tatu, C; Varonka, M; Lerch, H; Bates, A; Engle, M; Crosby, L; McIntosh, J. 

(2014). Organic substances in produced and formation water from unconventional 

natural gas extraction in coal and shale. Int J Coal Geol 126: 20-31. 

http://dx.doi.org/10.1016/j.coal.2014.01.003. 

Orem et al. (2014) b(21)

Thacker, JB; Carlton, DD, Jr; Hildenbrand, ZL; Kadjo, AF; Schug, KA. (2015). Chemical 

analysis of wastewater from unconventional drilling operations. Water 7: 1568-1579. 

http://dx.doi.org/10.3390/w7041568.

Thacker et al. (2015) b (22)

Thurman, EM; Ferrer, I; Blotevogel, J; Borch, T. (2014). Analysis of hydraulic fracturing 

flowback and produced waters using accurate mass: Identification of ethoxylated 

surfactants. Anal Chem 86: 9653-9661. http://dx.doi.org/10.1021/ac502163k. 

Thurman et al. (2014) b

(23)
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-6

Reference Citation

Rowan, EL; Engle, MA; Kirby, CS; Kraemer, TF. (2011). Radium content of oil- and gasfield produced waters in the northern Appalachian Basin (USA): Summary and 

discussion of data. (Scientific Investigations Report 20115135). Reston, VA: U.S. 

Geological Survey. http://pubs.usgs.gov/sir/2011/5135/. 

Rowan et al. (2011) b(24)

PA DEP (Pennsylvania Department of Environmental Protection). (2015). 

Technologically enhanced naturally occurring radioactive materials (TENORM) study 

report. Harrisburg, PA.

PA DEP (2015) b(25)

Ziemkiewicz, PF; He, YT. (2015). Evolution of water chemistry during Marcellus Shale

gas development: A case study in West Virginia. Chemosphere 134: 224-231. 

http://dx.doi.org/10.1016/j.chemosphere.2015.04.040. 

Ziemkiewicz and He 

(2015) b (26) 

Dresel, PE; Rose, AW. (2010). Chemistry and origin of oil and gas well brines in 

western Pennsylvania (pp. 48). (Open-File Report OFOG 1001.0). Harrisburg, PA: 

Pennsylvania Geological Survey, 4th ser. 

http://www.marcellus.psu.edu/resources/PDFs/brines.pdf. 

Dresel and Rose (2010) b

(27)

Barbot, E; Vidic, NS; Gregory, KB; Vidic, RD. (2013). Spatial and temporal correlation 

of water quality parameters of produced waters from Devonian-age shale following 

hydraulic fracturing. Environ Sci Technol 47: 2562-2569.

Barbot et al. (2013) b(28)

a Sources used to identify chemicals used in hydraulic fracturing fluids.

b Sources used to identify chemicals detected in produced water.

Once it had identified chemicals used in hydraulic fracturing fluids and chemicals detected in 

produced water, the EPA conducted an initial review of the chemicals for preliminary validation of 

provided chemical name and Chemical Abstracts Service Registry Number (CASRN) combinations. 

A CASRN is a numeric identifier assigned by the Chemical Abstracts Service (CAS) to a chemical 

substance when it enters the CAS Registry Database. 

The EPA Office of Research and Development’s National Center for Computational Toxicology 

(NCCT) processed and provided the final list of curated CASRN-chemical name matches with 

validated chemical structures from NCCT’s Distributed Structure-Searchable Toxicity Database 

(DSSTox) (U.S. EPA, 2013b). As of late 2016, the DSSTox database exceeds 700,000 chemical 

substances. The highest quality, manually curated subset (~25,000 chemical substances) focuses on 

chemicals of relevance to environmental exposures, toxicity, and bioactivity. Additional content 

(~130,000 chemical substances) imported from the EPA’s Substance Registry System (SRS) 

chemicals and the National Library of Medicine (NLM)’s ChemID library comprises a portion the 

DSSTox database with intermediate quality (NLM, 2014; U.S. EPA, 2014e). The remainder of the 

chemical substances are imported from lower quality, uncurated public resources such as PubChem 

(https://pubchem.ncbi.nlm.nih.gov/). The entire DSSTox database is searchable through the EPA 

public CompTox Dashboard (https://comptox.epa.gov/dashboard).

The DSSTox database is distinguished from other publicly available chemical databases by the 

manual curation workflow applied to high-priority EPA chemical lists, as well as by the 

enforcement of unique (1:1:1) mappings of CASRN to a single “preferred name” and unique 
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-7 

chemical structure. Initial automated-processing of a CASRN and/or chemical name list yields 

various types of corrections, notes, and mappings to registered DSSTox chemical substance records. 

The simplest include: (1) CASRN- exact chemical name match; (2) CASRN-synonym chemical name 

match; (3) CASRN-match through mapping of a “deleted” CASRN that is no longer in use to an 

“active” CASRN; (4) Auto-repair of common errors in CASRN formatting resulting in a CASRN- exact 

or synonym chemical name match. These four situations are considered valid “matches” and the 

records are mapped to a DSSTox ID directly. 

Other situations (such as when a CASRN-chemical name appears mismatched in an original source 

of information or when only a chemical name without a CASRN is provided in the original source) 

require various levels of curation review prior to final mapping of a CASRN to a single chemical 

name and unique structure. The general methodology for resolving conflicts between CASRNchemical name combinations and other chemical identification issues differed slightly depending 

on the data provided by each source. To resolve CASRN-chemical name issues in data provided by 

the nine service companies, the EPA worked with each company to verify the CASRN-chemical 

name matches proposed by NCCT. In cases of CASRN-chemical name mismatches in data provided 

by FracFocus, chemical names were considered primary to the CASRN (i.e., the name overrode the 

CASRN). When the chemical name was non-specific and the CASRN was valid, then the CASRN was 

considered primary to the chemical name, and the correct specific chemical name from DSSTox was 

assigned to the CASRN. For all other sources of information, the CASRN was considered primary 

unless it was invalid or missing. In such cases, the chemical name was primary. 

When no CASRN-chemical name match is possible, the chemical may undergo manual curation 

review and require registration of new DSSTox substance-structure records. Each registered 

DSSTox substance record, in turn, is assigned a Curation Quality Score that indicates the level of 

curation (automated vs. manual) and reliability of the CASRN-chemical name-structure association. 

The manual DSSTox curation process is carried out in accordance with the published DSSTox 

Chemical Information Quality Review Procedures (ftp://ftp.epa.gov/dsstoxftp/DSSTox_Archive_

20150930/DSSTox_ChemInfQAProcedures_20150930.pdf). 

Individual chemicals or chemical mixtures with valid CASRN-chemical name matches that are used 

in hydraulic fracturing fluids are presented in Table H-2. Generic chemicals used in hydraulic 

fracturing fluids (i.e., encompassing a general class of chemicals) or chemicals without a valid 

CASRN-chemical name match are presented in Table H-3. Chemicals with valid CASRN-chemical 

name matches that have been detected in produced water are presented in Table H-4. Generic 

chemicals or chemicals without a valid CASRN-chemical name match that have been detected in 

produced water are presented in Table H-5. Chemicals with valid CASRN-chemical name matches 

found in both fracturing fluids and produced water are also indicated in Table H-2 and Table H-4. 

In total, 1,606 chemicals with valid CASRN-chemical name matches were reported to be used in 

hydraulic fracturing fluids and/or detected in produced water from hydraulically fractured wells. 

This total number comprises 1,084 chemicals reported to be used in hydraulic fracturing fluids 

from 2005–2013 and 599 chemicals detected in produced water according to the sources of 

information that we summarized. The number of chemicals reported to be used in hydraulic 

fracturing fluids from 2005–2013 that were also detected in produced water was 77.
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-8 

Table H-2. Chemicals reported to be used in hydraulic fracturing fluids. 

Chemicals were reported to be used in hydraulic fracturing fluids from 2005-2013, according to the references cited. An “X” indicates the availability of 

physicochemical properties from EPI SuiteTM (Appendix C) and selected toxicity data (Appendix G). An empty cell indicates no information was available from 

the sources we consulted. Reference number corresponds to the citation in Table H-1.

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

(13Z)-N,N-bis(2-hydroxyethyl)-N-methyldocos-13-en-1-aminium 

chloride 120086-58-0 X 1

(2,3-dihydroxypropyl)trimethylammonium chloride 34004-36-9 X 8

(E)-Crotonaldehyde 123-73-9 X X 1, 4

[Nitrilotris(methylene)]tris-phosphonic acid pentasodium salt 2235-43-0 X 1

1-(1-Naphthylmethyl)quinolinium chloride 65322-65-8 X 1

1-(Alkyl* amino)-3-aminopropane *(42%C12, 26%C18, 15%C14, 8%C16, 

5%C10, 4%C8) 68155-37-3 X 8

1-(Phenylmethyl)pyridinium Et Me derivs., chlorides 68909-18-2 X 1, 2, 3, 4, 6, 8

1,2,3-Trimethylbenzene 526-73-8 X X X 1, 4

1,2,4-Trimethylbenzene 95-63-6 X X X 1, 2, 3, 4, 5

1,2-Benzisothiazolin-3-one 2634-33-5 X 1, 3, 4

1,2-Dibromo-2,4-dicyanobutane 35691-65-7 X 1, 4

1,2-Ethanediamine, polymer with 2-methyloxirane 25214-63-5 8

1,2-Ethanediaminium, N,N'-bis[2-[bis(2-

hydroxyethyl)methylammonio]ethyl]-N,N'-bis(2-hydroxyethyl)-N,N'-

dimethyl-, tetrachloride

138879-94-4 X 1, 4

1,2-Propylene glycol 57-55-6 X X X 1, 2, 3, 4, 8

1,2-Propylene oxide 75-56-9 X X 1, 4

1,3,5-Triazine 290-87-9 X 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-9 

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

1,3,5-Triazine-1,3,5(2H,4H,6H)-triethanol 4719-04-4 X 1, 4

1,3,5-Trimethylbenzene 108-67-8 X X X 1, 4

1,3-Butadiene 106-99-0 X X 8

1,3-Dichloropropene 542-75-6 X X 8

1,4-Dioxane 123-91-1 X X X 2, 3, 4

1,4-Dioxane-2,5-dione, 3,6-dimethyl-, (3R,6R)-, polymer with (3S,6S)-

3,6-dimethyl-1,4-dioxane-2,5-dione and (3R,6S)-rel-3,6-dimethyl-1,4-

dioxane-2,5-dione

9051-89-2 1, 4, 8

1,6-Hexanediamine 124-09-4 X 1, 2

1,6-Hexanediamine dihydrochloride 6055-52-3 X 1

1-[2-(2-Methoxy-1-methylethoxy)-1-methylethoxy]-2-propanol 20324-33-8 X 4

1-Amino-2-propanol 78-96-6 X 8

1-Benzylquinolinium chloride 15619-48-4 X 1, 3, 4

1-Butanol 71-36-3 X X X 1, 2, 3, 4, 7

1-Butoxy-2-propanol 5131-66-8 X 8

1-Decanol 112-30-1 X 1, 4

1-Dodecyl-2-pyrrolidinone 2687-96-9 X 1, 4

1-Eicosene 3452-07-1 X 3

1-Ethyl-2-methylbenzene 611-14-3 X X 4

1-Hexadecene 629-73-2 X X 3

1-Hexanol 111-27-3 X 1, 4, 8

1-Hexanol, 2-ethyl-, manuf. of, by products from, distn. residues 68609-68-7 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-10

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

1H-Imidazole-1-ethanamine, 4,5-dihydro-, 2-nortall-oil alkyl derivs. 68442-97-7 2, 4

1-Methoxy-2-propanol 107-98-2 X 1, 2, 3, 4

1-Octadecanamine, acetate (1:1) 2190-04-7 X 8

1-Octadecanamine, N,N-dimethyl- 124-28-7 X 1, 3, 4

1-Octadecene 112-88-9 X X 3

1-Octanol 111-87-5 X 1, 4

1-Pentanol 71-41-0 X 8

1-Propanaminium, 3-amino-N-(carboxymethyl)-N,N-dimethyl-, N-coco 

acyl derivs., chlorides, sodium salts 61789-39-7 1

1-Propanaminium, 3-amino-N-(carboxymethyl)-N,N-dimethyl-, N-coco 

acyl derivs., inner salts 61789-40-0 1, 2, 3, 4

1-Propanaminium, 3-chloro-2-hydroxy-N,N,N-trimethyl-, chloride 3327-22-8 X 8

1-Propanaminium, N-(3-aminopropyl)-2-hydroxy-N,N-dimethyl-3-sulfo-, 

N-coco acyl derivs., inner salts 68139-30-0 1, 3, 4

1-Propanaminium, N-(carboxymethyl)-N,N-dimethyl-3-[(1-

oxooctyl)amino]-, inner salt 73772-46-0 8

1-Propanesulfonic acid 5284-66-2 X 3

1-Propanol 71-23-8 X X 1, 2, 4, 5

1-Propanol, zirconium(4+) salt 23519-77-9 1, 4, 8

1-Propene 115-07-1 X X 2

1-tert-Butoxy-2-propanol 57018-52-7 X X 8

1-Tetradecene 1120-36-1 X 3

1-Tridecanol 112-70-9 X 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-11

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

1-Undecanol 112-42-5 X 2

2-(2-Butoxyethoxy)ethanol 112-34-5 X X X 2, 4

2-(2-Ethoxyethoxy)ethanol 111-90-0 X X 1, 4

2-(2-Ethoxyethoxy)ethyl acetate 112-15-2 X 1, 4

2-(Dibutylamino)ethanol 102-81-8 X 1, 4

2-(Hydroxymethylamino)ethanol 34375-28-5 X 1, 4

2-(Thiocyanomethylthio)benzothiazole 21564-17-0 X X 2

2,2'-(diazene-1,2-diyldiethane-1,1-diyl)bis-4,5-dihydro-1H-imidazole 

dihydrochloride 27776-21-2 X 3

2,2'-(Octadecylimino)diethanol 10213-78-2 X 1

2,2'-[Ethane-1,2-diylbis(oxy)]diethanamine 929-59-9 X 1, 4

2,2'-Azobis(2-amidinopropane) dihydrochloride 2997-92-4 X 1, 4

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 X X 1, 2, 3, 4, 6, 7, 8

2,2-Dibromopropanediamide 73003-80-2 X 3

2,4-Hexadienoic acid, potassium salt, (2E,4E)- 24634-61-5 X 3

2,6,8-Trimethyl-4-nonanol 123-17-1 X 8

2-Acrylamide - 2-propanesulfonic acid and N,N-dimethylacrylamide 

copolymer NOCAS_51252 2

2-Acrylamido -2-methylpropanesulfonic acid copolymer NOCAS_51255 8

2-Acrylamido-2-methyl-1-propanesulfonic acid 15214-89-8 X 1, 3

2-Amino-2-methylpropan-1-ol 124-68-5 X 8

2-Aminoethanol ester with boric acid (H3BO3) (1:1) 10377-81-8 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-12

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

2-Aminoethanol hydrochloride 2002-24-6 X 4, 8

2-Bromo-3-nitrilopropionamide 1113-55-9 X 1, 2, 3, 4, 5

2-Butanone oxime 96-29-7 X 1

2-Butenediamide, (2E)-, N,N'-bis[2-(4,5-dihydro-2-nortall-oil alkyl-1Himidazol-1-yl)ethyl] derivs. 68442-77-3 3, 8

2-Butoxy-1-propanol 15821-83-7 X 8

2-Butoxyethanol 111-76-2 X X X 1, 2, 3, 4, 6, 7, 8

2-Dodecylbenzenesulfonic acid- n-(2-aminoethyl)ethane-1,2-

diamine(1:1) 40139-72-8 X 8

2-Ethoxyethanol 110-80-5 X X 6

2-Ethoxynaphthalene 93-18-5 X 3

2-Ethyl-1-hexanol 104-76-7 X X 1, 2, 3, 4, 5

2-Ethyl-2-hexenal 645-62-5 X 2

2-Ethylhexyl benzoate 5444-75-7 X 4

2-Hydroxyethyl acrylate 818-61-1 X 1, 4

2-Hydroxyethylammonium hydrogen sulphite 13427-63-9 X 1

2-Hydroxy-N,N-bis(2-hydroxyethyl)-N-methylethanaminium chloride 7006-59-9 X 8

2-Mercaptoethanol 60-24-2 X 1, 4

2-Methoxyethanol 109-86-4 X X 4

2-Methyl-1-propanol 78-83-1 X X 1, 2, 4

2-Methyl-2,4-pentanediol 107-41-5 X 1, 2, 4

2-Methyl-3(2H)-isothiazolone 2682-20-4 X 1, 2, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-13

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

2-Methyl-3-butyn-2-ol 115-19-5 X 3

2-Methylbutane 78-78-4 X 2

2-Methylquinoline hydrochloride 62763-89-7 X 3

2-Phosphono-1,2,4-butanetricarboxylic acid 37971-36-1 X 1, 4

2-Phosphonobutane-1,2,4-tricarboxylic acid, potassium salt (1:x) 93858-78-7 X 1

2-Propanol, aluminum salt 555-31-7 1

2-Propen-1-aminium, N,N-dimethyl-N-2-propenyl-, chloride, 

homopolymer 26062-79-3 3

2-Propenamide, homopolymer 25038-45-3 8

2-Propenoic acid, 2-(2-hydroxyethoxy)ethyl ester 13533-05-6 X 4

2-Propenoic acid, 2-ethylhexyl ester, polymer with 2-hydroxyethyl 2-

propenoate 

36089-45-9 8

2-Propenoic acid, 2-methyl-, polymer with 2-propenoic acid, sodium salt 28205-96-1 8

2-Propenoic acid, 2-methyl-, polymer with sodium 2-methyl-2-[(1-oxo2-propen-1-yl)amino]-1-propanesulfonate (1:1) 136793-29-8 8

2-Propenoic acid, ethyl ester, polymer with ethenyl acetate and 2,5-

furandione, hydrolyzed 113221-69-5 4, 8

2-Propenoic acid, ethyl ester, polymer with ethenyl acetate and 2,5-

furandione, hydrolyzed, sodium salt 111560-38-4 8

2-Propenoic acid, polymer with 2-propenamide, sodium salt 25987-30-8 3, 4, 8

2-Propenoic acid, polymer with ethene, zinc salt 28208-80-2 8

2-Propenoic acid, polymer with ethenylbenzene 25085-34-1 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-14

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

2-Propenoic acid, polymer with sodium ethanesulfonate, 

peroxydisulfuric acid, disodium salt- initiated, reaction products with 

tetrasodium ethenylidenebis (phosphonata)

397256-50-7 8

2-Propenoic acid, polymer with sodium phosphinate (1:1), sodium salt 129898-01-7 8

2-Propenoic acid, sodium salt (1:1), polymer with sodium 2-methyl-2-

((1-oxo-2-propen-1-yl)amino)-1-propanesulfonate (1:1) 37350-42-8 1

2-Propenoic acid, telomer with sodium 4-ethenylbenzenesulfonate 

(1:1), sodium 2-methyl-2-[(1-oxo-2-propen-1-yl)amino]-1-

propanesulfonate (1:1) and sodium sulfite (1:1), sodium salt

151006-66-5 4

2-Propenoic, polymer with sodium phosphinate 71050-62-9 3, 4

3-(Dimethylamino)propylamine 109-55-7 X 8

3,4,4-Trimethyloxazolidine 75673-43-7 X 8

3,5,7-Triazatricyclo(3.3.1.1(superscript 3,7))decane, 1-(3-chloro-2-

propenyl)-, chloride, (Z)-

51229-78-8 X 3

3,7-Dimethyl-2,6-octadienal 5392-40-5 X 3

3-Hydroxybutanal 107-89-1 X 1, 2, 4

3-Methoxypropylamine 5332-73-0 X 8

3-Phenylprop-2-enal 104-55-2 X 1, 2, 3, 4, 7

4,4-Dimethyloxazolidine 51200-87-4 X 8

4,6-Dimethyl-2-heptanone 19549-80-5 X 8

4-[Abieta-8,11,13-trien-18-yl(3-oxo-3-phenylpropyl)amino]butan-2-one 

hydrochloride 143106-84-7 X 1, 4

4-Ethyloct-1-yn-3-ol 5877-42-9 X 1, 2, 3, 4

4-Hydroxy-3-methoxybenzaldehyde 121-33-5 X 3
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-15

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

4-Methoxybenzyl formate 122-91-8 X 3

4-Methoxyphenol 150-76-5 X 4

4-Methyl-2-pentanol 108-11-2 X 1, 4

4-Methyl-2-pentanone 108-10-1 X X 5

4-Nonylphenol 104-40-5 X 8

4-Nonylphenol polyethoxylate 68412-54-4 2, 3, 4

5-Chloro-2-methyl-3(2H)-isothiazolone 26172-55-4 X 1, 2, 4

Acetaldehyde 75-07-0 X X X 1, 4

Acetic acid 64-19-7 X X 1, 2, 3, 4, 5, 6, 7, 8

Acetic acid ethenyl ester, polymer with ethenol 25213-24-5 1, 4

Acetic acid, C6-8-branched alkyl esters 90438-79-2 X 4

Acetic acid, hydroxy-, reaction products with triethanolamine 68442-62-6 X 3

Acetic acid, mercapto-, monoammonium salt 5421-46-5 X 2, 8

Acetic acid, reaction products with acetophenone, cyclohexylamine, 

formaldehyde and methanol 224635-63-6 8

Acetic anhydride 108-24-7 X 1, 2, 3, 4, 7

Acetone 67-64-1 X X X 1, 3, 4, 6

Acetonitrile, 2,2',2''-nitrilotris- 7327-60-8 X 1, 4

Acetophenone 98-86-2 X X X 1

Acetyltriethyl citrate 77-89-4 X 1, 4

Acrolein 107-02-8 X X X 2

Acrylamide 79-06-1 X X 1, 2, 3, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-16

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Acrylamide/ sodium acrylate copolymer 25085-02-3 1, 2, 3, 4, 8

Acrylamide-sodium-2-acrylamido-2-methlypropane sulfonate 

copolymer 38193-60-1 1, 2, 3, 4

Acrylic acid 79-10-7 X X 2, 4

Acrylic acid, with sodium-2-acrylamido-2-methyl-1-propanesulfonate 

and sodium phosphinate 110224-99-2 X 8

Alcohols (C13-C15), ethoxylated 64425-86-1 8

Alcohols, C10-12, ethoxylated 67254-71-1 X 3

Alcohols, C10-14, ethoxylated 66455-15-0 3

Alcohols, C11-14-iso-, C13-rich 68526-86-3 X 3

Alcohols, C11-14-iso-, C13-rich, butoxylated ethoxylated 228414-35-5 1

Alcohols, C11-14-iso-, C13-rich, ethoxylated 78330-21-9 X 3, 4, 8

Alcohols, C12-13, ethoxylated 66455-14-9 X 4

Alcohols, C12-14, ethoxylated 68439-50-9 2, 3, 4, 8

Alcohols, C12-14, ethoxylated propoxylated 68439-51-0 X 1, 3, 4, 8

Alcohols, C12-14-secondary 126950-60-5 X 1, 3, 4

Alcohols, C12-14-secondary, ethoxylated 84133-50-6 3, 4, 8

Alcohols, C12-15, ethoxylated 68131-39-5 3, 4

Alcohols, C12-16, ethoxylated 68551-12-2 X 3, 4, 8

Alcohols, C14-15, ethoxylated 68951-67-7 X 3, 4, 8

Alcohols, C6-12, ethoxylated 68439-45-2 X 3, 4, 8

Alcohols, C7-9-iso-, C8-rich, ethoxylated 78330-19-5 X 2, 4, 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-17

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Alcohols, C8-10, ethoxylated propoxylated 68603-25-8 3

Alcohols, C9-11, ethoxylated 68439-46-3 X 3, 4

Alcohols, C9-11-iso-, C10-rich, ethoxylated 78330-20-8 X 1, 2, 4, 8

Alkanes C10-16-branched and linear 90622-52-9 4

Alkanes, C10-14 93924-07-3 1

Alkanes, C12-14-iso- 68551-19-9 X 2, 4, 8

Alkanes, C13-16-iso- 68551-20-2 X 1, 4

Alkenes, C>10 .alpha.- 64743-02-8 X 1, 3, 4, 8

Alkenes, C>8 68411-00-7 1

Alkenes, C24-25 alpha-, polymers with maleic anhydride, docosyl esters 68607-07-8 8

Alkyl quaternary ammonium with bentonite 71011-24-0 4

Alkyl* dimethyl ethylbenzyl ammonium chloride *(50%C12, 30%C14, 

17%C16, 3%C18) NOCAS_34320 X 8

Alkyl* dimethyl ethylbenzyl ammonium chloride *(60%C14, 30%C16, 

5%C12, 5%C18) 68956-79-6 X 8

Alkylbenzenesulfonate, linear 42615-29-2 X 1, 4, 6

Almandite and pyrope garnet 1302-62-1 1, 4

alpha-[3.5-dimethyl-1-(2-methylpropyl)hexyl]-omega-hydroxy-poly(oxy1,2-ethandiyl) 60828-78-6 3

alpha-Amylase 9000-90-2 4

alpha-Lactose monohydrate 5989-81-1 X 8

alpha-Terpineol 98-55-5 X 3

Alumina 1344-28-1 1, 2, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-18

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Aluminatesilicate 1327-36-2 8

Aluminum 7429-90-5 X X 1, 4, 6

Aluminum calcium oxide (Al2CaO4) 12042-68-1 2

Aluminum chloride 7446-70-0 1, 4

Aluminum chloride hydroxide sulfate 39290-78-3 8

Aluminum chloride, basic 1327-41-9 3, 4

Aluminum oxide (Al2O3) 90669-62-8 8

Aluminum oxide silicate 12068-56-3 1, 2, 4

Aluminum silicate 12141-46-7 1, 2, 4

Aluminum sulfate 10043-01-3 1, 4

Amaranth 915-67-3 X X 4

Amides, C8-18 and C18-unsatd., N,N-bis(hydroxyethyl) 68155-07-7 3

Amides, coco, N-[3-(dimethylamino)propyl] 68140-01-2 1, 4

Amides, coco, N-[3-(dimethylamino)propyl], alkylation products with 

chloroacetic acid, sodium salts 70851-07-9 1, 4

Amides, coco, N-[3-(dimethylamino)propyl], alkylation products with 

sodium 3-chloro-2-hydroxypropanesulfonate 70851-08-0 8

Amides, coco, N-[3-(dimethylamino)propyl], N-oxides 68155-09-9 1, 3, 4

Amides, from C16-22 fatty acids and diethylenetriamine 68876-82-4 3

Amides, tall-oil fatty, N,N-bis(hydroxyethyl) 68155-20-4 3, 4

Amides, tallow, N-[3-(dimethylamino)propyl],N-oxides 68647-77-8 1, 4

Amine oxides, cocoalkyldimethyl 61788-90-7 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-19

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Amines, C14-18; C16-18-unsaturated, alkyl, ethoxylated 68155-39-5 1

Amines, C8-18 and C18-unsatd. alkyl 68037-94-5 5

Amines, coco alkyl 61788-46-3 4

Amines, coco alkyl, acetates 61790-57-6 1, 4

Amines, coco alkyl, ethoxylated 61791-14-8 8

Amines, coco alkyldimethyl 61788-93-0 8

Amines, dicoco alkyl 61789-76-2 8

Amines, dicoco alkylmethyl 61788-62-3 8

Amines, ditallow alkyl, acetates 71011-03-5 8

Amines, hydrogenated tallow alkyl, acetates 61790-59-8 4

Amines, N-tallow alkyltrimethylenedi-, ethoxylated 61790-85-0 8

Amines, polyethylenepoly-, ethoxylated, phosphonomethylated 68966-36-9 1, 4

Amines, polyethylenepoly-, reaction products with benzyl chloride 68603-67-8 1

Amines, tallow alkyl 61790-33-8 8

Amines, tallow alkyl, ethoxylated, acetates (salts) 68551-33-7 1, 3, 4

Amines, tallow alkyl, ethoxylated, phosphates 68308-48-5 4

Aminotrimethylene phosphonic acid 6419-19-8 X 1, 4, 8

Ammonia 7664-41-7 X 1, 2, 3, 4, 7

Ammonium (lauryloxypolyethoxy)ethyl sulfate 32612-48-9 4

Ammonium acetate 631-61-8 X 1, 3, 4, 5, 8

Ammonium acrylate 10604-69-0 X 8

Ammonium acrylate-acrylamide polymer 26100-47-0 2, 4, 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-20

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Ammonium bisulfate 7803-63-6 2

Ammonium bisulfite 10192-30-0 1, 2, 3, 4, 7

Ammonium chloride 12125-02-9 1, 2, 3, 4, 5, 6, 8

Ammonium citrate (1:1) 7632-50-0 X 3

Ammonium citrate (2:1) 3012-65-5 X 8

Ammonium dodecyl sulfate 2235-54-3 X 1

Ammonium fluoride 12125-01-8 1, 4

Ammonium hydrogen carbonate 1066-33-7 X 1, 4

Ammonium hydrogen difluoride 1341-49-7 1, 3, 4, 7

Ammonium hydrogen phosphonate 13446-12-3 4

Ammonium hydroxide 1336-21-6 1, 3, 4

Ammonium lactate 515-98-0 X 8

Ammonium ligninsulfonate 8061-53-8 2

Ammonium nitrate 6484-52-2 1, 2, 3

Ammonium phosphate 7722-76-1 X 1, 4

Ammonium sulfate 7783-20-2 1, 2, 3, 4, 6

Ammonium thiosulfate 7783-18-8 8

Amorphous silica 99439-28-8 1, 7

Anethole 104-46-1 X 3

Aniline 62-53-3 X X 2, 4

Antimony pentoxide 1314-60-9 1, 4

Antimony trichloride 10025-91-9 X 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-21

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Antimony trioxide 1309-64-4 X 8

Arsenic 7440-38-2 X X 4

Ashes, residues 68131-74-8 4

Asphalt, sulfonated, sodium salt 68201-32-1 2

Attapulgite 12174-11-7 X 2, 3

Aziridine, polymer with 2-methyloxirane 31974-35-3 4, 8

Barium sulfate 7727-43-7 1, 2, 4

Bauxite 1318-16-7 1, 2, 4

Benactyzine hydrochloride 57-37-4 X 8

Bentonite 1302-78-9 1, 2, 4, 6

Bentonite, benzyl(hydrogenated tallow alkyl) dimethylammonium 

stearate complex 121888-68-4 3, 4

Benzamorf 12068-08-5 X 1, 4

Benzene 71-43-2 X X X 1, 3, 4

Benzene, 1,1'-oxybis-, sec-hexyl derivs., sulfonated, sodium salts 147732-60-3 8

Benzene, 1,1'-oxybis-, tetrapropylene derivs., sulfonated 119345-03-8 8

Benzene, 1,1'-oxybis-, tetrapropylene derivs., sulfonated, sodium salts 119345-04-9 3, 4, 8

Benzene, C10-16-alkyl derivs. 68648-87-3 X 1

Benzene, ethenyl-, polymer with 2-methyl-1,3-butadiene, hydrogenated 68648-89-5 8

Benzenemethanaminium, N,N-dimethyl-N-(2-((1-oxo-2-propen-1-

yl)oxy)ethyl)-, chloride (1:1), polymer with 2-propenamide 74153-51-8 3

Benzenesulfonic acid 98-11-3 X 2
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-22

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Benzenesulfonic acid, (1-methylethyl)-, 37953-05-2 X 4

Benzenesulfonic acid, (1-methylethyl)-, ammonium salt 37475-88-0 X 3, 4

Benzenesulfonic acid, (1-methylethyl)-, sodium salt 28348-53-0 X 8

Benzenesulfonic acid, C10-16-alkyl derivs. 68584-22-5 X 1, 4

Benzenesulfonic acid, C10-16-alkyl derivs., compds. with 

cyclohexylamine 255043-08-4 X 1

Benzenesulfonic acid, C10-16-alkyl derivs., compds. with 

triethanolamine 68584-25-8 X 8

Benzenesulfonic acid, C10-16-alkyl derivs., potassium salts 68584-27-0 X 1, 4, 8

Benzenesulfonic acid, dodecyl-, branched, compds. with 2-propanamine 90218-35-2 X 4

Benzenesulfonic acid, mono-C10-16 alkyl derivs., compds. with 2-

propanamine 68648-81-7 1, 4

Benzenesulfonic acid, mono-C10-16-alkyl derivs., sodium salts 68081-81-2 X 8

Benzoic acid 65-85-0 X X 1, 4, 7

Benzyl chloride 100-44-7 X X X 1, 2, 4, 8

Benzyldimethyldodecylammonium chloride 139-07-1 X 2, 8

Benzylhexadecyldimethylammonium chloride 122-18-9 X 8

Benzyltrimethylammonium chloride 56-93-9 X 8

Bicine 150-25-4 X 1, 4

Bio-Perge 55965-84-9 8

Bis(1-methylethyl)naphthalenesulfonic acid, cyclohexylamine salt 68425-61-6 X 1

Bis(2-chloroethyl) ether 111-44-4 X X X 8

Bisphenol A 80-05-7 X X X 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-23

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Bisphenol A/ Epichlorohydrin resin 25068-38-6 1, 2, 4

Bisphenol A/ Novolac epoxy resin 28906-96-9 1, 4

Blast furnace slag 65996-69-2 2, 3

Borax 1303-96-4 1, 2, 3, 4, 6

Boric acid 10043-35-3 1, 2, 3, 4, 6, 7

Boric acid (H3BO3), compd. with 2-aminoethanol (1:x)d 26038-87-9 8

Boric oxide 1303-86-2 1, 2, 3, 4

Boron 7440-42-8 X X 8

Boron potassium oxide (B4K2O7) 1332-77-0 8

Boron potassium oxide (B4K2O7), tetrahydrate 12045-78-2 8

Boron potassium oxide (B5KO8) 11128-29-3 1

Boron sodium oxide 1330-43-4 1, 2, 4

Boron sodium oxide pentahydrate 12179-04-3 8

Bronopol 52-51-7 X 1, 2, 3, 4, 6

Butane 106-97-8 X 2, 5

Butanedioic acid, sulfo-, 1,4-bis(1,3-dimethylbutyl) ester, sodium salt 2373-38-8 X 1

Butene 25167-67-3 X 8

Butyl glycidyl ether 2426-08-6 X 1, 4

Butyl lactate 138-22-7 X 1, 4

Butyryl trihexyl citrate 82469-79-2 X 8

C.I. Acid Red 1 3734-67-6 X 4

C.I. Acid violet 12, disodium salt 6625-46-3 X 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-24

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

C.I. Pigment Red 5 6410-41-9 X 4

C.I. Solvent Red 26 4477-79-6 X 4

C10-16-Alkyldimethylamines oxides 70592-80-2 X 4

C10-C16 ethoxylated alcohol 68002-97-1 X 1, 2, 3, 4, 8

C11-15-Secondary alcohols ethoxylated 68131-40-8 1, 2, 8

C12-14 tert-alkyl ethoxylated amines 73138-27-9 X 3

C8-10 Alcohols 85566-12-7 8

Calcined bauxite 66402-68-4 2, 8

Calcium aluminate 12042-78-3 2

Calcium bromide 7789-41-5 4

Calcium carbide (CaC2) 75-20-7 8

Calcium chloride 10043-52-4 1, 2, 3, 4, 7

Calcium dichloride dihydrate 10035-04-8 1, 4

Calcium dodecylbenzene sulfonate 26264-06-2 X 4

Calcium fluoride 7789-75-5 1, 4

Calcium hydroxide 1305-62-0 1, 2, 3, 4

Calcium hypochlorite 7778-54-3 1, 2, 4

Calcium magnesium hydroxide oxide 58398-71-3 4

Calcium oxide 1305-78-8 1, 2, 4, 7

Calcium peroxide 1305-79-9 1, 3, 4, 8

Calcium sulfate 7778-18-9 1, 2, 4

Calcium sulfate dihydrate 10101-41-4 2
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-25

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Camphor 76-22-2 X 3

Canola oil 120962-03-0 8

Carbon black 1333-86-4 X 1, 2, 4

Carbon dioxide 124-38-9 X X 1, 3, 4, 6

Carbonic acid calcium salt (1:1) 471-34-1 1, 2, 4

Carbonic acid, dipotassium salt 584-08-7 X 1, 2, 3, 4, 8

Carboxymethyl cellulose 9000-11-7 8

Carboxymethyl guar gum, sodium salt 39346-76-4 1, 2, 4

Castor oil 8001-79-4 8

Cedarwood oil 8000-27-9 3

Cellophane 9005-81-6 1, 4

Cellulose 9004-34-6 1, 2, 3, 4

Chloride 16887-00-6 X 4, 8

Chlorine 7782-50-5 X X 2

Chlorine dioxide 10049-04-4 X 1, 2, 3, 4, 8

Chlorobenzene 108-90-7 X X X 8

Chloromethane 74-87-3 X X X 8

Choline bicarbonate 78-73-9 X 3, 8

Choline chloride 67-48-1 X 1, 3, 4, 7, 8

Chromium (III) 16065-83-1 X X 2, 6

Chromium (VI) 18540-29-9 X X 6

Chromium acetate, basic 39430-51-8 2
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-26

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Chromium(III) acetate 1066-30-4 1, 2

Citric acid 77-92-9 X 1, 2, 3, 4, 7

Citronella oil 8000-29-1 3

Citronellol 106-22-9 X 3

Citrus extract 94266-47-4 1, 3, 4, 8

Coal, granular 50815-10-6 1, 2, 4

Cobalt(II) acetate 71-48-7 1, 4

Coco-betaine 68424-94-2 3

Coconut oil 8001-31-8 8

Coconut oil acid/Diethanolamine condensate (2:1) 68603-42-9 X 1

Coconut trimethylammonium chloride 61789-18-2 X 1, 8

Copper 7440-50-8 X X 1, 4

Copper sulfate 7758-98-7 1, 4, 8

Copper(I) chloride 7758-89-6 1, 4

Copper(I) iodide 7681-65-4 X 1, 2, 4, 6

Copper(II) chloride 7447-39-4 1, 3, 4

Copper(II) sulfate, pentahydrate 7758-99-8 8

Corn flour 68525-86-0 4

Corn sugar gum 11138-66-2 1, 2, 4

Corundum (Aluminum oxide) 1302-74-5 4, 8

Cottonseed, flour 68308-87-2 2, 4

Coumarin 91-64-5 X X 3
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-27

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Cremophor(R) EL 61791-12-6 1, 3

Cristobalite 14464-46-1 1, 2, 4

Crystalline silica, tridymite 15468-32-3 1, 2, 4

Cumene 98-82-8 X X X 1, 2, 3, 4

Cupric chloride dihydrate 10125-13-0 1, 4, 7

Cyclohexane 110-82-7 X 1, 7

Cyclohexanol 108-93-0 X 8

Cyclohexanone 108-94-1 X X 1, 4

Cyclohexylamine sulfate 19834-02-7 X 8

D&C Red 28 18472-87-2 X 4

D&C Red No. 33 3567-66-6 X 8

Daidzein 486-66-8 X 8

Dapsone 80-08-0 X X 1, 4

Dazomet 533-74-4 X 1, 2, 3, 4, 7, 8

Decamethylcyclopentasiloxane 541-02-6 8

Decyldimethylamine 1120-24-7 X 3, 4

Deuterium oxide 7789-20-0 8

D-Glucitol 50-70-4 X 1, 3, 4

D-Gluconic acid 526-95-4 X 1, 4

D-Glucopyranoside, methyl 3149-68-6 X 2

D-Glucose 50-99-7 X 1, 4

Di(2-ethylhexyl) phthalate 117-81-7 X X X 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-28

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Diammonium peroxydisulfate 7727-54-0 1, 2, 3, 4, 6, 7, 8

Diatomaceous earth 68855-54-9 2, 4

Diatomaceous earth, calcined 91053-39-3 1, 2, 4

Dibromoacetonitrile 3252-43-5 X X X 1, 2, 3, 4, 8

Dicalcium silicate 10034-77-2 1, 2, 4

Dichloromethane 75-09-2 X X X 8

Didecyldimethylammonium chloride 7173-51-5 X X 1, 2, 4, 8

Diethanolamine 111-42-2 X X 1, 2, 3, 4, 6

Diethylbenzene 25340-17-4 X 1, 3, 4

Diethylene glycol 111-46-6 X 1, 2, 3, 4, 7

Diethylene glycol monomethyl ether 111-77-3 X 1, 2, 4

Diethylenetriamine 111-40-0 X 1, 2, 4, 5

Diethylenetriamine reaction product with fatty acid dimers 68647-57-4 2

Diisobutyl ketone 108-83-8 X 8

Diisopropanolamine 110-97-4 X 8

Diisopropylnaphthalene 38640-62-9 X 3, 4

Dimethyl adipate 627-93-0 X 8

Dimethyl glutarate 1119-40-0 X 1, 4

Dimethyl polysiloxane 63148-62-9 1, 2, 4

Dimethyl succinate 106-65-0 X 8

Dimethylaminoethanol 108-01-0 X 2, 4

Dimethyldiallylammonium chloride 7398-69-8 X 3, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-29

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Diphenyl oxide 101-84-8 X 3

Dipotassium monohydrogen phosphate 7758-11-4 5

Dipropylene glycol 25265-71-8 X 1, 3, 4

Di-sec-butylphenol 31291-60-8 X 1

Disodium dodecyl(sulphonatophenoxy)benzenesulphonate 28519-02-0 X 1

Disodium ethylenediaminediacetate 38011-25-5 X 1, 4

Disodium ethylenediaminetetraacetate dihydrate 6381-92-6 X 1

Disodium octaborate 12008-41-2 4, 8

Disodium octaborate tetrahydrate 12280-03-4 1, 4

Disodium sulfide 1313-82-2 8

Distillates, petroleum, catalytic reformer fractionator residue, lowboiling 68477-31-6 1, 4

Distillates, petroleum, heavy arom. 67891-79-6 1, 4

Distillates, petroleum, hydrodesulfurized light catalytic cracked 68333-25-5 1

Distillates, petroleum, hydrodesulfurized middle 64742-80-9 1

Distillates, petroleum, hydrotreated heavy naphthenic 64742-52-5 1, 2, 3, 4

Distillates, petroleum, hydrotreated heavy paraffinic 64742-54-7 1, 2, 4

Distillates, petroleum, hydrotreated light 64742-47-8 1, 2, 3, 4, 5, 7, 8

Distillates, petroleum, hydrotreated light naphthenic 64742-53-6 1, 2, 8

Distillates, petroleum, hydrotreated light paraffinic 64742-55-8 8

Distillates, petroleum, hydrotreated middle 64742-46-7 1, 2, 3, 4, 8

Distillates, petroleum, light catalytic cracked 64741-59-9 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-30

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Distillates, petroleum, light hydrocracked 64741-77-1 3

Distillates, petroleum, solvent-dewaxed heavy paraffinic 64742-65-0 1

Distillates, petroleum, solvent-refined heavy naphthenic 64741-96-4 1, 4

Distillates, petroleum, steam-cracked 64742-91-2 1, 4

Distillates, petroleum, straight-run middle 64741-44-2 1, 2, 4

Distillates, petroleum, sweetened middle 64741-86-2 1, 4

Ditallow alkyl ethoxylated amines 71011-04-6 3

D-Lactic acid 10326-41-7 X 1, 4

D-Limonene 5989-27-5 X X X 1, 3, 4, 5, 7, 8

Docusate sodium 577-11-7 X 1

Dodecamethylcyclohexasiloxane 540-97-6 8

Dodecane 112-40-3 X X 8

Dodecylbenzene 123-01-3 X 3, 4

Dodecylbenzenesulfonic acid 27176-87-0 X X 2, 3, 4, 8

Dodecylbenzenesulfonic acid, monoethanolamine salt 26836-07-7 X 1, 4

Edifas B 9004-32-4 2, 3, 4

EDTA, copper salt 12276-01-6 1, 5, 6

Endo-1,4-.beta.-mannanase 37288-54-3 3, 8

Epichlorohydrin 106-89-8 X X 1, 4, 8

Epoxy resin 25085-99-8 1, 4, 8

Erucic amidopropyl dimethyl betaine 149879-98-1 1, 3

Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2-propenyl)oxy]-, chloride 44992-01-0 X 3
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-31

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2-propenyl)oxy]-,chloride, 

polymer with 2-propenamide 69418-26-4 1, 3, 4

Ethanaminium, N,N,N-trimethyl-2-[(2-methyl-1-oxo-2-propen-1-yl)oxy]-, 

chloride (1:1), polymer with 2-propenamide 35429-19-7 8

Ethanaminium, N,N,N-trimethyl-2-[(2-methyl-1-oxo-2-propenyl)oxy]-, 

methyl sulfate, homopolymer 27103-90-8 8

Ethane 74-84-0 X 2, 5

Ethanol 64-17-5 X X X 1, 2, 3, 4, 5, 6, 8

Ethanol, 2,2',2''-nitrilotris-, tris(dihydrogen phosphate) (ester), sodium 

salt 68171-29-9 X 4

Ethanol, 2,2'-iminobis-, N-coco alkyl derivs., N-oxides 61791-47-7 1

Ethanol, 2,2'-iminobis-, N-tallow alkyl derivs. 61791-44-4 1

Ethanol, 2,2'-oxybis-, reaction products with ammonia, morpholine 

derivs. residues 68909-77-3 4, 8

Ethanol, 2,2-oxybis-, reaction products with ammonia, morpholine 

derivs. residues, acetates (salts) 68877-16-7 4

Ethanol, 2,2-oxybis-, reaction products with ammonia, morpholine 

derivs. residues, reaction products with sulfur dioxide 102424-23-7 4

Ethanol, 2-[2-[2-(tridecyloxy)ethoxy]ethoxy]-, hydrogen sulfate, sodium 

salt 25446-78-0 X 1, 4

Ethanol, 2-amino-, polymer with formaldehyde 34411-42-2 4

Ethanol, 2-amino-, reaction products with ammonia, by-products from, 

phosphonomethylated 68649-44-5 4

Ethanolamined 141-43-5 X 1, 2, 3, 4, 6, 8

Ethoxylated dodecyl alcohol 9002-92-0 X 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-32

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Ethoxylated hydrogenated tallow alkylamines 61790-82-7 4

Ethoxylated, propoxylated trimethylolpropane 52624-57-4 3

Ethyl acetate 141-78-6 X X 1, 4, 7

Ethyl acetoacetate 141-97-9 X 1, 4

Ethyl benzoate 93-89-0 X 3

Ethyl lactate 97-64-3 X 3

Ethyl salicylate 118-61-6 X 3

Ethylbenzene 100-41-4 X X X 1, 2, 3, 4, 7

Ethylcellulose 9004-57-3 2

Ethylene 74-85-1 X X 8

Ethylene glycol 107-21-1 X X X 1, 2, 3, 4, 6, 7, 8

Ethylene oxide 75-21-8 X X 1, 2, 3, 4

Ethylenediamine 107-15-3 X X 2, 4

Ethylenediaminetetraacetic acid 60-00-4 X 1, 2, 4

Ethylenediaminetetraacetic acid tetrasodium salt 64-02-8 X 1, 2, 3, 4

Ethylenediaminetetraacetic acid, diammonium copper salt 67989-88-2 4

Ethylenediaminetetraacetic acid, disodium salt 139-33-3 X 1, 3, 4, 8

Ethyne 74-86-2 X 7

Fats and Glyceridic oils, vegetable, hydrogenated 68334-28-1 8

Fatty acid, tall oil, hexa esters with sorbitol, ethoxylated 61790-90-7 1, 4

Fatty acids, C 8-18 and C18-unsaturated compounds with 

diethanolamine 68604-35-3 3
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-33

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Fatty acids, C14-18 and C16-18-unsatd., distn. residues 70321-73-2 2

Fatty acids, C18-unsatd., dimers 61788-89-4 X 2

Fatty acids, C18-unsatd., dimers, compds. with ethoxylated tall-oil fatty 

acid-polyethylenepolyamine reaction products 68132-59-2 8

Fatty acids, C18-unsatd., dimers, ethoxylated propoxylated 68308-89-4 8

Fatty acids, coco, ethoxylated 61791-29-5 3

Fatty acids, coco, reaction products with diethylenetriamine and soya 

fatty acids, ethoxylated, chloromethane-quaternized 68604-75-1 8

Fatty acids, coco, reaction products with ethanolamine, ethoxylated 61791-08-0 3

Fatty acids, tall oil, reaction products with acetophenone, formaldehyde 

and thiourea 68188-40-9 3

Fatty acids, tall-oil 61790-12-3 1, 2, 3, 4

Fatty acids, tall-oil, reaction products with diethylenetriamine 61790-69-0 1, 4

Fatty acids, tall-oil, reaction products with diethylenetriamine, maleic 

anhydride, tetraethylenepentamine and triethylenetetramine 68990-47-6 8

Fatty acids, tallow, sodium salts 8052-48-0 1, 3

Fatty acids, vegetable-oil, reaction products with diethylenetriamine 68153-72-0 3

Fatty quaternary ammonium chloride 61789-68-2 1, 4

FD&C Blue no. 1 3844-45-9 X X 1, 4

FD&C Yellow 5 1934-21-0 X 8

FD&C Yellow 6 2783-94-0 X X 8

Ferric chloride 7705-08-0 1, 3, 4

Ferric sulfate 10028-22-5 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-34

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Ferrous sulfate monohydrate 17375-41-6 2

Ferumoxytol 1309-38-2 8

Fiberglass 65997-17-3 2, 3, 4

Formaldehyde 50-00-0 X X 1, 2, 3, 4

Formaldehyde polymer with 4,1,1-(dimethylethyl)phenol and 

methyloxirane 29316-47-0 3

Formaldehyde polymer with methyl oxirane, 4-nonylphenol and oxirane 63428-92-2 4, 8

Formaldehyde, polymer with 4-(1,1-dimethylethyl)phenol, 2-

methyloxirane and oxirane 30704-64-4 1, 2, 4, 8

Formaldehyde, polymer with 4-(1,1-dimethylethyl)phenol, 2-

methyloxirane, 4-nonylphenol and oxirane 68188-99-8 8

Formaldehyde, polymer with 4-nonylphenol and oxirane 30846-35-6 1, 4

Formaldehyde, polymer with 4-nonylphenol and phenol 40404-63-5 8

Formaldehyde, polymer with ammonia and phenol 35297-54-2 1, 4

Formaldehyde, polymer with bisphenol A 25085-75-0 4

Formaldehyde, polymer with N1-(2-aminoethyl)-1,2-ethanediamine, 

benzylated 70750-07-1 8

Formaldehyde, polymer with nonylphenol and oxirane 55845-06-2 4

Formaldehyde, polymers with branched 4-nonylphenol, oxirane and 2-

methyloxirane 153795-76-7 1, 3

Formaldehyde/amine NOCAS_51232 1, 2, 3, 4

Formamide 75-12-7 X 1, 2, 3, 4

Formic acid 64-18-6 X X X 1, 2, 3, 4, 6, 7

Formic acid, potassium salt 590-29-4 X 1, 3, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-35

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Frits, chemicals 65997-18-4 8

Fuel oil, no. 2 68476-30-2 1, 2

Fuels, diesel 68334-30-5 2

Fuels, diesel, no. 2 68476-34-6 2, 4, 8

Fuller's earth 8031-18-3 2

Fumaric acid 110-17-8 X 1, 2, 3, 4, 6

Fumes, silica 69012-64-2 8

Furfural 98-01-1 X X 1, 4

Furfuryl alcohol 98-00-0 X 1, 4

Galantamine hydrobromide 69353-21-5 X 8

Gas oils, petroleum, straight-run 64741-43-1 1, 4

Gelatin 9000-70-8 1, 4

Gilsonite 12002-43-6 1, 2, 4

Gluconic acid 133-42-6 X 7

Glutaraldehyde 111-30-8 X X 1, 2, 3, 4, 7

Glycerides, C14-18 and C16-18-unsatd. mono- and di- 67701-32-0 8

Glycerol 56-81-5 X 1, 2, 3, 4, 5

Glycine, N-(carboxymethyl)-N-(2-hydroxyethyl)-, disodium salt 135-37-5 X 1

Glycine, N-(hydroxymethyl)-, monosodium salt 70161-44-3 X 8

Glycine, N,N-bis(carboxymethyl)-, trisodium salt 5064-31-3 X 1, 2, 3, 4

Glycine, N-[2-[bis(carboxymethyl)amino]ethyl]-N-(2-hydroxyethyl)-, 

trisodium salt 139-89-9 X 1
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-36

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Glycolic acid 79-14-1 X X 1, 3, 4

Glycolic acid sodium salt 2836-32-0 X 1, 3, 4

Glyoxal 107-22-2 X X 1, 2, 4

Glyoxylic acid 298-12-4 X 1

Goethite (Fe(OH)O) 1310-14-1 8

Guar gum 9000-30-0 1, 2, 3, 4, 7, 8

Guar gum, carboxymethyl 2-hydroxypropyl ether, sodium salt 68130-15-4 1, 2, 3, 4, 7

Gypsum (Ca(SO4).2H2O) 13397-24-5 2, 4

Hematite 1317-60-8 X 1, 2, 4

Hemicellulase 9012-54-8 1, 2, 3, 4, 5

Hemicellulase enzyme concentrate 9025-56-3 3, 4

Heptane 142-82-5 X X 1, 2

Heptene, hydroformylation products, high-boiling 68526-88-5 1, 4

Hexadecyltrimethylammonium bromide 57-09-0 X 1

Hexane 110-54-3 X X X 5

Hexanedioic acid 124-04-9 X X 1, 2, 4, 6

Humic acids, commercial grade 1415-93-6 2

Hydrazine 302-01-2 X X 8

Hydrocarbons, terpene processing by-products 68956-56-9 1, 3, 4

Hydrochloric acid 7647-01-0 X X 1, 2, 3, 4, 5, 6, 7, 8

Hydrogen fluoride 7664-39-3 1, 2, 4

Hydrogen peroxide 7722-84-1 X 1, 3, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-37

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Hydrogen sulfide 7783-06-4 1, 2

Hydroxyethylcellulose 9004-62-0 1, 2, 3, 4

Hydroxylamine hydrochloride 5470-11-1 1, 3, 4

Hydroxylamine sulfate (2:1) 10039-54-0 4

Hydroxypropyl cellulose 9004-64-2 2, 4

Hydroxypropyl guar gum 39421-75-5 1, 3, 4, 5, 6, 8

Hydroxyvalerenic acid 1619-16-5 X 8

Hypochlorous acid 7790-92-3 8

Illite 12173-60-3 8

Ilmenite (FeTiO3), conc. 98072-94-7 8

Indole 120-72-9 X 2

Inulin, carboxymethyl ether, sodium salt 430439-54-6 1, 4

Iridium oxide 12030-49-8 8

Iron 7439-89-6 X X 2, 4

Iron oxide 1332-37-2 1, 4

Iron oxide (Fe3O4) 1317-61-9 4

Iron(II) sulfate 7720-78-7 2

Iron(II) sulfate heptahydrate 7782-63-0 1, 2, 3, 4

Iron(III) oxide 1309-37-1 X 1, 2, 4

Isoascorbic acid 89-65-6 X 1, 3, 4

Isobutane 75-28-5 X 2

Isobutene 115-11-7 X 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-38

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Isooctanol 26952-21-6 X 1, 4, 5

Isopentyl alcohol 123-51-3 X 1, 4

Isopropanol 67-63-0 X X X 1, 2, 3, 4, 6, 7

Isopropanolamine dodecylbenzene 42504-46-1 X 1, 3, 4

Isopropylamine 75-31-0 X 1, 4

Isoquinoline 119-65-3 X X 8

Isoquinoline, reaction products with benzyl chloride and quinoline 68909-80-8 X 3

Isoquinolinium, 2-(phenylmethyl)-, chloride 35674-56-7 X 3

Isotridecanol, ethoxylated 9043-30-5 1, 3, 4, 8

Kaolin 1332-58-7 1, 2, 4

Kerosine, petroleum, hydrodesulfurized 64742-81-0 1, 2, 4

Kieselguhr 61790-53-2 1, 2, 4

Kyanite 1302-76-7 1, 2, 4

Lactic acid 50-21-5 X 1, 4, 8

Lactose 63-42-3 X 3

Latex 2000 TM 9003-55-8 X 2, 4

Lauryl hydroxysultaine 13197-76-7 X 1

Lavandula hybrida abrial herb oil 8022-15-9 3

L-Dilactide 4511-42-6 X 1, 4

Lead 7439-92-1 X X 1, 4

Lecithin 8002-43-5 4

L-Glutamic acid 56-86-0 X 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-39

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Lignite 129521-66-0 2

Lignosulfuric acid 8062-15-5 2

Ligroine 8032-32-4 X 8

Limestone 1317-65-3 1, 2, 3, 4

Linseed oil 8001-26-1 8

L-Lactic acid 79-33-4 X 1, 4, 8

Magnesium carbonate (1:1) 7757-69-9 8

Magnesium carbonate (1:x) 546-93-0 1, 3, 4

Magnesium chloride 7786-30-3 1, 2, 4

Magnesium chloride hexahydrate 7791-18-6 4

Magnesium hydroxide 1309-42-8 1, 4

Magnesium iron silicate 19086-72-7 1, 4

Magnesium nitrate 10377-60-3 1, 2, 4

Magnesium oxide 1309-48-4 1, 2, 3, 4

Magnesium peroxide 14452-57-4 1, 4

Magnesium phosphide 12057-74-8 1

Magnesium silicate 1343-88-0 1, 4

Magnesium sulfate 7487-88-9 8

Maleic acid homopolymer 26099-09-2 8

Methanamine-N-methyl polymer with chloromethyl oxirane 25988-97-0 4

Methane 74-82-8 X 2, 5

Methanol 67-56-1 X X X 1, 2, 3, 4, 5, 6, 7, 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-40

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Methenamine 100-97-0 X 1, 2, 4

Methoxyacetic acid 625-45-6 X 8

Methyl cellulose 9004-67-5 8

Methyl salicylate 119-36-8 X 1, 2, 3, 4, 7

Methyl vinyl ketone 78-94-4 X 1, 4

Methylcyclohexane 108-87-2 X X 1

Methylene bis(thiocyanate) 6317-18-6 X 2

Methylenebis(5-methyloxazolidine) 66204-44-2 X 2

Methyloxirane polymer with oxirane, mono (nonylphenol) ether, 

branched 68891-11-2 3

Mica 12001-26-2 1, 2, 4, 6

Mineral oil - includes paraffin oil 8012-95-1 X 4, 8

Mineral spirits 64475-85-0 X 2

Mono- and di- potassium salts of phosphorous acid 13492-26-7 8

Montmorillonite 1318-93-0 2

Morpholine 110-91-8 X X 1, 2, 4

Morpholinium, 4-ethyl-4-hexadecyl-, ethyl sulfate 78-21-7 X 8

MT 6 76-31-3 8

Mullite 1302-93-8 1, 2, 4, 8

N-(2-Acryloyloxyethyl)-N-benzyl-N,N-dimethylammonium chloride 46830-22-2 X 3

N-(3-Chloroallyl)hexaminium chloride 4080-31-3 X 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-41

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

N,N,N-Trimethyl-2[1-oxo-2-propenyl]oxy ethanaminimum chloride, 

homopolymer 54076-97-0 3

N,N,N-Trimethyl-3-((1-oxooctadecyl)amino)-1-propanaminium methyl 

sulfate 19277-88-4 X 1

N,N,N-Trimethyloctadecan-1-aminium chloride 112-03-8 X 1, 3, 4

N,N'-Dibutylthiourea 109-46-6 X 1, 4

N,N-Dimethyldecylamine oxide 2605-79-0 X 1, 3, 4

N,N-Dimethylformamide 68-12-2 X X X 1, 2, 4, 5, 8

N,N-Dimethylmethanamine hydrochloride 593-81-7 X 1, 4, 5, 7

N,N-Dimethyl-methanamine-N-oxide 1184-78-7 X 3

N,N-dimethyloctadecylamine hydrochloride 1613-17-8 X 1, 4

N,N'-Methylenebisacrylamide 110-26-9 X 1, 4

Naphtha, petroleum, heavy catalytic reformed 64741-68-0 1, 2, 3, 4

Naphtha, petroleum, hydrotreated heavy 64742-48-9 1, 2, 3, 4, 8

Naphthalene 91-20-3 X X X 1, 2, 3, 4, 5, 7

Naphthalenesulfonic acid, bis(1-methylethyl)- 28757-00-8 X 1, 3, 4

Naphthalenesulfonic acid, polymer with formaldehyde, sodium salt 9084-06-4 2

Naphthalenesulphonic acid, bis (1-methylethyl)-methyl derivatives 99811-86-6 X 1

Naphthenic acid ethoxylate 68410-62-8 X 4

Navy fuels JP-5 NOCAS_25704 1, 2, 3, 4, 8

Nickel sulfate 7786-81-4 X 2

Nickel(II) sulfate hexahydrate 10101-97-0 X 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-42

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Nitriles, tallow, hydrogenated 61790-29-2 4

Nitrilotriacetamide 4862-18-4 X 1, 4, 7

Nitrilotriacetic acid 139-13-9 X X 1, 4

Nitrilotriacetic acid trisodium monohydrate 18662-53-8 X X 1, 4

Nitrogen 7727-37-9 1, 2, 3, 4, 6

N-Methyl-2-pyrrolidone 872-50-4 X X 1, 4

N-Methyldiethanolamine 105-59-9 X 2, 4, 8

N-Methylethanolamine 109-83-1 X 4

N-Methyl-N-hydroxyethyl-N-hydroxyethoxyethylamine 68213-98-9 X 4

N-Oleyl diethanolamide 13127-82-7 X 1, 4

Nonyl nonoxynol-10 9014-93-1 4

Nonylphenol (mixed) 25154-52-3 1, 4

Octamethylcyclotetrasiloxane 556-67-2 8

Octoxynol-9 9036-19-5 1, 2, 3, 4, 8

Oil of eucalyptus 8000-48-4 3

Oil of lemongrass 8007-02-1 3

Oil of rosemary 8000-25-7 3

Oleic acid 112-80-1 X 2, 4

Olivine-group minerals 1317-71-1 4

Orange terpenes 8028-48-6 4

Oxirane, 2-methyl-, polymer with oxirane, ether with (chloromethyl) 

oxirane polymer with 4,4`-(1-methylidene) bis[phenol] 68036-95-3 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-43

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Oxirane, 2-methyl-, polymer with oxirane, mono(2-ethylhexyl) ether 64366-70-7 8

Oxirane, 2-methyl-, polymer with oxirane, monodecyl ether 37251-67-5 8

Oxirane, methyl-, polymer with oxirane, mono-C10-16-alkyl ethers, 

phosphates 68649-29-6 1, 4

Oxygen 7782-44-7 4

o-Xylene 95-47-6 X X X 4

Ozone 10028-15-6 8

Paraffin waxes and Hydrocarbon waxes 8002-74-2 1

Paraformaldehyde 30525-89-4 2

PEG-10 Hydrogenated tallow amine 61791-26-2 1, 3

Pentaethylenehexamine 4067-16-7 X 4

Pentane 109-66-0 X X X 2, 5

Pentyl acetate 628-63-7 X 3

Pentyl butyrate 540-18-1 X 3

Peracetic acid 79-21-0 X 8

Perboric acid, sodium salt, monohydrate 10332-33-9 1, 8

Perlite 93763-70-3 4

Petrolatum, petroleum, oxidized 64743-01-7 3

Petroleum 8002-05-9 X 1, 2

Petroleum distillate hydrotreated light 6742-47-8 8

Phenanthrene 85-01-8 X X X 6

Phenol 108-95-2 X X X 1, 2, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-44

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Phenol, 4,4'-(1-methylethylidene)bis-, polymer with 2-

(chloromethyl)oxirane, 2-methyloxirane and oxirane 68123-18-2 8

Phenol-formaldehyde resin 9003-35-4 1, 2, 4, 7

Phosphine 7803-51-2 X 1, 4

Phosphonic acid 13598-36-2 1, 4

Phosphonic acid (dimethylamino(methylene)) 29712-30-9 X 1

Phosphonic acid, (((2-[(2-

hydroxyethyl)(phosphonomethyl)amino)ethyl)imino]bis(methylene))bis-

, compd. with 2-aminoethanol

129828-36-0 X 1

Phosphonic acid, (1-hydroxyethylidene)bis-, potassium salt 67953-76-8 X 4

Phosphonic acid, (1-hydroxyethylidene)bis-, tetrasodium salt 3794-83-0 X 1, 4

Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1-

ethanediylnitrilobis(methylene)]]tetrakis15827-60-8 X 1, 2, 4

Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1-

ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt (1:x) 70714-66-8 X 3

Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1-

ethanediylnitrilobis(methylene)]]tetrakis-, sodium salt 22042-96-2 X 3

Phosphonic acid, [[(phosphonomethyl)imino]bis[6,1-

hexanediylnitrilobis(methylene)]]tetrakis34690-00-1 X 1, 4, 8

Phosphonic acid, [[(phosphonomethyl)imino]bis[6,1-

hexanediylnitrilobis(methylene)]]tetrakis-, sodium salt (1:x) 35657-77-3 8

Phosphoric acid 7664-38-2 X 1, 2, 4

Phosphoric acid, aluminium sodium salt 7785-88-8 X 1, 2

Phosphoric acid, ammonium salt (1:x) 10124-31-9 8

Phosphoric acid, ammonium salt (1:3) 10361-65-6 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-45

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Phosphoric acid, diammonium salt 7783-28-0 X 2

Phosphoric acid, mixed decyl and Et and octyl esters 68412-60-2 1

Phosphorous acid 10294-56-1 1

Phthalic anhydride 85-44-9 X X 1, 4

Pine oils 8002-09-3 1, 2, 4

Pluronic F-127 9003-11-6 1, 3, 4, 8

Policapram (Nylon 6) 25038-54-4 X 1, 4

Poly (acrylamide-co-acrylic acid), partial sodium salt 62649-23-4 3, 4

Poly(acrylamide-co-acrylic acid) 9003-06-9 4, 8

Poly(lactide) 26680-10-4 1

Poly(oxy-1,2-ethanediyl), .alpha.-(nonylphenyl)-.omega.-hydroxy-, 

phosphate 51811-79-1 1, 4

Poly(oxy-1,2-ethanediyl), .alpha.-(octylphenyl)-.omega.-hydroxy-, 

branched 68987-90-6 X 1, 4

Poly(oxy-1,2-ethanediyl), .alpha.,.alpha.'-[[(9Z)-9-octadecenylimino]di2,1-ethanediyl]bis[.omega.-hydroxy26635-93-8 1, 4

Poly(oxy-1,2-ethanediyl), .alpha.-[(9Z)-1-oxo-9-octadecenyl]-.omega.-

hydroxy9004-96-0 8

Poly(oxy-1,2-ethanediyl), .alpha.-hydro-.omega.-hydroxy-, mono-C10-

14-alkyl ethers, phosphates 68585-36-4 8

Poly(oxy-1,2-ethanediyl), .alpha.-hydro-.omega.-hydroxy-, mono-C8-10-

alkyl ethers, phosphates 68130-47-2 8

Poly(oxy-1,2-ethanediyl), .alpha.-isodecyl-.omega.-hydroxy- 61827-42-7 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-46

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Poly(oxy-1,2-ethanediyl), .alpha.-sulfo-.omega.-hydroxy-, C10-16-alkyl 

ethers, sodium salts 68585-34-2 8

Poly(oxy-1,2-ethanediyl), .alpha.-sulfo-.omega.-hydroxy-, C12-14-alkyl 

ethers, sodium salts 68891-38-3 1, 4

Poly(oxy-1,2-ethanediyl), alpha-(2,3,4,5-tetramethylnonyl)-omegahydroxy 68015-67-8 1

Poly(oxy-1,2-ethanediyl), alpha-(nonylphenyl)-omega-hydroxy-

,branched, phosphates 68412-53-3 1

Poly(oxy-1,2-ethanediyl), alpha-hexyl-omega-hydroxy 31726-34-8 3, 8

Poly(oxy-1,2-ethanediyl), alpha-hydro-omega-hydroxy-, (9Z)-9-

octadecenoate 56449-46-8 3

Poly(oxy-1,2-ethanediyl), alpha-hydro-omega-hydroxy-, ether with 

alpha-fluoro-omega-(2-hydroxyethyl)poly(difluoromethylene) (1:1) 65545-80-4 1

Poly(oxy-1,2-ethanediyl), alpha-hydro-omega-hydroxy-, ether with Dglucitol (2:1), tetra-(9Z)-9-octadecenoate 61723-83-9 8

Poly(oxy-1,2-ethanediyl), alpha-sulfo-omega-(decyloxy)-, ammonium 

salt (1:1) 52286-19-8 4

Poly(oxy-1,2-ethanediyl), alpha-sulfo-omega-(hexyloxy)-, ammonium 

salt (1:1) 63428-86-4 1, 3, 4

Poly(oxy-1,2-ethanediyl), alpha-sulfo-omega-(hexyloxy)-, C6-10-alkyl 

ethers, ammonium salts 68037-05-8 3, 4

Poly(oxy-1,2-ethanediyl), alpha-sulfo-omega--(nonylphenoxy)- 9081-17-8 4

Poly(oxy-1,2-ethanediyl), alpha-sulfo-omega-(octyloxy)-, ammonium 

salt (1:1) 52286-18-7 4

Poly(oxy-1,2-ethanediyl), alpha-sulfo-omega-hydroxy-, C10-12-alkyl 

ethers, ammonium salts 68890-88-0 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-47

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Poly(oxy-1,2-ethanediyl), alpha-tridecyl-omega-hydroxy- 24938-91-8 1, 3, 4

Poly(oxy-1,2-ethanediyl), alpha-undecyl-omega-hydroxy-, branched and 

linear 127036-24-2 1

Poly-(oxy-1,2-ethanediyl)-alpha-undecyl-omega-hydroxy 34398-01-1 1, 3, 4, 8

Poly(oxy-1,2-ethanediyl)-nonylphenyl-hydroxy branched 127087-87-0 1, 2, 3, 4

Poly(sodium-p-styrenesulfonate) 25704-18-1 1, 4

Poly(tetrafluoroethylene) 9002-84-0 X 8

Poly[imino(1,6-dioxo-1,6-hexanediyl)imino-1,6-hexanediyl] 32131-17-2 2

Polyacrylamide 9003-05-8 1, 2, 4, 6

Polyacrylate/ polyacrylamide blend NOCAS_51256 2

Polyacrylic acid, sodium bisulfite terminated 66019-18-9 3

Polyethylene glycol 25322-68-3 1, 2, 3, 4, 7, 8

Polyethylene glycol (9Z)-9-octadecenyl ether 9004-98-2 8

Polyethylene glycol ester with tall oil fatty acid 68187-85-9 1

Polyethylene glycol monobutyl ether 9004-77-7 1, 4

Polyethylene glycol mono-C8-10-alkyl ether sulfate ammonium 68891-29-2 1, 3, 4

Polyethylene glycol nonylphenyl ether 9016-45-9 1, 2, 3, 4, 8

Polyethylene glycol tridecyl ether phosphate 9046-01-9 1, 3, 4

Polyethyleneimine 9002-98-6 4

Polyglycerol 25618-55-7 2

Poly-L-aspartic acid sodium salt 34345-47-6 8

Polyoxyethylene sorbitan trioleate 9005-70-3 3
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-48

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Polyoxyethylene(10)nonylphenyl ether 26027-38-3 1, 2, 3, 4, 8

Polyoxyl 15 hydroxystearate 70142-34-6 8

Polyoxypropylenediamine 9046-10-0 1

Polyphosphoric acids, esters with triethanolamine, sodium salts 68131-72-6 1

Polyphosphoric acids, sodium salts 68915-31-1 X 1, 4

Polypropylene glycol 25322-69-4 X 1, 2, 4

Polypropylene glycol glycerol triether, epichlorohydrin, bisphenol A 

polymer 68683-13-6 1

Polyquaternium 5 26006-22-4 1, 4

Polysorbate 20 9005-64-5 8

Polysorbate 60 9005-67-8 3, 4

Polysorbate 80 9005-65-6 3, 4

Polyvinyl acetate copolymer 9003-20-7 X 2

Polyvinyl acetate, partially hydrolyzed 304443-60-5 8

Polyvinyl alcohol 9002-89-5 X 1, 2, 4

Polyvinyl alcohol/polyvinyl acetate copolymer NOCAS_50147 2

Polyvinylidene chloride 9002-85-1 8

Polyvinylpyrrolidone 9003-39-8 X 8

Portland cement 65997-15-1 2, 4

Potassium acetate 127-08-2 X 1, 3, 4

Potassium aluminum silicate 1327-44-2 5

Potassium antimonate 29638-69-5 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-49

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Potassium bisulfate 7646-93-7 8

Potassium borate 12712-38-8 3

Potassium borate (1:x) 20786-60-1 1, 3

Potassium carbonate sesquihydrate 6381-79-9 5

Potassium chloride 7447-40-7 1, 2, 3, 4, 5, 6, 7

Potassium dichromate 7778-50-9 4

Potassium hydroxide 1310-58-3 1, 2, 3, 4, 6

Potassium iodide 7681-11-0 X 1, 4

Potassium metaborate 13709-94-9 1, 2, 3, 4, 8

Potassium oleate 143-18-0 X 4

Potassium oxide 12136-45-7 1, 4

Potassium persulfate 7727-21-1 1, 2, 4

Potassium phosphate, tribasic 7778-53-2 X 8

Potassium sulfate 7778-80-5 2

Propane 74-98-6 X 2, 5

Propanol, 1(or 2)-(2-methoxymethylethoxy)- 34590-94-8 X 1, 2, 3, 4

Propargyl alcohol 107-19-7 X X X 1, 2, 3, 4, 5, 6, 7, 8

Propylene carbonate 108-32-7 X 1, 4

Propylene pentamer 15220-87-8 X 1

p-Xylene 106-42-3 X X X 1, 4

Pyridine, alkyl derivs. 68391-11-7 1, 4

Pyridinium, 1-(phenylmethyl)-, alkyl derivs., chlorides 100765-57-9 4, 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-50

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Pyridinium, 1-(phenylmethyl)-, C7-8-alkyl derivs., chlorides 70914-44-2 6

Pyrimidine 289-95-2 X 2

Pyrrole 109-97-7 X 2

Quartz-alpha (SiO2) 14808-60-7 X 1, 2, 3, 4, 5, 6, 8

Quaternary ammonium compounds (2-ethylhexyl) hydrogenated tallow 

alkyl)dimethyl, methyl sulfates 308074-31-9 8

Quaternary ammonium compounds, (oxydi-2,1-ethanediyl)bis[coco 

alkyldimethyl, dichlorides 68607-28-3 2, 3, 4, 8

Quaternary ammonium compounds, benzyl(hydrogenated tallow 

alkyl)dimethyl, bis(hydrogenated tallow alkyl)dimethylammonium salt 

with bentonite 

71011-25-1 8

Quaternary ammonium compounds, benzylbis(hydrogenated tallow 

alkyl)methyl, salts with bentonite 68153-30-0 2, 5, 6

Quaternary ammonium compounds, benzyl-C10-16-

alkyldimethyl, chlorides 68989-00-4 1, 4

Quaternary ammonium compounds, benzyl-C12-16-alkyldimethyl, 

chlorides 68424-85-1 X 1, 2, 4, 8

Quaternary ammonium compounds, benzyl-C12-18-alkyldimethyl, 

chlorides 68391-01-5 8

Quaternary ammonium compounds, benzylcoco alkyldimethyl, 

chlorides 61789-71-7 8

Quaternary ammonium compounds, bis(hydrogenated tallow 

alkyl)dimethyl, salts with bentonite 68953-58-2 2, 3, 4, 8

Quaternary ammonium compounds, bis(hydrogenated tallow 

alkyl)dimethyl, salts with hectorite 71011-27-3 2

Quaternary ammonium compounds, di-C8-10-alkyldimethyl, chlorides 68424-95-3 X 2
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-51

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Quaternary ammonium compounds, dicoco alkyldimethyl, chlorides 61789-77-3 1

Quaternary ammonium compounds, pentamethyltallow 

alkyltrimethylenedi-, dichlorides 68607-29-4 4

Quaternary ammonium compounds, trimethyltallow alkyl, chlorides 8030-78-2 1, 4

Quinaldine 91-63-4 X 8

Quinoline 91-22-5 X X X 2, 4

Raffinates (petroleum) 68514-29-4 5

Raffinates, petroleum, sorption process 64741-85-1 1, 2, 4, 8

Residual oils, petroleum, solvent-refined 64742-01-4 5

Residues, petroleum, catalytic reformer fractionator 64741-67-9 1, 4, 8

Rhodamine B 81-88-9 X X 4

Rosin 8050-09-7 1, 4

Rutile titanium dioxide 1317-80-2 8

Sand 308075-07-2 8

Scandium oxide 12060-08-1 8

Sepiolite 63800-37-3 2

Silane, dichlorodimethyl-, reaction products with silica 68611-44-9 2, 4

Silica 7631-86-9 X X 1, 2, 3, 4, 8

silica gel, cryst. -free 112926-00-8 3, 4

Silica, amorphous, fumed, cryst.-free 112945-52-5 1, 3, 4

Silica, vitreous 60676-86-0 1, 4, 8

Silicic acid, aluminum potassium sodium salt 12736-96-8 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-52

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Siloxanes (Polysiloxane) 9011-19-2 4

Siloxanes and Silicones, di-Me, 3-hydroxypropyl Me, ethoxylated 

propoxylated 68937-55-3 8

Siloxanes and Silicones, di-Me, Me hydrogen 68037-59-2 8

Siloxanes and silicones, di-Me, polymers with Me silsesquioxanes 68037-74-1 4

Siloxanes and Silicones, di-Me, reaction products with silica 67762-90-7 4

Siloxanes and silicones, dimethyl, 63148-52-7 4

Silwet L77 27306-78-1 1

Sodium 1-octanesulfonate 5324-84-5 X 3

Sodium 2-mercaptobenzothiolate 2492-26-4 X 2

Sodium acetate 127-09-3 X 1, 3, 4

Sodium aluminate 1302-42-7 2, 4

Sodium benzoate 532-32-1 X 3

Sodium bicarbonate 144-55-8 X 1, 2, 3, 4, 7

Sodium bis(tridecyl) sulfobutanedioate 2673-22-5 X 4

Sodium bisulfite 7631-90-5 X 1, 3, 4

Sodium borate 1333-73-9 1, 4, 6, 7

Sodium bromate 7789-38-0 1, 2, 4

Sodium bromide 7647-15-6 1, 2, 3, 4, 7

Sodium bromosulfamate 1004542-84-0 8

Sodium C14-16 alpha-olefin sulfonate 68439-57-6 X 1, 3, 4

Sodium caprylamphopropionate 68610-44-6 X 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-53

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Sodium carbonate 497-19-8 X 1, 2, 3, 4, 8

Sodium chlorate 7775-09-9 X 1, 4

Sodium chloride 7647-14-5 1, 2, 3, 4, 5, 8

Sodium chlorite 7758-19-2 X 1, 2, 3, 4, 5, 8

Sodium chloroacetate 3926-62-3 X 3

Sodium cocaminopropionate 68608-68-4 1

Sodium decyl sulfate 142-87-0 X 1

Sodium D-gluconate 527-07-1 X 4

Sodium diacetate 126-96-5 X 1, 4

Sodium dichloroisocyanurate 2893-78-9 X 2

Sodium dl-lactate 72-17-3 X 8

Sodium dodecyl sulfate 151-21-3 X 8

Sodium erythorbate (1:1) 6381-77-7 X 1, 3, 4, 8

Sodium ethasulfate 126-92-1 X 1

Sodium formate 141-53-7 X 2, 8

Sodium hydrogen sulfate 7681-38-1 4

Sodium hydroxide 1310-73-2 1, 2, 3, 4, 7, 8

Sodium hydroxymethanesulfonate 870-72-4 X 8

Sodium hypochlorite 7681-52-9 1, 2, 3, 4, 8

Sodium iodide 7681-82-5 X 4

Sodium ligninsulfonate 8061-51-6 2

Sodium l-lactate 867-56-1 X 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-54

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Sodium maleate (1:x) 18016-19-8 X 8

Sodium metabisulfite 7681-57-4 X 1

Sodium metaborate 7775-19-1 3, 4

Sodium metaborate dihydrate 16800-11-6 1, 4

Sodium metaborate tetrahydrated 10555-76-7 1, 4, 8

Sodium metasilicate 6834-92-0 1, 2, 4

Sodium molybdate(VI) 7631-95-0 8

Sodium nitrate 7631-99-4 2

Sodium nitrite 7632-00-0 1, 2, 4

Sodium N-methyl-N-oleoyltaurate 137-20-2 X 4

Sodium octyl sulfate 142-31-4 X 1

Sodium oxide 1313-59-3 1

Sodium perborate 11138-47-9 4

Sodium perborate tetrahydrate 10486-00-7 1, 4, 5, 8

Sodium peroxoborate 7632-04-4 1

Sodium persulfate 7775-27-1 1, 2, 3, 4, 7, 8

Sodium phosphate 7632-05-5 1, 4

Sodium polyacrylate 9003-04-7 1, 2, 3, 4

Sodium pyrophosphate 7758-16-9 X 1, 2, 4

Sodium salicylate 54-21-7 X 1, 4

Sodium sesquicarbonate 533-96-0 X 1, 2

Sodium silicate 1344-09-8 1, 2, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-55

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Sodium starch glycolate 9063-38-1 2

Sodium sulfate 7757-82-6 1, 2, 3, 4

Sodium sulfite 7757-83-7 X 2, 4, 8

Sodium thiocyanate 540-72-7 X 1, 4

Sodium thiosulfate 7772-98-7 1, 2, 3, 4

Sodium thiosulfate, pentahydrate 10102-17-7 1, 4

Sodium trichloroacetate 650-51-1 X 1, 4

Sodium trimetaphosphate 7785-84-4 X 8

Sodium xylenesulfonate 1300-72-7 X 1, 3, 4

Sodium zirconium lactate 15529-67-6 8

Sodium zirconium lactic acid (4:4:1) 10377-98-7 1, 4

Solvent naphtha, petroleum, heavy aliph. 64742-96-7 2, 4, 8

Solvent naphtha, petroleum, heavy arom. 64742-94-5 1, 2, 4, 5, 8

Solvent naphtha, petroleum, light aliph. 64742-89-8 8

Solvent naphtha, petroleum, light arom. 64742-95-6 1, 2, 4

Sorbic acid 110-44-1 X 8

Sorbitan sesquioleate 8007-43-0 X 4

Sorbitan, mono-(9Z)-9-octadecenoate 1338-43-8 X 1, 2, 3, 4

Sorbitan, monooctadecanoate 1338-41-6 X 8

Sorbitan, tri-(9Z)-9-octadecenoate 26266-58-0 X 8

Spirit of ammonia, aromatic 8013-59-0 8

Stannous chloride dihydrate 10025-69-1 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-56

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Starch 9005-25-8 1, 2, 4

Steam cracked distillate, cyclodiene dimer, dicyclopentadiene polymer 68131-87-3 1

Stoddard solvent 8052-41-3 X 1, 3, 4

Stoddard solvent IIC 64742-88-7 1, 2, 4

Strontium chloride 10476-85-4 X 4

Styrene 100-42-5 X X 2

Subtilisin 9014-01-1 8

Sucrose 57-50-1 X 1, 2, 3, 4

Sulfamic acid 5329-14-6 1, 4

Sulfan blue 129-17-9 X X 8

Sulfate 14808-79-8 X 1, 4

Sulfo NHS Biotin 119616-38-5 8

Sulfomethylated quebracho 68201-64-9 2

Sulfonic acids, C10-16-alkane, sodium salts 68608-21-9 6

Sulfonic acids, petroleum 61789-85-3 1

Sulfonic acids, petroleum, sodium salts 68608-26-4 3

Sulfur dioxide 7446-09-5 X 2, 4, 8

Sulfuric acid 7664-93-9 X 1, 2, 4, 7

Sulfuric acid, mono-C12-18-alkyl esters, sodium salts 68955-19-1 X 4

Sulfuric acid, mono-C6-10-alkyl esters, ammonium salts 68187-17-7 X 1, 4, 8

Symclosene 87-90-1 X 2

Talc 14807-96-6 X 1, 3, 4, 6, 7
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-57

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Tall oil 8002-26-4 4, 8

Tall oil imidazoline 61791-36-4 4

Tall oil, compound with diethanolamine 68092-28-4 1

Tall oil, ethoxylated 65071-95-6 4, 8

Tall-oil pitch 8016-81-7 4

Tallow alkyl amines acetate 61790-60-1 8

Tar bases, quinoline derivatives, benzyl chloride-quaternized 72480-70-7 1, 3, 4

Tegin M 8043-29-6 8

Terpenes and Terpenoids, sweet orange-oil 68647-72-3 1, 3, 4, 8

Terpineol 8000-41-7 1, 3

tert-Butyl hydroperoxide 75-91-2 X 1, 4

tert-Butyl perbenzoate 614-45-9 X 1

Tetra-calcium-alumino-ferrite 12068-35-8 1, 2, 4

Tetradecane 629-59-4 X X 8

Tetradecyldimethylbenzylammonium chloride 139-08-2 X 1, 4, 8

Tetraethylene glycol 112-60-7 X 1, 4

Tetraethylenepentamine 112-57-2 X 1, 4

Tetrakis(hydroxymethyl)phosphonium sulfate 55566-30-8 X 1, 2, 3, 4, 7

Tetramethyl orthosilicate 681-84-5 1

Tetramethylammonium chloride 75-57-0 X 1, 2, 3, 4, 7, 8

Tetrasodium pyrophosphate 7722-88-5 X 8

Thiamine hydrochloride 67-03-8 X 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-58

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Thiocyanic acid, ammonium salt 1762-95-4 X 2, 3, 4

Thioglycolic acid 68-11-1 X 1, 2, 3, 4

Thiourea 62-56-6 X X 1, 2, 3, 4, 6

Thiourea, polymer with formaldehyde and 1-phenylethanone 68527-49-1 1, 4, 8

Thuja plicata donn ex. D. don leaf oil 68917-35-1 3

Tin(II) chloride 7772-99-8 1

Titanium dioxided 13463-67-7 X 1, 2, 4, 8

Titanium(4+) 2-[bis(2-hydroxyethyl)amino]ethanolate propan-2-olate 

(1:2:2) 36673-16-2 1

Titanium, isopropoxy (triethanolaminate) 74665-17-1 1, 4

Toluene 108-88-3 X X X 1, 3, 4

Tributyl phosphate 126-73-8 X X X 1, 2, 4

Tributyltetradecylphosphonium chloride 81741-28-8 X 1, 3, 4

Tricalcium phosphate 7758-87-4 X 1, 4

Tricalcium silicate 12168-85-3 1, 2, 4

Tridecane 629-50-5 X X 8

Triethanolamine 102-71-6 X X 1, 2, 4

Triethanolamine hydrochloride 637-39-8 X 8

Triethanolamine hydroxyacetate 68299-02-5 X 3

Triethanolamine polyphosphate ester 68131-71-5 1, 4, 8

Triethyl citrate 77-93-0 X 1, 4

Triethyl phosphate 78-40-0 X 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-59

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Triethylene glycol 112-27-6 X 1, 2, 3

Triethylenetetramine 112-24-3 X 4

Triisopropanolamine 122-20-3 X 1, 4

Trimethanolamine 14002-32-5 X 3

Trimethyl borate 121-43-7 8

Trimethylamine 75-50-3 X 8

Trimethylamine quaternized polyepichlorohydrin 51838-31-4 1, 2, 3, 4, 5, 8

Trimethylbenzene 25551-13-7 X X 1, 2, 4

Triphosphoric acid, pentasodium salt 7758-29-4 X 1, 4

Tripoli 1317-95-9 4

Tripotassium citrate monohydrate 6100-05-6 X 4

Tripropylene glycol monomethyl ether 25498-49-1 X 2

Trisodium citrate 68-04-2 X 3

Trisodium citrate dihydrate 6132-04-3 X 1, 4

Trisodium ethylenediaminetetraacetate 150-38-9 X 1, 3

Trisodium ethylenediaminetriacetate 19019-43-3 X 1, 4, 8

Trisodium phosphate 7601-54-9 X 1, 2, 4

Trisodium phosphate dodecahydrate 10101-89-0 1

Tritan R (X-100) 92046-34-9 8

Triton X-100 9002-93-1 1, 3, 4

Tromethamine 77-86-1 X 3, 4

Tryptone 73049-73-7 8
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-60

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Ulexite 1319-33-1 1, 2, 3, 8

Undecane 1120-21-4 X X 3, 8

Undecanol, branched and linear 128973-77-3 8

Urea 57-13-6 X 1, 2, 4, 8

Vermiculite 1318-00-9 2

Vinyl acetate ethylene copolymer 24937-78-8 1, 4

Vinylidene chloride/methylacrylate copolymer 25038-72-6 4

Water 7732-18-5 2, 4, 8

White mineral oil, petroleum 8042-47-5 1, 2, 4

Xylenes 1330-20-7 X X X 1, 2, 4

Yeast extract 8013-01-2 8

Zeolites 1318-02-1 X 8

Zinc 7440-66-6 X X 2

Zinc carbonate 3486-35-9 2

Zinc chloride 7646-85-7 1, 2

Zinc oxide 1314-13-2 1, 4

Zinc sulfate monohydrate 7446-19-7 8

Zirconium nitrate 13746-89-9 2, 6

Zirconium oxide sulfate 62010-10-0 1, 4

Zirconium oxychloride 7699-43-6 1, 2, 4

Zirconium(IV) chloride tetrahydrofuran complex 21959-01-3 5

Zirconium(IV) sulfate 14644-61-2 2, 6
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-61

Chemical namea CASRNb

Known 

constituent of 

produced water

Physicochemical 

properties

Selected 

toxicity 

datac Reference

Zirconium, 1,1'-((2-((2-hydroxyethyl)(2-

hydroxypropyl)amino)ethyl)imino)bis(2-propanol) complexes 197980-53-3 4

Zirconium, acetate lactate oxo ammonium complexes 68909-34-2 4, 8

Zirconium, chloro hydroxy lactate oxo sodium complexes 174206-15-6 4

Zirconium, hydroxylactate sodium complexes 113184-20-6 1, 4

Zirconium,tetrakis[2-[bis(2-hydroxyethyl)amino-kN]ethanolato-kO]- 101033-44-7 1, 2, 4, 5

a DSSTox chemical names assigned to the listed CASRN can be reformatted or change over time with additional curation review. In the case that a chemical name in this table no 

longer matches the DSSTox chemical name for a listed CASRN, the CASRN would be presumed to be the invariant identifier.

b Some chemicals are designated as “NOCAS_” which are DSSTox database-specific CAS-like identifiers assigned to a listed chemical name or substance.

c Chemicals are flagged as having selected toxicity data available if they have one or more oral reference values, oral slope factors, or qualitative cancer classifications available 

from the sources presented in Appendix G.

d Four chemicals have data in the EPA’s FracFocus 1.0 project database for CASRNs that are different from those in this table: Ethanolamine, CASRN 9007-33-4; Sodium 

metaborate tetrahydrate, CASRN 35585-58-1; Boric acid (H3BO3), compd. with 2-aminoethanol (1:x), CASRN 68425-67-2; and Titanium dioxide, CASRN 98084-96-9. Three of 

these (9007-33-4, 68425-67-2, and 98084-96-9) are “deleted” CASRNs, and so were not included in this table; instead, the chemical name has been remapped here to the 

current “active” CASRNs. CASRN 35585-58-1 is listed for sodium metaborate tetrahydrate in the EPA’s FracFocus 1.0 project database, but is assigned to a different chemical 

(disodium dioxoborate) in the EPA’s Distributed Structure-Searchable Toxicity (DSSTox) Database, and so was not included in this table.
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-62

Table H-3. List of generic names of chemicals reportedly used in hydraulic fracturing fluids. 

In some cases, the generic chemical name masks a specific chemical name and CASRN provided to the EPA and 

claimed as CBI by one or more of the nine hydraulic fracturing service companies. 

Generic chemical name Reference

2-Substituted aromatic amine salt 1, 4

Acetylenic alcohol 1

Acrylamide acrylate copolymer 4

Acrylamide copolymer 1, 4

Acrylamide modified polymer 4

Acrylamide-sodium acrylate copolymer 4

Acrylate copolymer 1

Acrylic copolymer 1

Acrylic polymer 1, 4

Acrylic resin 4

Acyclic hydrocarbon blend 1, 4

Acylbenzylpyridinium choride 8

Alcohol alkoxylate 1, 4

Alcohol and fatty acid blend 2

Alcohol ethoxylates 4

Alcohols 1, 4

Alcohols, C9-C22 1, 4

Aldehydes 1, 4, 5

Alfa-alumina 1, 4

Aliphatic acids 1, 2, 3, 4

Aliphatic alcohol 2

Aliphatic alcohol glycol ether 3, 4

Aliphatic alcohols, ethoxylated 2

Aliphatic amine derivative 1

Aliphatic carboxylic acid 4

Alkaline bromide salts 1, 4

Alkaline metal oxide 4

Alkanes/alkenes 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-63

Generic chemical name Reference

Alkanolamine derivative 2

Alkanolamine/aldehyde condensate 1, 2, 4

Alkenes 1, 4

Alklaryl sulfonic acid 1, 4

Alkoxylated alcohols 1

Alkoxylated amines 1, 4

Alkyaryl sulfonate 1, 2, 3, 4

Alkyl alkoxylate 1, 4

Alkyl amide 4

Alkyl amine 1, 4

Alkyl amine blend in a metal salt solution 1, 4

Alkyl aryl amine sulfonate 4

Alkyl aryl polyethoxy ethanol 3, 4

Alkyl dimethyl benzyl ammonium chloride 4

Alkyl esters 1, 4

Alkyl ether phosphate 4

Alkyl hexanol 1, 4

Alkyl ortho phosphate ester 1, 4

Alkyl phosphate ester 1, 4

Alkyl phosphonate 4

Alkyl pyridines 2

Alkyl quaternary ammonium chlorides 1, 4

Alkyl quaternary ammonium salt 4

Alkylamine alkylaryl sulfonate 4

Alkylamine salts 2

Alkylaryl sulfonate 1, 4

Alkylated quaternary chloride 1, 2, 4

Alkylated sodium naphthalenesulphonate 2

Alkylbenzenesulfonate 2

Alkylbenzenesulfonic acid 1, 4, 5
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-64

Generic chemical name Reference

Alkylethoammonium sulfates 1

Alkylphenol ethoxylates 1, 4

Alkylpyridinium quaternary 4

Alphatic alcohol polyglycol ether 2

Aluminum oxide 1, 4

Amide 4

Amidoamine 1, 4

Amine 1, 4

Amine compound 4

Amine oxides 1, 4

Amine phosphonate 1, 4

Amine salt 1

Amino compounds 1, 4

Amino methylene phosphonic acid salt 1, 4

Ammonium alcohol ether sulfate 1, 4

Ammonium salt 1, 4

Ammonium salt of ethoxylated alcohol sulfate 1, 4

Amorphous silica 4

Amphoteric surfactant 2

Anionic acrylic polymer 2

Anionic copolymer 1, 4

Anionic polyacrylamide 1, 2, 4

Anionic polyacrylamide copolymer 1, 4, 6

Anionic polymer 1, 3, 4

Anionic surfactants 2, 4, 6

Antifoulant 1, 4

Antimonate salt 1, 4

Aqueous emulsion of diethylpolysiloxane 2

Aromatic alcohol glycol ether 1

Aromatic aldehyde 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-65

Generic chemical name Reference

Aromatic hydrocarbons 3, 4

Aromatic ketones 1, 2, 3, 4

Aromatic polyglycol ether 1

Arsenic compounds 4

Ashes, residues 4

Bentone clay 4

Biocide 4

Biocide component 1, 4

Bis-quaternary methacrylamide monomer 4

Blast furnace slag 4

Borate salts 1, 2, 4

Cadmium compounds 4

Carbohydrates 1, 2, 4

Carboxylmethyl hydroxypropyl guar 4

Cationic polyacrylamide 4

Cationic polymer 2, 4

Cedar fiber, processed 2

Cellulase enzyme 1

Cellulose derivative 1, 2, 4

Cellulose ether 2

Cellulosic polymer 2

Ceramic 4

Chlorous ion solution 1

Chromates 1, 4

Chrome-free lignosulfonate compound 2

Citrus rutaceae extract 4

Common white 4

Complex alkylaryl polyo-ester 1

Complex aluminum salt 1, 4

Complex carbohydrate 2
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-66

Generic chemical name Reference

Complex organometallic salt 1

Complex polyamine salt 7

Complex substituted keto-amine 1

Complex substituted keto-amine hydrochloride 1

Copper compounds 6

Coric oxide 4

Cotton dust (raw) 2

Cottonseed hulls 2

Cured acrylic resin 1, 4

Cured resin 1, 4, 5

Cured urethane resin 1, 4

Cyclic alkanes 1, 4

Defoamer 4

Dibasic ester 4

Dicarboxylic acid 1, 4

Diesel 1, 4, 6

Dimethyl silicone 1, 4

Dispersing agent 1

Emulsifier 4

Enzyme 4

Epoxy 4

Epoxy resin 1, 4

Essential oils 1, 4

Ester Salt 2, 4

Esters 2, 4

Ether compound 4

Ether salt 4

Ethoxylated alcohol blend 4

Ethoxylated alcohol/ester mixture 4

Ethoxylated alcohols 1, 2, 4, 5, 7
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-67

Generic chemical name Reference

Ethoxylated alkyl amines 1, 4

Ethoxylated amine blend 4

Ethoxylated amines 1, 4

Ethoxylated fatty acid 4

Ethoxylated fatty acid ester 1, 4

Ethoxylated nonionic surfactant 1, 4

Ethoxylated nonylphenol 1, 2, 4

Ethoxylated sorbitol esters 1, 4

Ethylene oxide-nonylphenol polymer 4

Fatty acid amine salt mixture 4

Fatty acid ester 1, 2, 4

Fatty acid tall oil 1, 4

Fatty acid, ethoxylate 4

Fatty acids 1

Fatty alcohol alkoxylate 1, 4

Fatty alkyl amine salt 1, 4

Fatty amine carboxylates 1, 4

Fatty imidazoline 4

Fluoroaliphatic polymeric esters 1, 4

Formaldehyde polymer 1

Glass fiber 1, 4

Glyceride esters 2

Glycol 4

Glycol blend 2

Glycol ethers 1, 4, 7

Ground cedar 2

Ground paper 2

Guar derivative 1, 4

Guar gum 4

Haloalkyl heteropolycycle salt 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-68

Generic chemical name Reference

Hexanes 1

High molecular weight polymer 2

High pH conventional enzymes 2

Hydrocarbons 1

Hydrogen solvent 4

Hydrotreated and hydrocracked base oil 1, 4

Hydrotreated distillate, light C9-16 4

Hydrotreated heavy naphthalene 5

Hydrotreated light distillate 2, 4

Hydrotreated light petroleum distillate 4

Hydroxyalkyl imino carboxylic sodium salt 2

Hydroxycellulose 6

Hydroxyethyl cellulose 1, 2, 4

Imidazolium compound 4

Inner salt of alkyl amines 1, 4

Inorganic borate 1, 4

Inorganic chemical 4

Inorganic particulate 1, 4

Inorganic salt 2, 4

Iso-alkanes/n-alkanes 1, 4

Isomeric aromatic ammonium salt 1, 4

Latex 2, 4

Lead compounds 4

Low toxicity base oils 1, 4

Lubra-Beads course 4

Maghemite 1, 4

Magnetite 1, 4

Metal salt 1

Metal salt solution 1

Mineral 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-69

Generic chemical name Reference

Mineral fiber 2

Mineral filler 1

Mineral oil 4

Mixed titanium ortho ester complexes 1, 4

Modified acrylamide copolymer 2, 4

Modified acrylate polymer 4

Modified alkane 1, 4

Modified bentonite 4

Modified cycloaliphatic amine adduct 1, 4

Modified lignosulfonate 2, 4

Naphthalene derivatives 1, 4

Neutralized alkylated napthalene sulfonate 4

Nickel chelate catalyst 4

Nonionic surfactant 1

N-tallowalkyltrimethylenediamines 4

Nuisance particulates 1, 2, 4

Nylon 4

Olefinic sulfonate 1, 4

Olefins 1, 4

Organic acid salt 1, 4

Organic acids 1, 4

Organic alkyl amines 4

Organic chloride 4

Organic modified bentonite clay 4

Organic phosphonate 1, 4

Organic phosphonate salts 1, 4

Organic phosphonic acid salts 1, 4

Organic polymer 4

Organic polyol 4

Organic salt 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-70

Generic chemical name Reference

Organic sulfur compound 1, 4

Organic surfactants 1

Organic titanate 1, 4

Organo amino silane 4

Organo phosphonic acid 4

Organo phosphonic acid salt 4

Organometallic ammonium complex 1

Organophilic clay 4

Oxidized tall oil 2

Oxoaliphatic acid 2

Oxyalkylated alcohol 1, 4

Oxyalkylated alkyl alcohol 2, 4

Oxyalkylated alkylphenol 1, 2, 3, 4

Oxyalkylated fatty acid 1, 4

Oxyalkylated fatty alcohol salt 2

Oxyalkylated phenol 1, 4

Oxyalkylated phenolic resin 4

Oxyalkylated polyamine 1

Oxyalkylated tallow diamine 2

Oxyethylated alcohol 2

Oxylated alcohol 1, 4

P/F resin 4

Paraffin inhibitor 4

Paraffinic naphthenic solvent 1

Paraffinic solvent 1, 4

Paraffins 1

Pecan shell 2

Petroleum distallate blend 2, 3, 4

Petroleum gas oils 1

Petroleum hydrocarbons 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-71

Generic chemical name Reference

Petroleum solvent 2

Phosphate ester 1, 4

Phosphonate 2

Phosphonic acid 1, 4

Phosphoric acid, mixed polyoxyalkylene aryl and alkyl esters 4

Plasticizer 1, 2

Polyacrylamide copolymer 4

Polyacrylamides 1

Polyacrylate 1, 4

Polyactide resin 4

Polyalkylene esters 4

Polyaminated fatty acid 2

Polyaminated fatty acid surfactants 2

Polyamine 1, 4

Polyamine polymer 4

Polyanionic cellulose 1

Polyaromatic hydrocarbons 6

Polycyclic organic matter 6

Polyelectrolyte 4

Polyether polyol 2

Polyethoxylated alkanol 2, 3, 4

Polyethylene copolymer 4

Polyethylene glycols 4

Polyethylene wax 4

Polyglycerols 2

Polyglycol 2

Polyglycol ether 6

Polylactide resin 4

Polymer 2, 4

Polymeric hydrocarbons 3, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-72

Generic chemical name Reference

Polymerized alcohol 4

Polymethacrylate polymer 4

Polyol phosphate ester 2

Polyoxyalkylene phosphate 2

Polyoxyalkylene sulfate 2

Polyoxyalkylenes 1, 4, 7

Polyphenylene ether 4

Polyphosphate 4

Polypropylene glycols 2

Polyquaternary amine 4

Polysaccaride polymers in suspension 2

Polysaccharide 4

Polysaccharide blend 4

Polyvinylalcohol/polyvinylactetate copolymer 4

Potassium chloride substitute 4

Quarternized heterocyclic amines 4

Quaternary amine 2, 4

Quaternary amine salt 4

Quaternary ammonium chloride 4

Quaternary ammonium compound 1, 2, 4

Quaternary ammonium salts 1, 2, 4

Quaternary compound 1, 4

Quaternary salt 1, 4

Quaternized alkyl nitrogenated compd 4

Red dye 4

Refined mineral oil 2

Resin 4

Salt of amine-carbonyl condensate 3, 4

Salt of fatty acid/polyamine reaction product 3, 4

Salt of phosphate ester 1
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-73

Generic chemical name Reference

Salt of phosphono-methylated diamine 1, 4

Salts 4

Salts of oxyalkylated fatty amines 4

Sand 4

Sand, AZ silica 4

Sand, brown 4

Sand, sacked 4

Sand, white 4

Secondary alcohol 1, 4

Silica sand, 100 mesh, sacked 4

Silicone emulsion 1

Silicone ester 4

Sodium acid pyrophosphate 4

Sodium calcium magnesium polyphosphate 4

Sodium phosphate 4

Sodium salt of aliphatic amine acid 2

Sodium xylene sulfonate 4

Softwood dust 2

Starch blends 6

Substituted alcohol 1, 2, 4

Substituted alkene 1

Substituted alklyamine 1, 4

Substituted alkyne 4

Sulfate 4

Sulfomethylated tannin 2, 5

Sulfonate 4

Sulfonate acids 1

Sulfonate surfactants 1

Sulfonated asphalt 2

Sulfonic acid salts 1, 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-74

Generic chemical name Reference

Sulfur compound 1, 4

Sulphonic amphoterics 4

Sulphonic amphoterics blend 4

Surfactant blend 3, 4

Surfactants 1, 2, 4

Synthetic copolymer 2

Synthetic polymer 4

Tallow soap 4

Telomer 4

Terpenes 1, 4

Titanium complex 4

Triethanolamine zirconium chelate 1 4

Triterpanes 4

Vanadium compounds 4

Wall material 1

Walnut hulls 1, 2, 4

Zirconium complex 2, 4

Zirconium salt 4
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-75

Table H-4. Chemicals detected in produced water. 

An “X” indicates the availability of physicochemical properties from EPI SuiteTM (Appendix C) and selected toxicity data (Appendix G). An empty cell indicates no 

information was available from the sources we consulted. Reference number corresponds to the citation in Table H-1. Formation type indicated by: “S” (shale), 

“C” (coalbed), or “U” (uncertain). This refers both to unknown formation types and chemicals in produced water that occur in other types of formations not 

specified. 

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

2,6-di(tert-butyl)-4-hydroxy-4-methyl2,5-cyclohexadien-1-on

10396-80-2 X Name C 21

(1,3-Dimethylbutyl)cyclohexane 61142-19-6 X Name S 18

(1-Butylheptyl)cyclohexane 13151-80-9 X Name S 18

(1-Methoxyethyl)-benzene 4013-34-7 Name S,C 21

(1-Methyl-1-buten-1-yl)benzene 53172-84-2 X Name S 18

(1-Pentyloctyl)cyclohexane 13151-91-2 X Name S 18

(1-Propylnonyl)cyclohexane 13151-84-3 X Name S 18

(3E)-3-Heptene 14686-14-7 X Name S 18

(3R)-3,7-Dimethyloct-6-enal 2385-77-5 X Name S 18

(4Z)-2-Methyl-4-tetradecene 866760-27-2 X Name S 18

(9E)-8-Methyl-9-tetradecen-1-yl 

acetate

912629-93-7 X Name S 18

(E)-5-Decene 7433-56-9 X S 18

(E)-5-Methylspiro[3,5]nonan-1-one 65147-56-0 X

Name; 

CASRN S 18

(Z)-1,2-Dimethylcyclohexane 2207-01-4 X S 18

(Z)-1,2-Dimethylcyclopentane 1192-18-3 X Name S 18

(Z)-1,3-Dimethylcyclohexane 638-04-0 X Name S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-76

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

(Z)-1-Ethyl-2-methylcyclopentane 930-89-2 X Name S 18

(Z)-1-Ethyl-3-methylcyclohexane 19489-10-2 X Name S 18

(Z)-5-Octen-1-ol 64275-73-6 X Name S 18

(Z)-9-Methylundec-4-ene 74630-56-1 X Name S 18

(Z)-9-Tricosene 27519-02-4 X C 18, 20

1-Heptadecene 6765-39-5 X S 18

1-(1,5-Dimethylhexyl)-4-(4-

methylpentyl)cyclohexane 56009-20-2 X Name S 18

1-(2,4-Dimethylphenyl)ethanone 89-74-7 X Name S 16

1-(2-Furanyl)-3-butene-1,2-diol 19261-13-3 X Name S 16

1-(3-Methylbutyl)-2,3,4-trimethylbenzene 107997-59-1 X Name C 21

1-(Butan-2-yl)-4-methylbenzene 1595-16-0 X Name S 18

1-(Cyclohexylmethyl)-4-

methylcyclohexane 66826-95-7 X S 18

1-(Pentyloxy)hexane 32357-83-8 X Name S 18

1,8,10-Pentadecatriene 1227308-82-8 X S 18

1,1,3,5-Tetramethylcyclohexane 4306-65-4 X S 18

1,1,3-Trimethylcyclohexane 3073-66-3 X Name S 18

1,1,3-Trimethylcyclopentane 4516-69-2 X Name S 18

1,12-Dibromododecane 3344-70-5 X S 18

1,1-Dichloroethane 75-34-3 X X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-77

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

1,1-Dimethyl-1,2,3,4-tetrahydro-7-

isopropyl phenanthrene 27530-79-6 X Name C 20

1,1-Dimethylcyclohexane 590-66-9 X S 18

1,1-Dimethylcyclopropane 1630-94-0 X S 18

1,1'-Methylenebis(4-methyl)-benzene 4957-14-6 X Name C 20

1,1'-Oxybisdecane 2456-28-2 X S 18

1,2,3,4-Tetrahydro-2,5,7-

trimethylnaphthalene 65001-61-8 X S 18

1,2,3,4-Tetrahydro-2,5,8-

trimethylnaphthalene 30316-17-7 X S 18

1,2,3,4-Tetrahydro-naphthalene 119-64-2 X Name S,C 21

1,2,3,4-Tetramethylcyclohexane 3726-45-2 X S 18

1,2,3,4-Tetramethylnaphthalene 3031-15-0 X S 18

1,2,3-Trichlorobenzene 87-61-6 X X S 3, 9

1,2,3-Trimethylbenzene 526-73-8 X X X S 18

1,2,3-Trimethylcyclopentane 2815-57-8 X S 18

1,2,4,5-Tetramethylbenzene 95-93-2 X Name S 18

1,2,4-Trichlorobenzene 120-82-1 X X S 9

1,2,4-Trimethylbenzene 95-63-6 X X X S,C 3, 9, 10, 13, 15, 18, 

22

1,2,4-Trimethylcyclohexane 2234-75-5 X S 18

1,2,4-Trimethylcyclopentane 2815-58-9 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-78

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

1,2-Benzenedicarboxylic acid, 1,2-

bis(8-methylnonyl) ester 89-16-7 X X Name S 18

1,2-Benzenedicarboxylic acid, 1-butyl 

2-(8-methylnonyl) ester 42343-36-2 X Name S 18

1,2-Di-but-2-enyl-cyclohexane NOCAS_873054 X C 20

1,2-Dimethyl-1-cycloheptene 20053-89-8 X Name S 18

1,2-Dimethyl-4-ethylbenzene 934-80-5 X Name S 18

1,2-Diphenylhydrazine 122-66-7 X X S 15

1,2-Epoxydodecane 2855-19-8 X Name S 18

1,2-Epoxyhexadecane 7320-37-8 X Name S 18

1,2-Propylene glycol 57-55-6 X X X S 3, 9, 22

1,3,5-Trimethylbenzene 108-67-8 X X X Name S,C 3, 9, 10, 13, 15, 18, 

22

1,3,5-Trimethylcyclohexane 1839-63-0 X S 18

1,3-Dimethyl-4-ethylbenzene 874-41-9 X Name S,C 18, 21

1,3-Dimethyladamantane 702-79-4 X Name C 13

1,3-Dimethylcyclohexane 591-21-9 X S 18

1,3-Dimethylcyclopentane 2453-00-1 X S 18

1,4,5,8-Tetramethylnaphthalene 2717-39-7 X S 16

1,4,5-Trimethylnaphthalene 2131-41-1 X S 18

1,4,6-Trimethylnaphthalene 2131-42-2 X S 18

1,4-Dihydro-1,4-methanonaphthalene 4453-90-1 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-79

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

1,4-Dimethyl-2,3-

diazabicyclo[2.2.1]hept-2-ene

71312-54-4 X Name S 16

1,4-Dimethylcyclohexane 589-90-2 X S 18

1,4-Dimethylnaphthalene 571-58-4 X S 18

1,4-Dioxane 123-91-1 X X X S 9, 10, 15

1,4-Hexadecansultone 15224-88-1 X Name S 18

1,5,7-Trimethyl-1,2,3,4-

tetrahydronaphthalene 21693-55-0 X Name S 18

1,54-Dibromotetrapentacontane 852228-22-9 X S 18

1,5-Dimethyl-7-

oxabicyclo[4.1.0]heptane 162239-52-3 X S 18

1,5-Dimethylnaphthalene 571-61-9 X S 18

1,6-Dimethyl-4(1-

methylethyl)naphthalene 483-78-3 X Name C 20

1,6-Dimethylnaphthalene 575-43-9 X S 18

10-Pentadecen-1-ol 129396-62-9 X S 18

10,4-Dihydroxy-70-methoxy-2,30-

dimethyl-,()-[1,20-binaphthalene]-

5,50,8,80-tetrone

119736-96-8 X Name S 18

10-Methylicosane 54833-23-7 X Name S 18

10-Methylnonadecane 56862-62-5 X S 18

11-(1-Ethylpropyl)-heneicosane 55282-11-6 X Name S 18

11,13-Dimethyl-12-tetradecen-1-yl 

acetate

400037-00-5 X Name S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-80

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

13-Tetradecen-1-ol 67400-04-8 X S 18

13-Tetradecen-1-yl acetate 56221-91-1 X Name S 18

14-Bromo-1-tetradecene 74646-31-4 X S 18

14-Methylhexadecanal 93815-50-0 X S 18

15-Isobutyl-(13.α.H)-isocopalane 228729-94-0 X Name C 20

17-Methylpentatriacontane 56987-83-8 X S 18

1a,9b-Dihydro-1Hcyclopropa[l]phenanthrene 949-41-7 X Name S 18

1-Allyl-3-methylindole-2-carbaldehyde 123731-75-9 X Name C 20

1-Bromo-11-iodoundecane 139123-69-6 X S 18

1-Bromohexadecane 112-82-3 X S 18

1-Bromooctadecane 112-89-0 X S 18

1-Bromopentadecane 629-72-1 X S 18

1-Butanol 71-36-3 X X X Name S 22

1-Butyl-2-ethyloctahydro-1H-4,7-

epoxyinden-5-ol 62583-58-8 X Name C 20

1-Butyl-2-pentylcyclopentane 61142-52-7 X S 18

1-Chloro-Heptacosane 62016-79-9 X Name S 18

1-Chlorohexadecane 4860-03-1 X S 18

1-Decene 872-05-9 X S 18

1-Docosanethiol 7773-83-3 X S 18

1-Dodecene 112-41-4 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-81

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

1-Dotriacontanol 6624-79-9 X S 18

1-Ethyl-2,3-dimethylbenzene 933-98-2 X S 18

1-Ethyl-2-methylbenzene 611-14-3 X X S 18

1-Ethyl-2-methylcyclohexane 3728-54-9 X S 18

1-Ethyl-2-methylcyclopentane 3726-46-3 X S 18

1-Ethyl-3-methylcyclohexane 3728-55-0 X S 18

1-Ethyl-4-methylcyclohexane 3728-56-1 X S 18

1-Ethyl-9,10-anthracenedione 24624-29-1 X Name C 20

1-Ethylidene-1H-indene 2471-83-2 X S 18

1-Fluorododecane 334-68-9 X S 18

1-Hentetracontanol 40710-42-7 X S 18

1-Hexacosanol 506-52-5 X S 18

1-Hexacosene 18835-33-1 C 20

1-Hexadecene 629-73-2 X X S 18

1-Iodo-2-methylundecane 73105-67-6 X S 18

1-Isopropyl-2,3-dimethylcyclopentane 489-20-3 X Name S 18

1-Methyl-1,2-cyclohexanediol 6296-84-0 X S 18

1-Methyl-2-pentylcyclohexane 54411-01-7 X S 18

1-Methyl-3-(1-

methylethyl)cyclopentane 53771-88-3 X Name S 18

1-Methyl-3-propylbenzene 1074-43-7 X Name S 16
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-82

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

1-Methyl-7-(1-

methylethyl)phenanthrene 483-65-8 X Name C 20, 21

1-Methyl-7-oxabicyclo[4.1.0]heptane 1713-33-3 X S 18

1-Methylene-1H-indene 2471-84-3 X S 18

1-Methylfluorene 1730-37-6 X Name C 20

1-Methylnaphthalene 90-12-0 X X S,C 18, 21, 22

1-Naphthol 90-15-3 X S 22

1-Nonene 124-11-8 X S 18

1-Octadecanethiol 2885-00-9 X S 18

1-Octadecene 112-88-9 X X S 18

1-Oxopyridin-2-ylamine 14150-95-9 X Name S 18

1-Pentyl-2-propylcyclopentane 62199-51-3 X S 18

1-Propanol 71-23-8 X X S 22

1-Propoxyhexane 53685-78-2 X S 18

1-Propylcyclohexene 2539-75-5 X S 18

1-Tricosene 18835-32-0 X S 18

1-Tridecene 2437-56-1 X S 18

2-(2-Buten-1-yl)-1,3,5-

trimethylbenzene 63435-25-6 X S 18

2-(2-Butoxyethoxy)ethanol 112-34-5 X X X S,C 21

2(3H)-Benzothiazolone 934-34-9 X C 20, 21

2-(Methylthio)-benzothiazole 615-22-5 X Name C 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-83

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

2,10-Dimethylundecane 17301-27-8 X S 18

2,2,3,3-Tetramethylhexane 13475-81-5 X S 18

2,2,4-trimethyl-1,3-pentanediol 144-19-4 X S,C 21

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 X X S 11

2,2-Dichloro-3,6-dimethyl-1-oxa-2-

silacyclohexa-3,5-diene 69586-09-0 X S 18

2,3',5-Trimethyldiphenylmethane 61819-81-6 X C 20

2,3,6-Trimethylnaphthalene 829-26-5 X S 18

2,3-Dihydro-1,1,2,3,3-pentamethyl-1Hindene 1203-17-4 X C 20

2,3-Dimethyldecahydronaphthalene 1008-80-6 X Name S 18

2,3-Dimethyldecane 17312-44-6 X S 18

2,3-Dimethylheptane 3074-71-3 X S 18

2,3-Dimethylnaphthalene 581-40-8 X S 18

2,3-Dimethylundecane 17312-77-5 X S 18

2,3-Heptanedione 96-04-8 X Name S 16

2,4,6-Trimethyl-azulene NOCAS_873044 Name C 20

2,4-Bis(1,1-dimethylethyl)phenol 96-76-4 X Name C 21

2,4-Dichloro-5-oxohex-2-enedioic acid 56771-78-9 X Name S 18

2,4-Dichlorophenol 120-83-2 X X S 15

2,4-dimethyl-1-(1-methylpropyl)-

benzene 1483-60-9 Name C 21

2,4-Dimethylheptane 2213-23-2 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-84

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

2,4-Dimethylhexane 589-43-5 X S 18

2,4-Dimethylphenol 105-67-9 X X S,C 3, 9, 10, 13, 15

2,4-Dimethylundecane 17312-80-0 X S 18

2,5,9-Trimethyldecane 62108-22-9 X S 18

2,5-Cyclohexadiene-1,4-dione 106-51-4 X X Name C 20

2,5-Dimethyldodecane 56292-65-0 X S 18

2,6,10-Trimethyl-9-undecenoic acid 97993-62-9 X S 18

2,6,10-Trimethylpentadecane 3892-00-0 X S 18

2,6,10-Trimethylundec-9-enal 141-13-9 X Name S 18

2,6,10-Trimethylundecanoic acid 1115-94-2 X S 18

2,6,11-Trimethyldodecane 31295-56-4 X S 18

2,6-Bis(dimethylethyl)-2,5-

cyclohexadiene-1,4-dione 719-22-2 X Name C 20

2,6-Dichlorophenol 87-65-0 X S 3, 9

2,6-Dimethyldecane 13150-81-7 X S 18

2,6-Dimethylheptane 1072-05-5 X S 18

2,6-Dimethylnaphthalene 581-42-0 X S 18

2,6-Di-tert-butylphenol 128-39-2 X Name C 10, 14, 20

2,7-Dimethylnaphthalene 582-16-1 X S 18

2-[2-[4-(1,1,3,3-

tetramethylbutyl)phenoxy]ethoxy]-

ethanol

2315-61-9 X Name C 20, 21

22-Tricosenoic acid 65119-95-1 X C 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-85

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

28-Nor-17.α.(H)-hopane 204781-73-7 X Name C 20

2-Aminoimidazole 7720-39-0 X Name S 18

2-Butoxyethanol 111-76-2 X X X S 22

2-Butyloctan-1-ol 3913-02-8 X Name S 18

2-Chloroethanol 107-07-3 X X S 18

2-Dodecen-1-yl(-)succinic anhydride 25377-73-5 X Name C 20

2'-Dodecyl- 1,1':3',1''-tercyclopentane 55282-68-3 X Name S 18

2-Ethyl-1,1,3-trimethylcyclohexane 442662-72-8 X S 18

2-Ethyl-1-decanol 21078-65-9 X S 18

2-Ethyl-1-hexanol 104-76-7 X X S 22

2-Ethylhexyl diphenyl phosphate 

(Octicizer) 1241-94-7 X Name C 20

2-Hexyl-1-decanol 2425-77-6 X S 18

2-Hydroxy-2-methylbut-3-en-1-yl 2-

methylbut-2-enoate

1418543-90-4 X Name S 18

2-Hydroxy-4-(propan-2-yl)cyclopent-2-

en-1-one

54639-82-6 X Name S 18

2-Imino-5,6-dihydro-2Hcyclopenta[d][1,3]thiazol-3(4H)-ol 738528-09-1 X Name S 18

2-Mercaptobenzothiazole 149-30-4 X X C 20

2-Methoxyfuran 25414-22-6 X S 16

2-Methyl-2-butene 513-35-9 X S 18

2-Methyl-7-octadecene 51050-50-1 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-86

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

2-Methyl-8-propyl-dodecane 55045-07-3 X Name C 20

2-Methylbut-1-ene 563-46-2 X Name S 18

2-Methyldecane 6975-98-0 X S 18

2-Methyldodecan-1-ol 22663-61-2 X Name S 18

2-Methyldodecane 1560-97-0 X S 18

2-Methylheptane 592-27-8 X S 18

2-Methylnaphthalene 91-57-6 X X S,C 3, 9, 10, 13, 15, 16, 

18, 21, 22

2-Methyl-nonadecane 52845-07-5 X Name C 20

2-Methylnonane 871-83-0 X S 18

2-Methyl-N-phenyl-benzenamine 1205-39-6 X Name C 21

2-Methyloctane 3221-61-2 X S 18

2-Methylpentadecane 1560-93-6 X S 18

2-Methylpentane 107-83-5 X S 18

2-Methylphenanthrene 2531-84-2 X S 18

2-Methylpropanoic acid 79-31-2 X U 10

2-Methylpyridine 109-06-8 X S 3, 9

2-Methyltetradecane 1560-95-8 X S 18

2-Methyltridecane 1560-96-9 X S 18

2-Methylundecane 7045-71-8 X S 18

2-Naphthalenol 135-19-3 X Name S 22

2-Octadecyl-propane-1,3-diol 5337-61-1 X Name C 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-87

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

2-Octene 111-67-1 X S 18

2-Pentyl-2-nonenal 3021-89-4 X S 18

2-Phenylpentane 2719-52-0 X Name S 18

3-(4-Methoxyphenyl)-2-

ethylhexylester-2-propenoic acid 5466-77-3 X Name C 20

3-(4-Methoxyphenyl)-2-propenoic acid 830-09-1 Name C 20

3-(Hexahydro-1H-azepin-1-yl)-1,1-

dioxide-1,2-benzisothiazole 309735-29-3 X Name C 20

3,3,5,5-Tetramethylcyclopentene 38667-10-6 X Name S 18

3,3'-5,5'-Tetramethyl-[1,1'-biphenyl]-

4,4'-diamine 54827-17-7 X Name S,C 21

3,4-Dihydro-1,9(2H,10H)acridinedione 80061-31-0 X Name C 21

3,5,24-Trimethyltetracontane 55162-61-3 X S 18

3,5-Dimethyloctane 15869-93-9 X S 18

3,5-Di-tert-butyl-4-

hydroxybenzaldehyde 1620-98-0 X Name C 20

3,6-Dimethylundecane 17301-28-9 X S 18

3,7-Dimethyldecane 17312-54-8 X S 18

3,7-Dimethylnonane 17302-32-8 X S 18

3,7-Dimethyloct-7-enal 141-26-4 X Name S 18

3,7-Dimethylundecane 17301-29-0 X S 18

3,8-Dimethyldecane 17312-55-9 X S 18

3,9-Dimethylundecane 17301-31-4 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-88

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

3-Cyclohexylpropan-1-ol 1124-63-6 X Name S 18

3-Cyclopentyl-2-methylpropan-1-ol 264258-62-0 X Name S 18

3-Ethyl-2-methylheptane 14676-29-0 X S 18

3-Ethylhexane 619-99-8 X S 18

3-Ethyltoluene 620-14-4 X Name S 18

3-Methyl-1-heptene 4810-09-7 X S 18

3-Methyl-2-(2-oxopropyl)furan 87773-62-4 X Name S 18

3-Methyl-3-hexene 42154-69-8 X S 18

3-Methylcyclohexene 591-48-0 X S 16

3-Methylcyclopentadecan-1-one 541-91-3 X Name S 18

3-Methyldecane 13151-34-3 X S 18

3-Methyldodecane 17312-57-1 X S 18

3-Methylnonane 5911-04-6 X S 18

3-Methyloctane 2216-33-3 X S 18

4-(1,1,3,3-Tetramethylbutyl)phenol 140-66-9 X Name C 14, 21

4,4-Diacetyldiphenylmethane 790-82-9 X Name C 20

4,4-Dimethyl-2-(1-

methylethenyl)cyclopentanone 343270-53-1 X Name S 18

4,6,8-Trimethyl-2-propylazulene 160951-15-5 X C 20

4,6-Dimethyldodecane 61141-72-8 X S 18

4-[1-(2-Methylphenyl)ethyl]phenol 35770-76-4 X Name C 20

4-Decene 19398-89-1 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-89

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

4-Ethyl-2,3-dimethylhex-2-ene 959028-24-1 X Name S 18

4-Ethyl-5-octyl-2,2-

bis(trifluoromethyl)-1,3-dioxolane, cis38274-72-5 X Name S 18

4-Ethyloctane 15869-86-0 X S 18

4-Methyl-2-pentene 4461-48-7 X S 18

4-Methyl-2-phenyl-2-pentenal 26643-91-4 X Name S 18

4-Methyldecane 2847-72-5 X S 18

4-Methyldocosane 25117-30-0 X S 18

4-Methyldodec-3-en-1-ol 1372101-59-1 X Name S 18

4-Methylheptane 589-53-7 X S 18

4-Methylnonane 17301-94-9 X S 18

4-Methyloctane 2216-34-4 X S 18

4-Methyltetradecane 25117-24-2 X S 18

4-Methyltridecane 26730-12-1 X S 18

4-Methylundecane 2980-69-0 X S 18

4-Phenyl-1-buten-4-ol 936-58-3 X Name S 18

4-Propyl-3-heptene 4485-13-6 X S 18

4-Propylcyclohexanone 40649-36-3 X S 18

4-Propylheptane 3178-29-8 X S 18

4-Propyl-xanthen-9-one 108837-05-4 X Name C 20

5-(1,1-Dimethylethyl)-1H-indene NOCAS_873045 C 20

5-Butyl-6-hexyloctahydro-1H-indene 55044-36-5 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-90

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

5-Methyldecane 13151-35-4 X S 18

5-Methyltetradecane 25117-32-2 X S 18

5-Methyltridecane 25117-31-1 X S 18

6-Methyl-6-ethylfulvene 3141-02-4 X Name S 18

6-Methyltridecane 13287-21-3 X S 18

6-Methylundecane 17302-33-9 X S 18

7,12-Dimethylbenz(a)anthracene 57-97-6 X X S 3, 9

7-Bromomethyl-pentadec-7-ene 941228-34-8 X Name C 20

7-Ethenylphenanthrene 68593-94-2 X Name C 20

7-Methylpentadecane 6165-40-8 X S 18

7-Methyltridecane 26730-14-3 X S 18

7-Tetradecyne 35216-11-6 X C 20

8-Hexadecyne 19781-86-3 X C 20

8-Methylundec-3-ene 876314-66-8 X Name S 18

9-Hexacosene 71502-22-2 X S 18

9-Methylanthracene 779-02-2 X S 18

9-Methylnonadecane 13287-24-6 X S 18

Acetaldehyde 75-07-0 X X X S 22

Acetate 71-50-1 X S,C 11, 21

Acetic acid 64-19-7 X X S 3, 9, 10, 12

Acetone 67-64-1 X X X S 3, 9, 10, 15, 18

Acetophenone 98-86-2 X X X S,C 3, 9, 15, 21, 22
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-91

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Acetyl tributyl citrate 77-90-7 X Name S 18

Acrolein 107-02-8 X X X S 9

Acrylonitrile 107-13-1 X X S 3, 9

Adamantane 281-23-2 X C 13

Aldrin 309-00-2 X X S 3, 9

Alpha particle 12587-46-1 X Name S 24, 25, 26

alpha-Farnesene 502-61-4 X Name S 18

alpha-Methyl-1H-imidazole-1-ethanol 37788-55-9 X Name S 18

Aluminum 7429-90-5 X X S 3, 9, 10

Ammonia 7664-41-7 X S 3, 9, 10, 18

Antimony 7440-36-0 X S 3, 9, 10

Aroclor 1248 12672-29-6 X S 3, 9

Arsenic 7440-38-2 X X S 3, 9, 10

Barium 7440-39-3 X S 3, 9, 10

Benz(a)anthracene 56-55-3 X X

Name; 

CASRN S 15

Benzene 71-43-2 X X X S,C 3, 9, 10, 12, 13, 16, 

22

Benzene, 1,3 (or 1,4)-dimethyl- 179601-23-1 Name C 13

Benzidine 92-87-5 X X S 15

Benzo(a)pyrene 50-32-8 X X S 3, 9, 15

Benzo(b)fluoranthene 205-99-2 X X S 3, 9, 15
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-92

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Benzo(g,h,i)perylene 191-24-2 X X S 3, 9, 10, 15

Benzo(k)fluoranthene 207-08-9 X X S 3, 9, 15

Benzophenone 119-61-9 X X C 21

Benzothiazole 95-16-9 X S,C 14, 20, 21

Benzyl alcohol 100-51-6 X X Name S 3, 9, 10, 15, 20

Benzyl butyl phthalate 85-68-7 X X Name C 20, 21

Benzyl chloride 100-44-7 X X X S 22

Beryllium 7440-41-7 X S 3, 9, 10

Beta particle 12587-47-2 X Name S 24, 25, 26

beta-Hexachlorocyclohexane 319-85-7 X X S 3, 9

biphenyl 92-52-4 X X C 20, 21

Bis(1,1-dimethylethyl)-phenol 26746-38-3 X Name S,C 21

Bis(2-chloroethyl) ether 111-44-4 X X X S 3, 9

Bis(2-ethylhexyl) isophthalate 137-89-3 X Name S 18

Bis(dichloromethyl) ether 20524-86-1 X Name S 18

Bis-(octylphenyl)-amine 26603-23-6 Name C 20

Bisphenol A 80-05-7 X X X Name S 22

Boron 7440-42-8 X X S 3, 9, 10

Bromide 24959-67-9 S 3, 9, 10

Bromodichloromethane 75-27-4 X X S 3

Bromoform 75-25-2 X X S 3, 9, 10

Butanenitrile 109-74-0 X S 16
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-93

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Butanoic acid 107-92-6 X S 9, 10

Butanoic acid, butyl ester 109-21-7 X Name C 20

Butyl 8-methylnonyl phthalate 89-18-9 X Name S 18

Butylbenzene 104-51-8 X X Name S,C 9, 10, 13

Butylcyclohexane 1678-93-9 X S 18

Butyrate 461-55-2 X S 11

Cadmium 7440-43-9 X S 3, 9, 10

Caesium 7440-46-2 Name C 14

Caesium-137 10045-97-3 S 3

Caffeine 58-08-2 X X C 20

Calcium 7440-70-2 S 3, 9, 10

Caprolactam 105-60-2 X X C 14, 21

Carbon dioxide 124-38-9 X X S 3, 9, 10

Carbon disulfide 75-15-0 X X S 3, 9, 22

Chloride 16887-00-6 X S 3, 9, 10

Chlorine 7782-50-5 X X S 3, 10

Chlorobenzene 108-90-7 X X X Name S 16

Chlorodibromomethane 124-48-1 X X S 3

Chloroform 67-66-3 X X S 3, 9, 10, 18

Chloromethane 74-87-3 X X X S 3, 10, 22

Chloromethyl 5-chloropentyl ether 145912-11-4 X Name S 18

Cholesterol 57-88-5 X X C 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-94

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Chromium 7440-47-3 X S 3, 9, 10

Chromium (III) 16065-83-1 X X S 3

Chromium (VI) 18540-29-9 X X S 3, 10

Chrysene 218-01-9 X X S 15

cis-1,4-Dimethyladamantane 24145-89-9 X Name S 18

cis-Octahydro-4a-methyl-2(1H)-

naphthalenone 938-06-7 X Name S 18

Cobalt 7440-48-4 X S 3, 9, 10

Copper 7440-50-8 X X S 3, 9, 10

Cumene 98-82-8 X X X Name S 3, 9, 22

Cyanide 57-12-5 X X S 3, 9, 10

Cyclohexyl mercaptoacetate 16849-98-2 X Name S 18

Cyclohexylbenzene 827-52-1 X S 18

Cyclopentadecane 295-48-7 X S 18

Cyclotetracosane 297-03-0 X S 18

Cyclotetradecane 295-17-0 X S 18

Cyclotridecane 295-02-3 X S 18

Decahydro-1-methyl-2-

methylenenaphthalene 90548-09-7 X S 18

Decahydro-2-methylnaphthalene 2958-76-1 X Name S 18

Decalin 91-17-8 X Name S 18

Decylcyclohexane 1795-16-0 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-95

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

delta-Hexachlorocyclohexane 319-86-8 X X S 9

Di(2-ethylhexyl) phthalate 117-81-7 X X X Name S 3, 9, 10, 18

Dibenz(a,h)anthracene 53-70-3 X X S 3, 9, 15

Dibenzosuberol 1210-34-0 X Name S 18

dibenzothiophene 132-65-0 X X C 21

Dibromoacetonitrile 3252-43-5 X X X S 11

Dibutyl hexanedioate 105-99-7 X Name S 18

Dibutyl phthalate 84-74-2 X X S,C 3, 9, 10, 20, 21

Dichloromethane 75-09-2 X X X Name S 9, 10, 18

didecyl phthalate 84-77-5 X S 18

Dieldrin 60-57-1 X X S 9

Diethyl phthalate 84-66-2 X X Name S,C 9, 20, 21

Diethyltoluamide 134-62-3 X X Name C 21

Diisodecyl phthalate 26761-40-0 X X Name S 18

Diisooctyl phthalate 27554-26-3 X Name S 18

Dimethyl phthalate 131-11-3 X X C 20

Dimethylnaphthalene 28804-88-8 Name C 20, 21

Dimethylphenol 1300-71-6 C 20, 21

Dimethyl-tetracyclo[5.2.1.0(2,6)-

0(3,5)]decane 74646-38-1 X Name C 20

DINP 28553-12-0 X Name S 18

Dioctadecyloate phosphoric acid 3037-89-6 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-96

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Dioctyl hexanedioate 123-79-5 X Name S 18

Dioctyl phthalate 117-84-0 X X Name S 9, 10, 14, 18, 21

Diphenylamine 122-39-4 X X S,C 3, 9, 15, 20, 21

Diphenylmethane 101-81-5 X C 20

Di-tert-butyl nitroxide 2406-25-9 X Name S 16

D-Limonene 5989-27-5 X X X S 22

Dodecane 112-40-3 X X S 12, 18

Dodecanoic acid 143-07-7 X S,C 14, 20, 21

Dotriacontane 544-85-4 X S 18

Drometrizole 2440-22-4 X Name C 20

Endosulfan I 959-98-8 X S 3, 9

Endosulfan II 33213-65-9 X S 3, 9

Endrin aldehyde 7421-93-4 X S 3, 9

Ethanol 64-17-5 X X X S 22

Ethyl glycylglycinate 627-74-7 X Name S 18

Ethylbenzene 100-41-4 X X X S,C 3, 9, 10, 13, 18, 22

Ethylcyclohexane 1678-91-7 X S 18

Ethylcyclopentane 1640-89-7 X S 18

Ethylene glycol 107-21-1 X X X S,C 3, 9, 21, 22

Farnesol 4602-84-0 X Name S 18

Fluoranthene 206-44-0 X X S 3, 9, 15

Fluorene 86-73-7 X X S,C 3, 9, 10, 15, 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-97

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Fluoride 16984-48-8 X S 3, 9, 10

Formate 71-47-6 X Name S 11, 19

Formic acid 64-18-6 X X X U 10

Glutaraldehyde 111-30-8 X X S 22

Glycolic acid 79-14-1 X X S 18

Heptachlor 76-44-8 X X S 3, 9

Heptachlor epoxide 1024-57-3 X X S 3, 9

Heptacosane 593-49-7 X S,C 18, 20

Heptane 142-82-5 X X S 18

Heptanoic acid 111-14-8 X U 10

Heptylcyclohexane 5617-41-4 X S 18

Hex-3-yne 928-49-4 X Name S 18

Hexadecahydropyrene 2435-85-0 X S 18

Hexadecanoic acid 57-10-3 X C 14, 21

Hexane 110-54-3 X X X S 18

Hexanoic acid 142-62-1 X U 10

Hexatriacontane 630-06-8 X S 18

Hexylcyclohexane 4292-75-5 X S 18

Hydratropaldehyde 93-53-8 X Name S 18

Hydrazine 302-01-2 X X S 18

Hydrochloric acid 7647-01-0 X X S 18

Hydroxyacetonitrile 107-16-4 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-98

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Imidazo[1,2-a]pyrimidine 274-95-3 X S 18

Indeno(1,2,3-cd)pyrene 193-39-5 X X S 3, 9, 15

Iodine 7553-56-2 X S 9, 14

Iron 7439-89-6 X X S 3, 9, 10

Isobutylbenzene 538-93-2 X Name S 18

Isobutylcyclohexane 1678-98-4 X Name S 18

Isopropanol 67-63-0 X X X S 3, 9, 22

Isopropyl myristate 110-27-0 X Name C 20

Isoquinoline 119-65-3 X X C 21

Isovaleric acid 503-74-2 X U 10

Kaur-16-ene 562-28-7 X Name C 21

Lead 7439-92-1 X X S 3, 9, 10

Lindane 58-89-9 X X S 3, 9

Lithium 7439-93-2 X S 3, 9, 10

m,p-Cresol mixture NOCAS_24858 X Name C 10

Magnesium 7439-95-4 S 3, 9, 10

Manganese 7439-96-5 X S 3, 9, 10

m-Cresol 108-39-4 X X Name S,C 3, 9, 10, 13, 15

m-Cymene 535-77-3 X Name S 18

Menthol 1490-04-6 X Name S 18

Mercury 7439-97-6 X S 3, 9, 10

Methanol 67-56-1 X X X S 3, 9, 22
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-99

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Methyl biphenyl, mixed isomers 28652-72-4 Name C 14, 21

Methyl bromide 74-83-9 X X S 3, 9

Methyl crotonate 18707-60-3 X Name S 18

Methyl ethyl ketone 78-93-3 X X Name S 3, 9, 10

Methyl(Z)-3,3-diphenyl-4-hexenoate 119296-91-2 X Name C 20

Methylcyclohexane 108-87-2 X X S 18

Methylenecyclohexane 1192-37-6 X CASRN S 18

Methylnaphthalene 1321-94-4 Name C 20, 21

Methylquinoline 27601-00-9 Name C 14

Molybdenum 7439-98-7 X S 3, 9, 10

m-xylene 108-38-3 X X Name S 18

N,N-Dimethylformamide 68-12-2 X X X S 22

Naphthalene 91-20-3 X X X S,C 3, 9, 10, 11, 12, 13, 

14, 15, 20, 21, 22

Nickel 7440-02-0 X S 3, 9, 10

Nitrate 14797-55-8 X S,C 3, 9, 10

Nitrite 14797-65-0 X S,C 3, 9, 10

N-Nitrosodiphenylamine 86-30-6 X X S 3, 9, 10, 15

N-Nitroso-N-methylethylamine 10595-95-6 X X Name S 9, 15

Nonacosane 630-03-5 X S 18

Nonahexacontanoic acid 40710-32-5 X S 18

Nonane 111-84-2 X X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-100

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Norphytane 1921-70-6 X Name S 18

o-Cresol 95-48-7 X X Name S,C 3, 9, 10, 13, 15

Octadecanoic acid 57-11-4 X S,C 14, 21

Octahydro-2-methylpentalene 3868-64-2 X S 18

Octane 111-65-9 X S 18

Octasulfur 10544-50-0 Name C 14

O-Decylhydroxylamine 29812-79-1 X S 18

O-Isobutylhydroxylamine 5618-62-2 X Name S 16

o-Xylene 95-47-6 X X X S 18

p,p'-DDE 72-55-9 X X S 3, 9

p-Cresol 106-44-5 X X Name S,C 3, 9, 10, 13, 15

p-Cymene 99-87-6 X Name S 9, 10, 18

Pentadecanoic acid 1002-84-2 X C 20

Pentane 109-66-0 X X X S 16

Pentanoic acid 109-52-4 X U 10

Pentatriacontane 630-07-9 X S 18

Pentylcyclohexane 4292-92-6 X S 18

Pentylhydroperoxide 74-80-6 X S 18

perylene 198-55-0 X X S,C 21

Phenanthrene 85-01-8 X X X S,C 3, 9, 10, 15, 16, 20

Phenanthrene-1-carboxlic acid 27875-89-4 X Name C 20

Phenol 108-95-2 X X X S,C 3, 9, 10, 13, 15
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-101

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Phorate 298-02-2 X X S 9

Phosphorus 7723-14-0 X S 3, 9

Polypropylene glycol 25322-69-4 X S 23

Potassium 7440-09-7 S 3, 9, 10

Propane-diphenyl 25167-94-6 Name C 20

Propargyl alcohol 107-19-7 X X X S 22

Propionate 72-03-7 X Name C 21

Propionic acid 79-09-4 X U 10

Propyl cyanate 1768-36-1 X Name S 16

Propylbenzene 103-65-1 X Name S 9, 13, 16, 18

Propylcyclohexane 1678-92-8 X S 18

Propylcyclopentane 2040-96-2 X S 18

p-Tert-butylphenol 98-54-4 X Name C 21

p-Xylene 106-42-3 X X X S,C 13, 22

Pyrene 129-00-0 X X S,C 9, 10, 15, 20, 21

Pyreno[4,5-c]furan 15123-40-7 C 20

Pyridine 110-86-1 X X S 3, 9, 10, 15

Pyruvate 57-60-3 X S 11

Quinoline 91-22-5 X X X S,C 21

Radium 7440-14-4 X S 3

Radium-226 13982-63-3 X S 3, 10, 24, 25, 26, 27

Radium-228 15262-20-1 X S 3, 10, 24, 25, 26
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-102

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

rel-(1R,2S)-1,2-Diethylcyclohexadecane 14113-60-1 X Name S 18

Rubidium 7440-17-7 C 14

Safrole 94-59-7 X X S 3, 9

sec-Butylbenzene 135-98-8 X S,C 9, 13

Selenium 7782-49-2 X S 3, 9, 10

Silica 7631-86-9 X X U 10

Silicon 7440-21-3 U 10

Silver 7440-22-4 X S 3, 9, 10

Sodium 7440-23-5 S 3, 9, 10

Sterane 50-24-8 X Name C 20

Strontium 7440-24-6 X S 3, 9, 10

Sulfate 14808-79-8 X S 3, 9, 10

Sulfide 18496-25-8 S 9, 14

Sulfite 14265-45-3 S 3

syn-1,6:8,13-Bismethano[14]annulene 55821-04-0 X Name S 18

tert-Butylbenzene 98-06-6 X C 13

Tetrachloroethene 127-18-4 X X Name S 3, 9, 11

Tetracontane 4181-95-7 X S 18

Tetradecanal 124-25-4 X S 18

Tetradecane 629-59-4 X X S,C 18, 20

Tetradecanoic acid 544-63-8 X S,C 14, 20, 21

Tetradecyl trifluoroacetate 6222-02-2 X Name S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-103

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

tetramethylbutanedinitrile 3333-52-6 X Name S,C 21

Thallium 7440-28-0 X S 3, 9, 10

Tin 7440-31-5 X S 9, 10

Titanium 7440-32-6 S 3, 9, 10

Toluene 108-88-3 X X X S

3, 9, 10, 12, 13, 18, 

22

trans-1,4-Dimethyladamantane 24145-88-8 X Name S 18

Triacontane 638-68-6 X S 18

Tributyl citrate 77-94-1 X Name S 18

Tributyl phosphate 126-73-8 X X X Name C 14

Trichlorodocosylsilane 7325-84-0 X S 18

trichlorophenol 25167-82-2 C 21

Tricyclo[4.4.0.0(3,9)]decane NOCAS_873040 X C 20

Tridecanal 10486-19-8 X S 18

Tridecane 629-50-5 X X S 18

Tridecanedial 63521-76-6 X C 20

Tridecyloate-2,2,3,3,4,4,4-

heptafluorobutanoic acid 959088-59-6 X S 18

Triethylene glycol monododecyl ether 3055-94-5 X S,C 13, 21

Trimethylbenzene 25551-13-7 X X Name S,C 12, 21

Triphenyl phosphate 115-86-6 X S,C 14, 20, 21

Tritetracontane 7098-21-7 X S 18
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-104

Chemical Namea CASRNb

Known 

constituent of 

hydraulic 

fracturing fluid

Physicochemical 

properties

Selected 

toxicity 

datac

NCCT 

CASRN or 

name 

changed

Formation 

type Reference

Undecane 1120-21-4 X X S 12, 18

Undecyl heptafluorobutanoate 959103-74-3 X Name S 18

Uranium-235 15117-96-1 X S 28

Uranium-238 7440-61-1 X S 26, 28

Vanadium 7440-62-2 X S 3, 10

Vellerdiol 51276-18-7 X Name C 20

Xylenes 1330-20-7 X X X Name S 3, 9, 10

Zinc 7440-66-6 X X S 3, 9, 10

Zirconium 7440-67-7 S 3, 9, 10

a The following chemicals were found in literature Reference #18 as being present in produced water, but were inadvertently not included in our chemical name/CASRN 

matching process. Chemical name/CASRN match was made by the authors of that study and may or may not reflect the preferred match as appears in DSSTox: 1-

Chlorooctadecane, CASRN 3386-33-2; 1-Nonadecene, CASRN 18435-45-5; 17-Pentatriacontene, CASRN 6971-40-0; 2,6,10-Trimethyldodecane, CASRN 3891-98-3; 2,6,10,14-

Tetramethylhexadecane, CASRN 638-36-8; Cyclotriacontane, CASRN 297-35-8; Docosane, CASRN 629-97-0; Hexacosane, CASRN 630-01-3; Pentacosane, CASRN 629-99-2; 

Tetracosane, CASRN 646-31-1; and Tricosane, CASRN 638-67-5. Ten out of 11 of these chemicals appear to have physicochemical properties available (all except 

Cyclotriacontane) and none have selected toxicity data.

b Some chemicals are designated as “NOCAS_” which are DSSTox database-specific CAS-like identifiers assigned to a listed substance name.

c Chemicals are flagged as having selected toxicity data available if they have one or more oral reference values, oral slope factors, or qualitative cancer classifications available 

from the sources presented in Appendix G.

d Chemicals indicated as having a “CASRN” or “Name” change were changed from one or more of the original references cited in the table during the matching process.
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-105

Table H-5. Chemicals detected in produced water for which a specific, valid CASRN could not 

be identified. 

These chemicals are either chemically ambiguous or too general for a definitive CASRN to be assigned (e.g., 

stereoisomerism not defined, groups of related compounds). 

Chemical Name Formation Type Reference

1,1,3-Trimethylcyclopentane S 18

1,2,4,5-Tetramethylbenzene S 18

1,6,7-Trimethylnaphthalene S,C 14, 18

1,7,11-Trimethyl-4-(1-methylethyl)-cyclotetradecane S 18

1-Chloro-octadecane S 18

1-Docosene C 20

1-Methyl-3-propylbenzene S 18

2,6,10-Trimethyl-dodecane S 18

2,6-Dimethyloctane S 18

2,6-Dimethylundecane S 18

Decane S 18

Eicosane S 18

Heptadecane S 18

Hexadecane S 18

N-dodecyl-N,N-dimethylamine S 22

N-tetradecyl-N,N-dimethylamine S 22

Octacosane S 18

Octadecane S 18

Pentadecane S,C 18, 21

Tetratetracontane S 18

Trimethylbenzenes S,C 20

Alkyl naphthalene S 16

Alkyl propo-benzene S 16

Trimethyl-piperdine S,C 21

Ethyl-tetrahydronaphthalene C 20

Alkyl benzene S 16

Alkyl phosphates C 21
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-106

Chemical Name Formation Type Reference

Alkyl phthalates S,C 21

Bis(2-ethylhexyl)-hexanedioic acid C 20

C11–C37 alkanes/alkenes S,C 21

C12, C14, C16, C18 fatty acids S,C 21

C23–C35 alkanes C 21

C23–C36 alkanes C 21

Dimethylphenanthrene C 20

Dioctyldiphenylamine C 20, 21

Ethyl-cyclodocosane C 20

Methyl-(2,5-dimethoxyphenol)-methanoate C 20

Octahydroanthracene C 20

Octylphenyl ethoxylate S,C 21

Phenanthrenone C 20, 21

Tetramethylacenaphthylene C 20

Tetramethylbenzenes S 12

Tetramethylnaphthalene C 20

Tetramethylphenanthrene C 20, 21

Trimethylnaphthalene S,C 12, 20

Trimethylphenanthrene C 20

1,2-Benzenedicarboxylic acid, 1,2-didecyl ester S 18

N-hexadecanoic acid C 20, 21

Methyl-biphenyl S,C 21

1,7,11-Trimethyl-cyclotetradecane C 20

P-tert-butyl-phenol, p-tert-butyl- C 21

2a,7a-(Epoxymethano)-2H-cyclobutyl C 20

Di-tetra-butyl-4-hydroxbenzaldehyde C 20

Phenanthrene derivative C 20

Bisphenol F Isomer S 22

Methoxynaphthalene derivative C 20

Naphthalenone derivative C 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-107

Chemical Name Formation Type Reference

Other alkyl phenols C 20

Other aromatic compounds C 20

Other benzenamines C 20

Other benzene alkyl compounds C 20

Other heterocyclics C 20

Other indene derivatives C 20

Other naphthalene alkyl compounds C 20

Other phthalates C 20

Other terpenoid compounds C 20

Quinolo-furazan derivative C 20

Benzisothiazole derivative C 20

1-Methylphenanthrene S 18

Poly(ethylene glycol) bis(carboxymethyl) ether S 23

Squalene C 20

Tetrahydro-dimethylnaphthalene C 21

Trimethoxy-benzaldehyde C 20

Methylpyrene C 20

Quinindoline S,C 21

Benzisothiazole C 21

Ethyl phenylmethyl benzene C 20

Dimethyl-ethylindene C 20

Dihydrophenanthrene C 20

9-Phenyl-tetrahydro-1H-benz[f]isoindol-1-one C 20

Methylanthracene C 20

Methoxyanthracene C 20

Dimethyl-biphenyl C 20

Methoxy-methylphenol C 21

Methylphenanthrene S,C 20, 21

Tert-butyl-phenol S,C 21

Methyl-2-quinolinecarboxylic acid C 20
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-108 

Chemical Name Formation Type Reference

Methylethylnaphthalene C 20

Tetrahydromethylnaphthalene C 20

Tetrahydrophenanthrene C 20

Dihydro-1-methylphenanthrene C 20

1,7,11-Trimethylcyclotetradecane C 20

Tetrahydro-trimethylnaphthalene C 20

1-(2-Hydroxy-5-methylphenyl)-2-hexen-1-one C 20

Ethyl dimethyl azulene C 20

9-Methoxyfluorene C 20

1,2-Di-but-2-enyl-cyclohexanone C 20

9H-Fluoren-9-ol C 20

1,4-[13C]-1,2,3,4-Tetrahydro-5-naphthaleneamine C 20

Dihydro-(-)-neocloven-(II) C 20

4-(4-Ethylcyclohexyl)-cyclohexene C 20

Methyl-2-octylcyclopropene-1-octane C 20

Decahydro-4,4,8,9,10-pentamethylnaphthalene S,C 21

Hexahydro-1,3,5-trimethyl-1,3,5-triazine-2-thione (a biocide) S,C 21

8-Isopropyl-2,5-dimethyl-terralin C 20

9,10-Dimethoxy-2,3-dihydroanthracene C 20

PEG-C-EO10aS 22

PEG-C-EO2aS 23

PEG-C-EO3aS 23

PEG-C-EO4aS 23

PEG-C-EO5aS 23

PEG-C-EO6aS 23

PEG-C-EO7aS 23

PEG-C-EO8aS 23

PEG-C-EO9aS 23

PEG-EO10bS 23

PEG-EO4bS 23
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-109

Chemical Name Formation Type Reference

PEG-EO5bS 23

PEG-EO6bS 23

PEG-EO7bS 23

PEG-EO8bS 23

PEG-EO9bS 23

PPG-PO10cS 23

PPG-PO2cS 23

PPG-PO3cS 23

PPG-PO4cS 23

PPG-PO5cS 23

PPG-PO6cS 23

PPG-PO7cS 23

PPG-PO8cS 23

PPG-PO9cS 23

a Polyethylene glycol carboxylates containing between four to 10 ethylene oxide monomers.

b Polyethylene glycols containing between four to 10 ethylene oxide monomers.

c Polypropylene glycols containing between two and 10 proplyene oxide monomers.
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

H-110

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Appendix I – Unit Conversions

I-1 

Appendix I. Unit Conversions
Appendix I – Unit Conversions

I-2 

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Appendix I – Unit Conversions

I-3 

Appendix I. Unit Conversions 

LENGTH 

1 in (inch) = 2.54 cm (centimeters) 

 25.4 mm (millimeters) 

 25,400 μm (microns) 

1 ft (foot) = 0.3048 m (meters) 

 30.48 cm 

1 mi (mile) = 5,280 ft 

 1,609.344 m 

 1.6093 km (kilometers) 

AREA 

1 ft2 (square foot) = 0.0929 m2 (square meters) 

1 acre = 43,560 ft2 

= 0.0016 mi2 (square miles) 

= 0.4047 ha (hectares) 

= 4,046.825 m2

1 mi2 = 639.9974 ac 

= 258.9988 ha 

= 2.5899 km2 (square kilometers) 

MASS 

1 lb (pound) = 453.5924 g (grams) 

= 0.4536 kg (kilograms) 

1 ton (short ton, U.S.) = 2,000 lb 

= 907.185 kg 

= 0.9072 metric tons 
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

I-4 

VOLUME OR CAPACITY (LIQUID MEASURE) 

1 bbl (barrel) = 42 gal (gallons, U.S.) 

= 158.9873 L (liters) 

1 gal = 231 in3 (cubic inches) 

= 0.1337 ft3 (cubic feet) 

= 3.7854 L 

= 0.0039 m3 (cubic meters) 

= 3.7854 × 10-9 Mm3 (million cubic meters) 

1 Mgal (million gallons) = 1.3368 × 105 ft3 

1 ft3 = 1,728 in3

= 7.4805 gal 

= 28.3169 L 

= 0.0283 m3

1 mi3 (cubic mile) = 4.1682 km3 (cubic kilometers) 

CONCENTRATION 

1 mg/L (milligram per liter) = 1.0 × 10-6 kg/L (kilograms per liter) 

= 1.0 × 10-3 g/L (grams per liter) 

= 1,000 μg/L (micrograms per liter) 

= 1.001 ppm (parts per million) 

= 8.3454 × 10-6 lb/gal (pounds per gallon) 

= 6.2428 × 10-5 lb/ft3 (pounds per cubic foot) 

SPEED 

1 mi/hr (mile per hour) = 1.4666̅ ft/s (feet per second) 

= 0.4470 m/s (meters per second) 

DENSITY 

1 g/mL = 1,000 g/L 

= 1.0 × 106 mg/L 
Appendix I – Unit Conversions

I-5 

VOLUME PER UNIT TIME 

1 ft3/s (cubic foot per second) = 448.8312 gpm (gallons per minute)

= 0.6163 Mgpd (million gallons per day) 

= 28.3169 L/s (liters per second) 

= 0.0283 m3/s (cubic meters per second) 

1 ft3/day (cubic feet per day) = 0.0052 gpm 

= 7.4805 gpd 

= 0.0283 m3/d (cubic meters per day) 

1 bbl/day (barrel per day) = 42 gpd 

= 158.9873 L/d (liters per day) 

PRESSURE 

1 psi (pound per square inch) = 6,894.7573 Pa (pascals) 

= 0.068 atm (standard atmospheres) 

RADIATION 

Activity

1 Ci (curie) = 3.7 × 1010 decays per second 

1 Bq (becquerel) ≈ 2.703 × 10-11 Ci

≈ 27.027 pCi (picocuries) 

1 pCi = 0.037 Bq 

= 0.037 decays per second 

= 2.22 decays per minute 

Exposure 

1 rem (röentgen equivalent in man) = 0.01 Sv (sieverts) 

1 Sv = 1 J/kg (joule per kilogram) 

ELECTRIC CONDUCTANCE 

1 S (siemen) = 1 Ω-1 (reciprocal of resistance) 

= 1 A/V (ampere per volt) 

= 1 kg-1 • m-2 • s3 • A2 (second cubed- ampere squared 

per kilogram-square meter) 

= 1.0 × 106 μS (microsiemens)

TEMPERATURE 

[°F (degrees, Fahrenheit) - 32] × 5/9 = °C (degrees, Celsius) 
Appendix H – Chemicals Identified in Hydraulic Fracturing Fluids and/or Produced Water 

I-6 

PERMEABILITY 

1 cm2 = 1.0 × 10-4 m2

≈ 1.0 × 108 D (darcys) 

1 D ≈ 1.0 × 10-12 m2

= 1,000 mD (millidarcys) 

= 1.0 × 106 μD (microdarcys)
Appendix J – Glossary

J-1 

Appendix J. Glossary 
Appendix J – Glossary

J-2 

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Appendix J – Glossary

J-3 

Appendix J. Glossary 

J.1. Introduction

This glossary is intended to provide definitions for scientific and technical terms used in the rest of 

the document. For most terms, a citation is provided that indicates the reference from which a 

definition was reprinted or adapted. For terms without a citation, the definition was developed for 

the purposes of this assessment. In some cases, terms in this glossary may also have a legal or 

regulatory definition in addition to the definition provided; the definitions of these terms in the 

glossary are not intended to replace or modify any such legal or regulatory definitions. The terms in 

this glossary do not constitute terms of art for legal or regulatory purposes. 

J.2. Glossary Terms and Definitions

Abandoned well: 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. 

Acid mine drainage: Flow of water from areas that have been mined for coal or other mineral ores. 

The water has a low pH because of its contact with sulfur‐bearing material and is harmful to 

aquatic organisms (U.S. EPA, 2013d). 

Additive: A single chemical or chemical mixture designed to serve a specific purpose in the 

hydraulic fracturing fluid. 

Adsorption: Adhesion of molecules of gas, liquid, or dissolved solids to a surface (U.S. EPA, 2013d). 

Advection: A mechanism for moving chemicals in flowing water, where a chemical moves along 

with the flow of the water itself. 

Aeration: The process of mixing air with water or soil. It promotes biological degradation of

organic matter in water. The process may be passive (as when waste is exposed to air) or active (as 

when a mixing or bubbling device introduces the air) (U.S. EPA, 2013d). 

Aerobic mesophiles: Microorganisms that use oxygen for energy production and are tolerant of 

moderate temperatures. 

Analyte: The element, ion, or compound that an analysis seeks to identify; the compound of interest 

(U.S. EPA, 2013d). 

Annulus: Refers to either the space between the casing of a well and the wellbore or the space 

between any two strings of tubing or casing (U.S. EPA, 2013d). 

API number: A unique identifying number for all oil and gas wells drilled in the United States. The 

system was developed by the American Petroleum Institute (Oil and Gas Mineral Services, 2010). 

Aquifer: A water-bearing geologic formation, group of formations, or part of a formation. 

Groundwater is the water in an aquifer. 
Appendix J – Glossary

J-4 

Base fluid: The fluid into which additives and proppants are mixed to formulate a hydraulic 

fracturing fluid. 

Basin: A depression in the crust of the earth, caused by plate tectonic activity and subsidence, into 

which sediments accumulate. Sedimentary basins vary from bowl‐shaped to elongated troughs. 

Basins can be bounded by faults. Rift basins are commonly symmetrical; basins along continental 

margins tend to be asymmetrical. If rich hydrocarbon source rocks occur in combination with 

appropriate depth and duration of burial, then a petroleum system can develop within the basin. 

Most basins contain some amount of shale, thus providing opportunities for shale gas exploration 

and production (Schlumberger, 2014). 

Bedding plane: The surface that separates two layers of stratified rocks. 

Biogenic: Methane that is produced in shallower formations by bacterial activity in anaerobic 

conditions. It is the ultimate dissimilation product of microbially mediated reactions of organic 

molecules. 

Blowout preventer (BOP): 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 

Brackish water: 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. 

BTEX: An acronym for benzene, toluene, ethylbenzene, and xylenes. These chemicals are a group of 

single ringed aromatic hydrocarbon based on the benzene structure. These compounds are found in 

petroleum and are of specific importance because of their health effects. 

British thermal unit (Btu): A measure of the heat (or energy) content of fuels. 

Caliper log: A log that is used to check for any wellbore irregularities. It is run prior to primary 

cementing as a means of calculating the amount of cement needed. Also run in conjunction with 

other open hole logs for log corrections or run on cased holes to evaluate metal loss (NYSDEC, 

2011). 

Capillarity: The action by which the surface of a liquid in contact with a solid is elevated or lowered 

depending on the relative attraction of the molecules of the liquid for each other (cohesion) and for 

those of the solid (adhesion). Capillary forces arise from the differential attraction between 

immiscible fluids and solid surfaces; these are the forces responsible for capillary rise in smalldiameter tubes and porous materials (adapted from Dake, 1978). 

Casing: Steel pipe that is lowered into a wellbore. Casing extends from the bottom of the hole to the 

surface (Schlumberger, 2014). 
Appendix J – Glossary

J-5 

Casing, fully cemented: Casing 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 it is a surface casing). 

Casing, partially cemented: Casing 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, if it is a 

surface casing), but is not fully cemented. 

Casing, uncemented: Casing 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, if it is a surface casing). 

Casing inspection log: An in situ record of casing thickness and integrity, to determine whether 

and to what extent the casing has undergone corrosion. The term refers to an individual 

measurement, or a combination of measurements using acoustic, electrical, and mechanical 

techniques, to evaluate the casing thickness and other parameters. The log is usually presented with 

the basic measurements and an estimate of metal loss. Today the terms casing‐evaluation log and 

pipe‐inspection log are used synonymously (Schlumberger, 2014). 

Casing string: An assembled length of steel pipe configured to suit a specific wellbore. 

Chemical Abstract Service Registry Number (CASRN): A unique numeric identifier for only one 

substance, which serves as a link to information about a specific chemical substance. The CAS 

registry covers substances identified from the scientific literature from 1957 to the present, with 

additional substances going back to the early 1900s (CAS Registry Service, 2016). For simplicity, we 

refer to both pure chemicals and chemical substances that are mixtures, which have a single CASRN, 

as “chemicals.”

Cation exchange capacity: The total amount of cations (positively charged ions) that a soil can hold. 

Cement: Material used to support and seal the well casing to the rock formations exposed in the 

wellbore. Cement also protects the casing from corrosion and prevents movement of fluids up the 

borehole (U.S. EPA, 2013d). 

Cement bond log: A representation of the integrity of the cement job, specifically whether the 

cement is adhering solidly to the outside of the casing (Schlumberger, 2014). Used to calculate a 

bond index, which varies between 0 and 1, with 1 representing the strongest bond and 0 

representing the weakest bond. 

Cement squeeze: A remedial cementing operation designed to force cement into leak paths in 

wellbore tubulars. The required squeeze pressure is achieved by carefully controlling pump 

pressure. Squeeze cementing operations may be performed to repair poor primary cement jobs, 

isolate perforations, or repair damaged casing or liner (Schlumberger, 2014). 

Centralized waste treatment facility (CWT): Any facility that treats (for disposal, recycling or

recovery of material) any hazardous or non-hazardous industrial wastes, hazardous or nonhazardous industrial wastewater, and/or used material received from off-site (U.S. EPA, 2012c). 
Appendix J – Glossary

J-6 

Coalbed methane: Methane contained in coal seams. A coal seam is a layer or stratum of coal 

parallel to the rock stratification (U.S. EPA, 2013d). 

Collapse pressure: The pressure at which a tube, or vessel, will catastrophically deform as a result 

of differential pressure acting from outside to inside of the vessel or tube (Schlumberger, 2014). 

Collar: A threaded coupling used to join two lengths of pipe such as production tubing, casing, or 

liner. The type of thread and style of collar varies with the specifications and manufacturer of the 

tubing (Schlumberger, 2014). 

Combination truck: A truck tractor or a truck tractor pulling any number of trailers (U.S. 

Department of Transportation, 2012). 

Community water system: A public water system which serves at least 15 service connections 

used by year-round residents or regularly serves at least 25 year-round residents (U.S. EPA, 

2013d). 

Completion: 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. 

Complexation: 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. 

Compressive strength: Measure of the ability of a substance to withstand compression (NYSDEC, 

2011). 

Conductor casing: This large diameter casing is usually the first string of casing in a well. It is set or 

driven into the unconsolidated material where the well will be drilled to keep the loose material 

from caving in (NYSDEC, 2011). 

Confidential business information (CBI): Information that is claimed by the submitter to be 

entitled to confidential treatment, such as trade secrets, commercial or financial information, or 

other information that has been claimed as confidential. This information is generally not publicly 

available. The EPA may have special procedures for handling such information. Further discussion 

of information claimed to be CBI, including the EPA’s process for determining the validity of such 

claims, is contained in 40 CFR. Part 2. 

Contaminant: A substance that is either present in an environment where it does not belong or is 

present at levels that might cause harmful (adverse) health effects (U.S. EPA, 2013d). 

Conventional rock formation: Permeable groups of rock with many large, well-connected pore 

spaces that allow fluids to move within the rock formation. See also conventional reservoir. 

Crosslinked gel: A fluid with polymers that have been linked together through a chemical bond. 

The polymer chains link together to form larger chemical structures with higher viscosity. 

Increased viscosity allows the fracturing fluid to carry more proppant into the fractures. 
Appendix J – Glossary

J-7 

Crude oil: A general term for unrefined petroleum or liquid petroleum (Schlumberger, 2014). 

Cumulative effect: Combined changes in the environment that can take place as a result of multiple 

activities over time and/or space. 

Cumulative water use/cumulative water: Refers to the amount of water used or consumed by all

hydraulic fracturing wells in a given area per year. 

Cyclical stress: Refers to stress caused by frequent or rapid changes in temperature or pressure. 

Deviated well: Any non-horizontal well in which the well bottom is intentionally located at a 

distance (e.g., hundreds of feet) laterally from the wellhead. 

Directional drilling: The practice of controlling the direction and deviation (angle) of a wellbore 

during drilling (SPE, 2016). This enables drilling the wellbore in a predetermined orientation to a 

targeted area in the subsurface. Directional drilling is required for drilling a deviated or horizontal 

well and is common in unconventional reservoirs. 

Discharge: Any emission (other than natural seepage), intentional or unintentional. Includes, but is

not limited to, spilling, leaking, pumping, pouring, emitting, emptying, or dumping (U.S. EPA, 

2013d). Or, where groundwater flows to the surface at springs or through the bottoms of lakes and 

rivers. 

Disclosure: With respect to the FracFocus Registry, all data submitted for a specific oil and gas 

production well for a specific fracture date. 

Disinfection byproduct (DBP): A compound formed by the reaction of a disinfectant such as

chlorine with organic material in the water supply (U.S. EPA, 2013d). 

Domestic water use: Includes indoor and outdoor water uses at residences, and includes, but is 

not limited to, uses such as drinking, food preparation, bathing, washing clothes and dishes, 

flushing toilets, watering lawns and gardens, and maintaining pools (USGS, 2015). 

Drill bit: The tool used to crush or cut rock during drilling of the well. Most bits work by scraping or 

crushing the rock as part of a rotational motion, while some bits work by pounding the rock 

vertically (Schlumberger, 2014). 

Drill collar: A component of a drill string that provides weight on the drill bit for drilling the well. 

Drill collars are thick‐walled tubular pieces machined from solid bars of steel, usually plain carbon 

steel but sometimes of nonmagnetic nickel‐copper alloy or other nonmagnetic premium alloys 

(Schlumberger, 2014). 

Drill cutting: The small pieces of broken and ground-up rock generated during the well drilling 

process. 

Drill string: The combination of the drillpipe, the bottomhole assembly, and any other tools used to 

make the drill bit turn at the bottom of the wellbore (Schlumberger, 2014). 
Appendix J – Glossary

J-8 

Drilling fluid: Any of a number of liquid and gaseous fluids and mixtures of fluids and solids used 

when drilling wellbores (adapted from Schlumberger, 2014). 

Drinking water resource: 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 (U.S. EPA, 2013d). 

Dry gas: Refers to natural gas that occurs in the absence of liquid hydrocarbons (adapted from 

Schlumberger, 2014). 

Effluent: Waste material being discharged into the environment, either treated or untreated (U.S. 

EPA, 2013d). For the purposes of this assessment, effluent refers to liquid waste material. 

Facultative anaerobes: Microorganisms that can use oxygen for energy production if it is present 

in their environment, but can also use alternatives for energy production if no oxygen is present. 

Factor: A feature of hydraulic fracturing operations or an environmental condition that affects the 

frequency or severity of impacts. 

Fault: A fracture or fracture zone along which there has been displacement of the sides relative to 

each other (NYSDEC, 2011). 

Field: Area of oil and gas production with at least one common reservoir for the entire area (Oil and 

Gas Mineral Services, 2010). 

Flowback: The term is defined multiple ways in the literature. In general, it is either fluids 

predominantly containing hydraulic fracturing fluid that return from a well to the surface or a 

process used to prepare the well for production. 

Fluid: A substance that flows when exposed to an external pressure; fluids include both liquids and 

gases. 

Fluid formulation: The entire suite of chemicals, proppant, and base fluid injected into a well 

during hydraulic fracturing (U.S. EPA, 2013d). 

Formation: A body of earth material with distinctive and characteristic properties and a degree of 

homogeneity in its physical properties (U.S. EPA, 2013d). 

Formation packer: A specialized well 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. 

Formation fluid: Fluid that occurs naturally within the pores of rock. These fluids consist primarily 

of water, with varying concentrations of total dissolved solids, but may also contain oil or gas. 

Sometimes referred to as native fluids, native brines, or reservoir fluids. 

FracFocus Registry: A registry for oil and gas well operators to disclose information about 

hydraulic fracturing well locations, and water and chemical use during hydraulic fracturing 
Appendix J – Glossary

J-9 

operations. The registry was developed by the Ground Water Protection Council and the Interstate 

Oil and Gas Compact Commission. 

Fracture: A crack or breakage surface within a rock. 

Fracture complexity: 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. 

Fracture geometry: Refers to characteristics of the fracture such as height, aperture, orientation, 

and azimuth. 

Fracture half-length: The radial distance from a wellbore to the outer tip of a fracture propagated 

from that well (Schlumberger, 2014). 

Freeboard: 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). 

Fresh water: Qualitatively refers to water with relatively low TDS (total dissolved solids) that is 

most readily available for drinking water currently. We do not use the term to imply an exact TDS 

limit, except in Chapter 2 where it refers to water having TDS content up to 3,000 milligrams per 

liter. 

Frequency: 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 the number of 

impacts per hydraulically fractured well. 

Gelation: The process in the setting of the cement where it begins to solidify and lose its ability to 

transmit pressure to the formation. 

Gelled fluid: Fracturing fluids that are usually water-based with added gels to increase the fluid 

viscosity to aid in the transport of proppants (Spellman, 2012; Gupta and Valkó, 2007). 

Groundwater: In the broadest sense, all subsurface water; more commonly that part of the 

subsurface water in the saturated zone (Solley et al., 1998). 

Groundwater age: Refers to how long the water has been in the ground. 

Groundwater availability: The amount of groundwater that is available regardless of legal or 

physical availability (TWDB, 2012). 

Groundwater supply: The amount of groundwater that can be produced given current permits 

and existing infrastructure (TWDB, 2012). 

Halite: A soft, soluble evaporate mineral commonly known as salt or rock salt. Can be critical in 

forming hydrocarbon traps and seals because it tends to flow rather than fracture during 
Appendix J – Glossary

J-10

deformation, thus preventing hydrocarbons from leaking out of a trap even during and after some 

types of deformation (Schlumberger, 2014). 

Hazard evaluation: A component of risk assessment that involves gathering and evaluating data on

the types of health injuries or diseases (e.g., cancer) that may be produced by a chemical and on the 

conditions of exposure under which such health effects are produced. 

Hazard identification: A process for determining if a chemical or a microbe can cause adverse 

health effects in humans and what those effects might be (U.S. EPA, 2013d). 

Henry’s law constant: Ratio of a chemical's vapor pressure in the atmosphere to its solubility in

water. The higher the Henry's law constant, the more volatile the compound will be from water 

(NYSDEC, 2011). 

Horizontal drilling: Drilling a portion of a well horizontally to expose more of the formation 

surface area to the wellbore (Oil and Gas Mineral Services, 2010). This is a type of directional 

drilling. 

Horizontal well: A well that is drilled vertically downward up 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. Directional drilling is required to drill a horizontal well. 

Hydraulic fracturing: A stimulation technique used to increase production of oil and gas. 

Hydraulic fracturing involves the injection of fluids under pressures great enough to fracture the 

oil- and gas-production formations (U.S. EPA, 2011a). 

Hydraulic fracturing fluids: Engineered fluids, typically consisting of a base fluid, additives, and 

proppant that are pumped under high pressure into the well to create and hold open fractures in

the formation. 

Hydraulic fracturing wastewater: 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.1

Hydraulic fracturing water cycle: The cycle of water in the hydraulic fracturing process, 

encompassing the acquisition of water, chemical mixing of the fracturing fluid, injection of the fluid 

into the formation, the production and handling of produced water, and the ultimate treatment and 

disposal of hydraulic fracturing wastewaters. 

 

1 This general description does not, and is not intended to, provide that the production, recovery, or recycling of oil, 

including the production, recovery, or recycling of produced water, 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. 
Appendix J – Glossary

J-11

Hydraulic gradient: Slope of a water table or potentiometric surface. More specifically, change in 

the hydraulic head per unit of distance in the direction of the maximum rate of decrease (U.S. EPA, 

2013d). 

Hydrocarbon: An organic compound containing only hydrogen and carbon, often occurring in

petroleum, natural gas, and coal (U.S. EPA, 2013d). 

Hydrophilic: A chemical property that describes a tendency to dissolve in water. Literally, “water 

loving.”

Hydrophobic: A chemical property that describes a tendency to be soluble in nonpolar solvents 

and sparingly soluble in water. Literally, “water fearing.”

Hydrostatic pressure: The pressure exerted by a column of fluid at a given depth. In Chapter 6, it 

refers to the pressure exerted by a column of drilling mud or cement on the formation at a 

particular depth. 

Imbibition: The displacement of a non-wet fluid (i.e., gas) by a wet fluid (typically water) (adapted 

from Dake, 1978). 

Immiscible: The chemical property in which two or more liquids or phases are incapable of 

attaining homogeneity (U.S. EPA, 2013d). 

Impact: 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. 

Induced fracture: A fracture created during hydraulic fracturing. 

Integrated risk information system (IRIS): An electronic database that contains the EPA's latest 

descriptive and quantitative regulatory information about chemical constituents. Files on chemicals 

maintained in IRIS contain information related to both noncarcinogenic and carcinogenic health 

effects (U.S. EPA, 2013d). 

Intermediate casing: Casing that seals off intermediate depths and geologic formations that may 

have considerably different reservoir pressures than deeper zones to be drilled (Devereux, 1998; 

Baker, 1979). 

Karst: A type of topography that results from dissolution and collapse of carbonate rocks, such as

limestone, dolomite, and gypsum, and that is characterized by closed depressions or sinkholes, 

caves, and underground drainage (Solley et al., 1998). 

Kill fluid: A weighted fluid with a density that is sufficient to overcome the formation pressure and 

prevent fluids from flowing up the wellbore. 

Large truck: A truck with a gross vehicle weight rating greater than 10,000 pounds (U.S. 

Department of Transportation, 2012). 

Lateral: A horizontal section of a well. 
Appendix J – Glossary

J-12

Leakoff: The fraction of the injected fluid that infiltrates into the formation (e.g., through an 

existing natural fissure) and is not recovered during production (i.e., it does not return through the 

well to the surface) (Economides et al., 2007). Fluids that leak off and are not recovered are 

sometimes referred to as “lost” fluids.

Linear gel: A series of chemicals linked together so that they form a chain. 

Liner: A casing string that does not extend to the top of the wellbore, but instead is anchored or

suspended from inside the bottom of the previous casing string (Schlumberger, 2014). 

Lost cement: Refers to a failure of the cement to be circulated back to the surface during 

construction of the well, indicating that the cement has escaped into the formation. 

Lowest-observable-adverse effect level (LOAEL): 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, 2011c). 

Maximum allowable daily level (MADL): The maximum allowable daily level of a reproductive 

toxicant at which the chemical would have no observable adverse reproductive effect, assuming 

exposure at 1,000 times that level (OEHHA, 2012). 

Maximum contaminant level (MCL): The highest level of a contaminant that is allowed in 

drinking water. MCLs are set as close to the MCLG as feasible using the best available analytical and 

treatment technologies and taking cost into consideration. MCLs are enforceable standards (U.S. 

EPA, 2012a).

Maximum contaminant level goal (MCLG): 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, 2012a) 

Mechanical integrity: The absence of significant leakage within the injection tubing, casing, or 

packer (known as internal mechanical integrity), or outside of the casing (known as external 

mechanical integrity) (U.S. EPA, 2013d). 

Microaerophiles: Microorganisms that require small amounts of oxygen for energy production. 

Microannuli: Very small openings that form between the cement and its surroundings and that 

may serve as pathways for fluid migration to drinking water resources. 

Microseismic monitoring: A technique to track the propagation of a hydraulic fracture as it

advances through a formation (Schlumberger, 2014). 

Minimal risk level (MRL): An ATSDR estimate of daily human exposure to a hazardous substance 

at or below which the substance is unlikely to pose a measurable risk of harmful (adverse), 

noncancerous effects. MRLs are calculated for a route of exposure (inhalation or oral) over a 

specified time period (acute, intermediate, or chronic). MRLs should not be used as predictors of 

harmful (adverse) health effects (ATSDR, 2016). 
Appendix J – Glossary

J-13

Mobility: The ratio of effective permeability to phase viscosity. The overall mobility is a sum of the 

individual phase viscosities. Well productivity is directly proportional to the product of the mobility 

and the layer thickness product (Schlumberger, 2014). 

National Pollution Discharge Elimination System (NPDES): A national program under Section 

402 of the Clean Water Act for regulation of discharges of pollutants from point sources to waters of 

the United States. The Clean Water Act prohibits the discharge of pollutants from any point source 

into waters of the United States, except as authorized by the Act, which may include issuance of an 

NPDES permit. 

National Secondary Drinking Water Regulations (NSDWR): Non-enforceable guidelines 

regulating contaminants that may cause cosmetic effects (such as skin or tooth discoloration) or 

aesthetic effects (such as taste, odor, or color) in drinking water (also referred to as secondary 

standards) (U.S. EPA, 2014c). 

Natural gas: A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases in porous 

formations beneath the earth’s surface, often in association with petroleum. The principal 

constituent of natural gas is methane (Schlumberger, 2014). 

Natural organic matter (NOM): Complex organic compounds that are formed from decomposing 

plant animal and microbial material in soil and water (U.S. EPA, 2013d). 

Naturally Occurring Radioactive Materials (NORM): Radioactive materials found in nature that 

have not been moved or concentrated by human activities. 

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, 2011c). 

Non-community water system: Water systems that supply water to at least 25 of the same people 

or have 15 service connections at least six months per year, but not year-round (U.S. EPA, 2013c). 

National Toxicology Program (NTP): The NTP describes the results of individual experiments on 

a chemical agent and notes the strength of the evidence for conclusions regarding each study. For 

more information, see Appendix G.

Octanol-water partition coefficient (Kow): A coefficient representing the ratio of the solubility of 

a compound in octanol (a nonpolar solvent) to its solubility in water (a polar solvent). The higher 

the Kow, the more nonpolar the compound. Log Kow is generally used as a relative indicator of the

tendency of an organic compound to adsorb to soil. Log Kow values are generally inversely related 

to aqueous solubility and directly proportional to molecular weight (U.S. EPA, 2013d). 

Offset well: An abandoned (i.e., plugged), inactive, or actively producing well near a well that is 

used for hydraulic fracturing. 
Appendix J – Glossary

J-14

Open hole completion: A well completion that has no casing or liner set across the reservoir 

formation, allowing the produced fluids to flow directly into the wellbore (Schlumberger, 2014). 

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 (U.S. EPA, 2011c). 

Soil adsorption coefficient (Koc): A coefficient that provides a measure of the ability of a chemical 

to sorb (adhere) to the organic portion of soil, sediment, and sludge. The higher the Koc, the more 

likely a compound is to adsorb to soils and sediments, and the less likely it is to migrate with water. 

Along with log Kow, log Koc is used as a relative indicator of the tendency of an organic compound to 

adsorb to soil. 

Orphaned well: An inactive oil or gas well with no known (or financially solvent) owner. 

Overburden: Material of any nature, consolidated or unconsolidated, that overlies a deposit of 

useful minerals or ores (U.S. EPA, 2013d). 

Packer: A mechanical device that expands to selectively seal off certain sections of the wellbore to 

keep fluid from migrating within the annulus. Packers can be used to seal the space between the 

tubing and casing, between two casings, or between the production casing and the surrounding 

rock formation (Schlumberger, 2014). 

Pad fluid: A mixture of base fluid, typically water and additives without solid, designed to create, 

elongate, and enlarge fractures along the natural channels of the formation when injected under 

high pressure at the start of the hydraulic fracturing process. 

Partial cementing: Cementing a casing string of a well along only a portion of its length. 

Passby flow: A prescribed, low-streamflow threshold below which withdrawals are not allowed 

(U.S. EPA, 2015d). 

Peer review: A documented critical review of a specific major scientific and/or technical work 

product. Peer review is intended to uncover any technical problems or unresolved issues in a 

preliminary or draft work product through the use of independent experts. This information is then 

used to revise the draft so that the final work product will reflect sound technical information and 

analyses. The process of peer review enhances the scientific or technical work product so that the 

decision or position taken by the EPA, based on that product, has a sound and credible basis (U.S. 

EPA, 2013d). 

Perforation: The communication tunnel created from the casing or liner into the reservoir 

formation through which injected fluids and oil or gas flows. Also refers to the process of creating 

communication channels, e.g., via the use of a jet perforating gun. 
Appendix J – Glossary

J-15

Permeability: The ability of fluids (including oil and gas) to flow through well-connected pores or 

small openings in the rock. Also referred to as intrinsic or absolute permeability. 

Persistence: The length of time a compound stays in the environment, once introduced. A 

compound may persist for less than a second or indefinitely. 

Physicochemical property: The inherent physical and chemical properties of a molecule such as

boiling point, density, physical state, molecular weight, vapor pressure, etc. These properties define 

how a chemical interacts with its environment (U.S. EPA, 2013d). 

Play: A set of oil or gas accumulations sharing similar geologic, geographic properties, such as

source rock, hydrocarbon type, and migration pathways (Oil and Gas Mineral Services, 2010). 

Poisson’s ratio: A ratio of transverse-to-axial (or latitudinal-to-longitudinal) strain; characterizes 

how a material is deformed under pressure. 

Polar molecule: 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. 

Porosity: A measure of empty space for a given volume of material, or the percentage of the 

material (e.g., rock or soil) volume that can be occupied by oil, gas, or water. 

Principal aquifer: A regionally extensive aquifer or aquifer system that has the potential to be 

used as a source of potable water. 

Private (non-public) water system: Water systems that serve fewer than 15 connections and 

fewer than 25 individuals (U.S. EPA, 1991). 

Produced water: Water that flows from the subsurface through oil and gas wells to the surface as a 

by-product of oil and gas production. 

Production casing: The deepest casing set in a well that serves primarily as the conduit for 

producing fluids, although when cemented to the wellbore, this casing can also serve to seal off 

other subsurface zones including groundwater resources (Devereux, 1998; Baker, 1979). 

Production well: A well that is used to bring fluids (such as oil or gas) to the surface. 

Production zone: Refers to the portion of a subsurface rock zone that contains oil or gas to be 

extracted (sometimes using hydraulic fracturing). The production zone is sometimes referred to as

the target zone or targeted rock formation. 

Proppant/propping agent: A granular substance (sand grains, aluminum pellets, or other 

material) that is carried in suspension by the fracturing fluid and that serves to keep the cracks 

open when fracturing fluid is withdrawn after a fracture treatment (U.S. EPA, 2013d). 

Protected groundwater resource: All aquifers, or their portions, that the state or other regulatory 

agency requires to be protected from fluid migration through or along wellbores. 
Appendix J – Glossary

J-16

Public water system source: The source of the surface water or groundwater used by a public 

water system, including source wells, intakes, reservoirs, infiltration galleries, and springs. 

Public water system: Water systems that 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 (Safe Drinking Water Act, 2002). 

Publicly owned treatment works (POTW): Any device or system used in the treatment (including 

recycling and reclamation) of municipal sewage or industrial wastes of a liquid nature that is owned 

by a state or municipality. This definition includes sewers, pipes, or other conveyances only if they 

convey wastewater to a POTW providing treatment (U.S. EPA, 2013d). 

Quality assurance (QA): An integrated system of management activities involving planning, 

implementation, documentation, assessment, reporting, and quality improvement to ensure that a 

process, item, or service is of the type and quality needed and expected by the customer (U.S. EPA, 

2013d). 

Quality assurance project plan (QAPP): A formal document describing in comprehensive detail 

the necessary quality assurance procedures, quality control activities, and other technical activities 

that need to be implemented to ensure that the results of the work performed will satisfy the stated 

performance or acceptance criteria (U.S. EPA, 2013d). 

Quality management plan: A document that describes a quality system in terms of the 

organizational structure, policy and procedures, functional responsibilities of management and 

staff, lines of authority, and required interfaces for those planning, implementing, documenting, and 

assessing all activities conducted (U.S. EPA, 2013d). 

Radioactive tracer log: A record of the presence of radioactive tracer material placed in or around 

the wellbore to measure fluid movement in injection wells (Schlumberger, 2014). 

Radionuclide: Radioactive particle, man‐made or natural, with a distinct atomic weight number. 

Emits radiation in the form of alpha or beta particles, or as gamma rays. Can have a long life as soil 

or water pollutant. Prolonged exposure to radionuclides increases the risk of cancer (U.S. EPA, 

2013d). 

Reference dose (RfD): An estimate (with uncertainty spanning perhaps an order of magnitude) of 

a daily oral exposure to the human population (including sensitive subgroups) that is likely to be 

without an appreciable risk of deleterious effects during a lifetime. It can be derived from a NOAEL, 

LOAEL, or benchmark dose, with uncertainty factors generally applied to reflect limitations of the 

data used. Generally used in EPA's noncancer health assessments (U.S. EPA, 2011c). 

Reference value (RfV): An estimate of an exposure or dose 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, 2011c). In the context of this report, the term RfV refers to reference values for 
Appendix J – Glossary

J-17

noncancer effects occurring via the oral route of exposure and for chronic durations, except where 

noted. 

Relative permeability: A dimensionless property allowing for 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. 

Reservoir: A geologic formation where hydrocarbons collect under pressure over geological time. 

Conventional reservoir: A reservoir in which buoyant forces keep hydrocarbons in place 

below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs 

typically permit oil or natural gas to flow readily into wellbores. The term is used to make a 

distinction from shale and other unconventional reservoirs, in which gas might be 

distributed throughout the reservoir at the basin scale, and in which buoyant forces or the 

influence of a water column on the location of hydrocarbons within the reservoir are not 

significant (Schlumberger, 2014). 

Unconventional reservoir: A reservoir characterized by lower permeability than 

conventional reservoirs. It can be the same formation where hydrocarbons are formed and 

also serve as the source for hydrocarbons that migrate and accumulate in conventional 

reservoirs. Unconventional reservoirs can include methane-rich coalbeds and oil- and/or 

gas-bearing shales and tight sands. 

Residuals: The solids generated or retained during the treatment of wastewater (U.S. EPA, 2013d). 

Safe Drinking Water Act (SDWA): The act designed to protect the nation’s drinking water supply 

by establishing national drinking water standards (maximum contaminant levels or specific 

treatment techniques) and by regulating underground injection control wells (U.S. EPA, 2013d). 

Sandstone: A clastic sedimentary rock whose grains are predominantly sand sized. The term is 

commonly used to imply consolidated sand or a rock made of predominantly quartz sand, although 

sandstones often contain feldspar, rock fragments, mica, and numerous additional mineral grains 

held together with silica or another type of cement. The relatively high porosity and permeability of

sandstones make them good reservoir rocks (Schlumberger, 2014). 

Science Advisory Board (SAB): A federal advisory committee that provides a balanced, expert 

assessment of scientific matters relevant to the EPA. An important function of the Science Advisory 

Board is to review EPA’s technical programs and research plans (U.S. EPA, 2013d). 

Service company: A company that assists well operators by providing specialty services, including 

hydraulic fracturing (U.S. EPA, 2013d). 

Severity: 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). 

Shale: A fine-grained, fissile, detrital sedimentary rock formed by consolidation of clay- and siltsized particles into thin, relatively impermeable layers (Schlumberger, 2014). 
Appendix J – Glossary

J-18

Shale gas: Natural gas generated and stored in shale. 

Shale oil: Oil present in reservoirs that are made up of shale. 

Shut in: The process of sealing off a well by either closing the valves at the wellhead, a downhole 

safety valve, or a blowout preventer. 

Slickwater: A type of fracturing fluid designed to have a low viscosity to reduce friction loss when 

pumping the fracturing fluid downhole. The critical additive in a slickwater is friction reducer, 

which allows pumping at high rates (Barati and Liang, 2014). 

Solubility: The amount of mass of a compound that will dissolve in a unit volume of solution (U.S. 

EPA, 2013d). 

Sorption: 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. 

Source water: Surface water or groundwater, or reused wastewater, acquired for use in hydraulic 

fracturing. 

Spacer fluid: A fluid pumped into the well during construction before the cement to clean drilling 

mud out of the wellbore. 

Spud (spud a well): To start the well drilling process by removing rock, dirt, and other 

sedimentary material with the drill bit (U.S. EPA, 2013d). 

Spill: Any unintended release of fluids. 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); flowback and produced water; wastewater. 

Stages (frac stages): A single reservoir interval that is hydraulically stimulated in succession with 

other intervals. 

Stimulation: Refers to (1) injecting fluids to clear the well or pore spaces near the well of drilling 

mud or other materials that create blockage and inhibit optimal production (i.e., matrix treatment) 

and (2) injecting fluid to fracture the rock to optimize the production of oil or gas. 

Stray gas: Refers to the phenomenon of natural gas (primarily methane) migrating into shallow 

drinking water resources or to the surface. 

Subsurface formation: a mappable body of rock of distinctive rock type(s) and characteristics 

(such as permeability and porosity) with a unique stratigraphic position. 

Surface casing: The shallowest cemented casing, with the widest diameter. Cemented surface 

casing generally serves as an anchor for blowout protection equipment and to seal off drinking 

water resources (Baker, 1979). 
Appendix J – Glossary

J-19

Surface water: All water naturally open to the atmosphere (rivers, lakes, reservoirs, ponds, 

streams, impoundments, seas, estuaries, etc.) (U.S. EPA, 2013d). 

Surfactant: Used during the hydraulic fracturing process to decrease liquid surface tension and 

improve fluid passage through the pipes (U.S. EPA, 2013d). 

Sustained casing pressure: The 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. 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) (Skjerven et al., 2011). 

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. 

Targeted rock formation: The portion of a subsurface rock formation that contains oil or gas to be 

extracted (sometimes called the “target zone” or the “production zone”).

Tolerable daily intake (TDI): An estimate of the intake of a substance, expressed on a body mass 

basis, to which an individual in a (sub) population may be exposed daily over its lifetime without 

appreciable health risk (WHO, 2015). 

Technically recoverable resource: The volumes of oil and natural gas that could be produced 

with current technology, regardless of oil and natural gas prices and production costs (EIA, 2013). 

Technologically Enhanced Naturally Occurring Radioactive Material (TENORM): defined by 

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. 

Temperature log: A log of the temperature of the fluids in the wellbore; a differential temperature 

log records the rate of change in temperature with depth and is sensitive to very small changes (U.S. 

EPA, 2013d). 

Tensile strength: The force per unit cross‐sectional area required to pull a substance apart 

(Schlumberger, 2014). 

Thermogenic: Methane that is produced by high temperatures and pressures in deep formations 

over geologic timescales. Thermogenic methane is formed by the thermal breakdown, or cracking, 

of organic material that occurs during deep burial of sediment. 

Tight oil: Oil found in relatively impermeable reservoir rock (Schlumberger, 2014). 

Total dissolved solids (TDS): The quantity of dissolved material in a given volume of water. Total 

dissolved solids can include salts (e.g., sodium chloride), dissolved metals, radionuclides, and 

dissolved organics (U.S. EPA, 2013d). Salinity and total dissolved solids are frequently 

interchangeable terms. 
Appendix J – Glossary

J-20

Total petroleum hydrocarbons (TPH): 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 (ATSDR, 2011). 

Toxicity: The degree to which a substance or mixture of substances can harm humans or animals. 

Acute toxicity involves harmful effects in an organism through a single or short‐term exposure. 

Chronic toxicity is the ability of a substance or mixture of substances to cause harmful effects over 

an extended period, usually upon repeated or continuous exposure, sometimes lasting for the entire 

life of the exposed organism. Subchronic toxicity is the ability of the substance to cause effects for 

more than 1 year but less than the lifetime of the exposed organism (U.S. EPA, 2013d). 

Tubing: The smallest, innermost steep pipe set within a completed well, either hung directly from 

the wellhead or secured at its bottom using a packer. Tubing is not typically cemented in the well. 

Underground Injection Control (UIC): The program under the Safe Drinking Water Act that 

regulates the use of wells to emplace fluids into the ground (U.S. EPA, 2013d). 

Underground Injection Control (UIC) Class II well: Refers to wells that inject fluids associated 

with oil and gas production, including for (1) disposal of fluids brought to the surface in connection 

with oil or natural gas production, (2) for enhanced recovery of oil or natural gas, and (3) for 

storage of hydrocarbons which are liquid at standard temperature and pressure. Adapted from § 

144.6(b). 

Underground Injection Control (UIC) Class IID well: Within the types of operations that can 

occur for UIC Class II wells (see above), refers to wells used for the disposal of fluids brought to the 

surface in connection with oil or natural gas production. Also known as wells for salt water 

disposal.

Underground source of drinking water (USDW): An aquifer or its portion that currently supplies 

a public water system; or which contains a sufficient quantity of groundwater to supply a public 

water system, and either now supplies water for human consumption, or contains fewer than 

10,000 mg/L TDS and is not exempted. Defined in the federal regulations that implement the UIC 

program (20 CFR 144.3). 

Unsaturated zone: The soil zone above the water table that is only partially filled by water; also 

referred to as the “vadose zone.”

Vapor pressure: The force per unit area exerted by a vapor in an equilibrium state with its pure 

solid, liquid, or solution at a given temperature. Vapor pressure is a measure of a substance's 

propensity to evaporate. Vapor pressure increases exponentially with an increase in temperature 

(U.S. EPA, 2013d). 
Appendix J – Glossary

J-21

Vertical separation distance: Measured vertically from the shallowest point of hydraulic 

fracturing to the bottom of the drinking water resource. If measured along a wellbore from the 

shallowest point of hydraulic fracturing to the bottom of the drinking water resource, this is 

referred to as measured depth, which may be a straight vertical distance below ground or may 

follow a more complicated path if the wellbore is not straight and vertical. 

Vertical well: A well in which the wellbore is vertical throughout its entire length, from the 

wellhead at the surface to the production zone. 

Viscosity: A measure of the internal friction of a fluid that provides resistance to shear within the 

fluid, informally referred to as how "thick" a fluid is. 

Volatile: Readily vaporizable at a relatively low temperature (U.S. EPA, 2013d). 

Volatilization: The process in which a chemical leaves the liquid phase and enters the gas phase. 

Wastewater: See hydraulic fracturing wastewater.

Wastewater treatment: Chemical, biological, and mechanical procedures applied to an industrial 

or municipal discharge or to any other sources of contaminated water in order to remove, reduce, 

or neutralize contaminants (U.S. EPA, 2013d). 

Water availability: 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. 

Water consumption: 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). 

Water intensity: The amount of water used per unit of energy obtained (Nicot et al., 2014; 

Laurenzi and Jersey, 2013) 

Water reuse: Any hydraulic fracturing wastewater that is used to offset total fresh water 

withdrawals for hydraulic fracturing, regardless of the level of treatment required. 

Water sensitivity: 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. 

Water table: The top, or uppermost surface, of groundwater. Below the water table, the ground is 

saturated with water. 
Appendix J – Glossary

J-22

Water use: Water withdrawn for a specific purpose, part or all of which may be returned to the 

local hydrologic cycle. 

Water withdrawal: The volume of water removed from its source, either the groundwater or 

diverted from a surface water source, for use, regardless of how much of that volume is returned to 

the local hydrologic cycle or consumed without being returned to the hydrologic cycle (Nicot et al., 

2014; Laurenzi and Jersey, 2013). 

Weight-of-evidence (WOE) characterization for carcinogenicity: A system used for 

characterizing the extent to which the available data support the hypothesis that an agent causes 

cancer in humans. The U.S. EPA issued guidelines in 1986, 1996, 1999, and 2005. For more 

information, see Appendix G. 

Well blowout: The uncontrolled flow of fluids out of a well. 

Well communication: When activities in a well that is being stimulated affect abandoned or active 

(producing) offset wells or their fracture networks. Also referred to as a “frac hit”.

Well logging: A continuous measurement of physical properties in or around the well with 

electrically powered instruments to infer formation properties. Measurements may include 

electrical properties (resistivity and conductivity), sonic properties, active and passive nuclear 

measurements, measurements of the wellbore, pressure measurement, formation fluid sampling, 

sidewall coring tools, and others. Measurements may be taken via a wireline, which is a wire or 

cable that is used to deploy tools and instruments downhole and that transmits data to the surface 

(adapted from Schlumberger, 2014). 

Well operator: A company that controls and operates oil and gas wells (U.S. EPA, 2013d). 

Well orientation: A well’s 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. 

Well pad: A temporary drilling site, usually constructed of local materials such as sand and gravel. 

After the drilling operation is over, most of the pad is usually removed or plowed back into the 

ground (NYSDEC, 2011). 

Wellbore: The drilled hole or borehole, including the open hole or uncased portion of the well. 

Wet gas: Refers to natural gas that typically contains less than 85% methane along with ethane and 

more complex hydrocarbons. 

Wettability: 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 
Appendix J – Glossary

J-23

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.

Wetting/nonwetting: The preferential attraction of a fluid to the surface. In typical reservoirs, 

water preferentially wets the surface, and gas is nonwetting (adapted from Dake, 1978). 

Workover: Refers to any maintenance activity performed on a well that involves ceasing 

operations and removing the wellhead. 

Young’s modulus: A ratio of stress to strain that is a measure of the rigidity of a material. 
Appendix J – Glossary

J-24

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Appendix K – References

K-1 

Appendix K. Appendix References
Appendix K – Appendix References

K-2 

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Appendix K – References

K-3 

Appendix K. Appendix References 

Hyperlinks to the reference citations throughout this document will take you to the ORD National 

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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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U.S. Environmental Protection Agency

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